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Oneok
OKE
#480
Rank
S$65.56 B
Marketcap
๐Ÿ‡บ๐Ÿ‡ธ United States
Country
S$104.11
Share price
-2.11%
Change (1 day)
-16.65%
Change (1 year)
๐Ÿ›ข Oil&Gas โšก Energy
Categories
Oneok is an American pipeline operator that operates in the midstream business - the long-distance transport and processing of gas products.
  1. Oneok
  2. Annual Reports (10-K)
  3. Financial Year 2025

Oneok - 10-K annual report 2025


Text size:
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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.
OR
☐ 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
okelogo.jpg
ONEOK, Inc.
(Exact name of registrant as specified in its charter)
Oklahoma73-1520922
(State or other jurisdiction of incorporation or organization)
(I.R.S. Employer Identification No.)
 
100 West Fifth Street,Tulsa,OK74103
(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 classTrading Symbol(s)Name of each exchange on which registered
Common stock, par value of $0.01OKENew 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
TABLE OF CONTENTS
Page No.
A. Summary of Significant Accounting Policies
B. Acquisitions and Divestitures
C. Fair Value Measurements
D. Risk-Management and Hedging Activities using Derivatives
E. Property, Plant and Equipment
F. Goodwill and Intangible Assets
G. Debt
H. Equity
I. Variable Interest Entities
J. Earnings Per Share
K. Share-Based Payments
L. Employee Benefit Plans
M. Income Taxes
N. Unconsolidated Affiliates
O. Commitments and Contingencies
P. Leases
Q. Revenues
R. Segments
2
TABLE OF CONTENTS
(CONTINUED)
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.
3
GLOSSARY

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

$2.5 Billion Credit AgreementONEOK’s $2.5 billion amended and restated revolving credit agreement, replaced by the $3.5 Billion Credit Agreement
$3.5 Billion Credit AgreementONEOK’s $3.5 billion amended and restated revolving credit agreement
AFUDCAllowance for funds used during construction
Annual ReportAnnual Report on Form 10-K for the year ended December 31, 2025
AscensionAscension Pipeline Company, LLC, a 50% owned joint venture
BblBarrels, 1 barrel is equivalent to 42 United States gallons
BcfBillion cubic feet
Bcf/dBillion cubic feet per day
BridgeTex BridgeTex Pipeline Company, LLC, a 30% owned joint venture, and after the BridgeTex Additional Interest Acquisition, a 60% owned joint venture
BridgeTex Additional Interest AcquisitionThe transaction completed on July 22, 2025, pursuant to which ONEOK acquired an additional 30% interest in BridgeTex
Delaware Basin JVDelaware G&P LLC, a 50.1% owned joint venture, and after the Delaware Basin JV Acquisition, a wholly owned subsidiary of ONEOK
Delaware Basin JV AcquisitionThe transaction completed on May 28, 2025, pursuant to which ONEOK acquired the remaining 49.9% noncontrolling interest in Delaware Basin JV
EBITDAEarnings before interest expense, income taxes, depreciation and amortization
Eiger Eiger Express Pipeline, LLC, a 25.5% owned joint venture, including the 10.5% held through Matterhorn
EnLinkEnLink Midstream, LLC, and after the EnLink Acquisition, Elk Merger Sub II, L.L.C., a wholly owned subsidiary of ONEOK
EnLink Acquisition
The transaction completed on January 31, 2025, pursuant to which ONEOK acquired all of the publicly held EnLink Units in a tax-free transaction, pursuant to the EnLink Merger Agreement
EnLink AcquisitionsThe EnLink Controlling Interest Acquisition and the EnLink Acquisition
EnLink AR FacilityEnLink’s $500 million accounts receivable securitization facility
EnLink Controlling Interest AcquisitionThe transaction completed on October 15, 2024, pursuant to which ONEOK acquired (i) approximately 43% of the outstanding EnLink Units and (ii) all of the outstanding limited liability company interests in EnLink Midstream Manager, LLC, pursuant to the EnLink Purchase Agreement
EnLink Merger AgreementAgreement and Plan of Merger, dated as of November 24, 2024, by and among ONEOK, Inc., Elk Merger Sub I, L.L.C., Elk Merger Sub II L.L.C., EnLink and EnLink Midstream Manager, LLC
EnLink PartnersEnLink Midstream Partners, LP, a wholly owned subsidiary of ONEOK
EnLink Purchase AgreementPurchase agreement, dated August 28, 2024, by and among ONEOK, GIP III Stetson I, L.P., GIP III Stetson II, L.P. and EnLink Midstream Manager, LLC
EnLink Revolving Credit FacilityEnLink’s $1.4 billion unsecured credit facility
EnLink UnitsCommon units representing limited liability company interests in EnLink
EPSEarnings per share of common stock
ESGEnvironmental, social and governance
Exchange ActSecurities Exchange Act of 1934, as amended
FERCFederal Energy Regulatory Commission
FitchFitch Ratings, Inc.
GAAPAccounting principles generally accepted in the United States of America
GHGGreenhouse gas
GIPGlobal Infrastructure Partners and certain of its managed fund vehicles, including GIP III Stetson I, L.P., GIP III Stetson II, L.P., GIP III Trophy GP 2, GIP III Trophy Acquisition
GuardianGuardian Pipeline, L.L.C.
Guardian Term Loan AgreementGuardian’s senior unsecured three-year $120 million term loan agreement dated June 2022
Intermediate PartnershipONEOK Partners Intermediate Limited Partnership, a wholly owned subsidiary of ONEOK
MagellanMagellan Midstream Partners, L.P., a wholly owned subsidiary of ONEOK
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Magellan AcquisitionThe transaction completed on September 25, 2023, pursuant to which ONEOK acquired all of Magellan’s outstanding common units in a cash-and-stock transaction, pursuant to the Magellan Merger Agreement
Magellan Merger AgreementAgreement and Plan of Merger of ONEOK, Otter Merger Sub, LLC and Magellan, dated May 14, 2023
MatterhornMXP Parent, LLC, a 15% owned joint venture
MBbl/dThousand barrels per day
MBTC PipelineMBTC Pipeline LLC, an 80% owned joint venture
MDth/dThousand dekatherms per day
MedallionGIP III Trophy Intermediate Holdings, L.P., and after the Medallion Acquisition, Medallion Parent Holdings, L.L.C., a wholly owned subsidiary of ONEOK
Medallion AcquisitionThe transaction completed on October 31, 2024, pursuant to which ONEOK (i) became general partner of Medallion and (ii) acquired all of the issued and outstanding limited partner interests in Medallion from GIP
MMBblMillion barrels
MMcf/dMillion cubic feet per day
Moody’sMoody’s Investors Service, Inc.
MVPMVP Terminalling, LLC, a 25% owned joint venture
Natural Gas ActNatural Gas Act of 1938, as amended
NGL(s)Natural gas liquid(s)
Northern BorderNorthern Border Pipeline Company, a 50% owned joint venture
NYMEXNew York Mercantile Exchange
NYSENew York Stock Exchange
ONEOKONEOK, Inc.
ONEOK PartnersONEOK Partners, L.P., a wholly owned subsidiary of ONEOK
Overland PassOverland Pass Pipeline Company, LLC, a 50% owned joint venture
POPPercent of Proceeds
Purity NGLsMarketable natural gas liquid purity products, such as ethane, ethane/propane mix, propane, iso-butane, normal butane and natural gasoline
Quarterly Report(s)Quarterly Report(s) on Form 10-Q
Refined ProductsThe output from crude oil refineries, including products such as gasoline, diesel fuel, aviation fuel, kerosene and heating oil
RINsRenewable Identification Numbers, which represent credits required for renewable fuel standard compliance
RoadrunnerRoadrunner Gas Transmission Holdings, LLC, a 50% owned joint venture
S&PS&P Global Ratings
SaddlehornSaddlehorn Pipeline Company, LLC, a 40% owned joint venture
SCOOPSouth Central Oklahoma Oil Province, an area in the Anadarko Basin in Oklahoma
SECSecurities and Exchange Commission
Securities Act
Securities Act of 1933, as amended
Series B Preferred UnitsEnLink Partners’ Series B Cumulative Convertible Preferred Units
Series C Preferred UnitsEnLink Partners’ Series C Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units
STACKSooner Trend Anadarko Canadian Kingfisher, an area in the Anadarko Basin in Oklahoma
Term SOFRThe forward-looking term rate based on Secured Overnight Financing Rate (SOFR)
Texas City LogisticsTexas City Logistics, LLC, a 50% owned joint venture
VikingViking Gas Transmission Company
Viking Term Loan AgreementViking’s senior unsecured three-year $60 million term loan agreement dated March 2023
WhiteWaterWhiteWater Midstream, LLC, the operator of Matterhorn and Eiger pipelines
XBRLeXtensible 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.
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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 dioxide treater, 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

Overview of 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.

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 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.

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.

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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

Overview of 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.

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 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 PositionAgeBusiness Experience in Past Five Years
Pierce H. Norton II662021 to presentPresident and Chief Executive Officer, ONEOK
President and Chief Executive Officer2021 to presentMember of the Board of Directors, ONEOK
2014 to 2021President and Chief Executive Officer, ONE Gas, Inc.
2014 to 2021Member of the Board of Directors, ONE Gas, Inc.
Walter S. Hulse III622022 to presentChief Financial Officer, Treasurer and Executive Vice President, Investor Relations and Corporate Development, ONEOK
Chief Financial Officer, Treasurer and Executive Vice President, Investor Relations and Corporate Development2019 to 2021Chief Financial Officer, Treasurer and Executive Vice President, Strategy and Corporate Affairs, ONEOK
Kevin L. Burdick612023 to presentExecutive Vice President and Chief Enterprise Services Officer, ONEOK
Executive Vice President and Chief Enterprise Services Officer2022 to 2023Executive Vice President and Chief Commercial Officer, ONEOK
2017 to 2022Executive Vice President and Chief Operating Officer, ONEOK
Sheridan C. Swords562025 to presentExecutive Vice President and Chief Commercial Officer, ONEOK
Executive Vice President and Chief Commercial Officer2023 to 2025Executive Vice President, Commercial Liquids and Gathering and Processing, ONEOK
2022 to 2023Senior Vice President, Natural Gas Liquids and Natural Gas Gathering and Processing, ONEOK
2017 to 2022Senior Vice President, Natural Gas Liquids, ONEOK
Lyndon C. Taylor672023 to presentExecutive Vice President, Chief Legal Officer and Assistant Secretary, ONEOK
Executive Vice President, Chief Legal Officer and Assistant Secretary2005 to 2021Executive Vice President and Chief Legal and Administrative Officer, Devon Energy Corporation
Randy N. Lentz612025 to presentExecutive Vice President and Chief Operating Officer, ONEOK
Executive Vice President and Chief Operating Officer2010 to 2024President and Chief Executive Officer, Medallion Midstream, LLC
Mary M. Spears462022 to presentSenior Vice President and Chief Accounting Officer, Finance and Tax, ONEOK
Senior Vice President and Chief Accounting Officer, Finance and Tax2019 to 2021Vice President and Chief Accounting Officer, 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.

Our long-term debt has been assigned an investment-grade credit rating of “Baa2” by Moody’s and “BBB” by both S&P and Fitch. Our commercial paper program has been assigned an investment-grade credit rating of Prime-2, A-2 and F2 by Moody’s, S&P and Fitch, respectively. We cannot provide assurance that any of our current ratings will remain in effect for any given period of time or that a rating will not be lowered or withdrawn entirely by these credit rating agencies. If these agencies were to downgrade our long-term debt or our commercial paper rating, particularly below investment grade, our borrowing costs could increase, which would adversely affect our financial results, and our potential pool of investors and funding sources could decrease. Ratings from these agencies are not recommendations to buy, sell or hold our securities. Each rating should be evaluated independently of any other rating.

Our indebtedness and guarantee obligations could impair our financial condition and our ability to fulfill our obligations.

As of December 31, 2025, we had total indebtedness of $34.0 billion. Our indebtedness and guarantee obligations could have significant consequences. For example, they could:
•make it more difficult for us to satisfy our obligations with respect to senior notes and other indebtedness due to the increased debt-service obligations, which could, in turn, result in an event of default on such other indebtedness or the senior notes;
•impair our ability to obtain additional financing in the future for working capital, capital expenditures, acquisitions or general business purposes;
•diminish our ability to withstand a downturn in our business or the economy;
•require us to dedicate a substantial portion of our cash flows from operations to debt-service payments, reducing the availability of cash for working capital, capital expenditures, acquisitions, dividends or general corporate purposes;
•limit our flexibility in planning for, or reacting to, changes in our business and the industry in which we operate; and
•place us at a competitive disadvantage compared with our competitors that have proportionately less debt and fewer guarantee obligations.

We are not prohibited under the indentures governing the senior notes from incurring additional indebtedness, but our debt agreements do subject us to certain operational limitations that could restrict our ability to finance future operations or expand or pursue business activities, as summarized in the next paragraph. If we incur significant additional indebtedness, it could worsen the negative consequences mentioned above and could adversely affect our ability to repay our other indebtedness.

Our $3.5 Billion Credit Agreement contains provisions that, among other things, limit our ability to make material changes to the nature of our business, merge, consolidate or dispose of all or substantially all of our assets, grant liens and security interests on our assets, engage in transactions with affiliates or make restricted payments, including dividends. It also requires us to maintain certain financial ratios, which limit the amount of additional indebtedness we can incur, as described in the “Liquidity and Capital Resources” section of Part II, Item 7, Management’s Discussion and Analysis of Financial Condition and Results of
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Operations, in this Annual Report. These restrictions could result in higher costs of borrowing and impair our ability to generate additional cash. Future financing agreements we may enter into may contain similar or more restrictive covenants.

If we are unable to meet our debt-service obligations or comply with financial covenants, we could be forced to restructure or refinance our indebtedness, seek additional equity capital or sell assets. We may be unable to obtain financing or sell assets on satisfactory terms, or at all.

An event of default may require us to offer to repurchase or repay certain of our and ONEOK Partners’ senior notes or may impair our ability to access capital.

The indentures governing certain of our and ONEOK Partners’ senior notes include an event of default upon the acceleration of other indebtedness of $15 million or more for certain of our senior notes or $100 million or more for certain of our and ONEOK Partners’ senior notes. Such events of default would entitle the trustee or the holders of 25% in aggregate principal amount of our and ONEOK Partners’ outstanding senior notes to declare those senior notes immediately due and payable in full. We may not have sufficient cash on hand to repurchase and repay any accelerated senior notes, which may cause us to borrow funds under our credit facility or seek alternative financing sources to finance the repurchases and repayment. We could also face difficulties accessing capital or our borrowing costs could increase, impacting our ability to obtain financing for acquisitions or capital expenditures, to refinance indebtedness and to fulfill our debt obligations.

The right to receive payments on our outstanding debt securities and subsidiary guarantees is unsecured and will be effectively subordinated to any future secured indebtedness as well as to any existing and future indebtedness of our subsidiaries that do not guarantee the senior notes.

Although ONEOK Partners, the Intermediate Partnership, Magellan, EnLink and EnLink Partners have guaranteed our debt securities, the guarantees are subject to release under certain circumstances, and we have subsidiaries that are not guarantors.
In those cases, the debt securities effectively are subordinated to the claims of all creditors, including trade creditors and tort claimants, of our subsidiaries that are not guarantors. In the event of the insolvency, bankruptcy, liquidation, reorganization, dissolution or winding up of the business of a subsidiary that is not a guarantor, creditors of that subsidiary would generally have the right to be paid in full before any distribution is made to us or the holders of the debt securities.

A court may use fraudulent conveyance considerations to avoid or subordinate the cross guarantees of our and ONEOK Partners’ indebtedness.

ONEOK, ONEOK Partners, the Intermediate Partnership, Magellan, EnLink and EnLink Partners have cross guarantees in place for our and ONEOK Partners’ indebtedness. A court may use fraudulent conveyance laws to subordinate or avoid the cross guarantees of certain of this indebtedness. It is also possible that under certain circumstances, a court could avoid or subordinate the guarantor’s guarantee of this indebtedness in favor of the guarantor’s other debts or liabilities to the extent that the court determined either of the following were true at the time the guarantor issued the guarantee:
•the guarantor incurred the guarantee with the intent to hinder, delay or defraud any of its present or future creditors or the guarantor contemplated insolvency with a design to favor one or more creditors to the total or partial exclusion of others; or
•the guarantor did not receive fair consideration or reasonable equivalent value for issuing the guarantee and, at the time it issued the guarantee, the guarantor:
–     was insolvent or rendered insolvent by reason of the issuance of the guarantee;
–     was engaged or about to engage in a business or transaction for which its remaining assets constituted unreasonably small capital; or
–     intended to incur, or believed that it would incur, debts beyond its ability to pay such debts as they matured.

The measure of insolvency for purposes of the foregoing will vary depending upon the law of the relevant jurisdiction. Generally, however, an entity would be considered insolvent for purposes of the foregoing if:
•the sum of its debts, including contingent liabilities, were greater than the fair saleable value of all of its assets at a fair valuation;
•the present fair saleable value of its assets was less than the amount that would be required to pay its probable liability on its existing debts, including contingent liabilities, as they become absolute and mature; or
•it could not pay its debts as they become due.

Among other things, a legal challenge of the cross guarantees of our and ONEOK Partners’ indebtedness on fraudulent conveyance grounds may focus on the benefits, if any, realized by the guarantor as a result of the issuance of such debt. To the
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extent the guarantor’s guarantee of any such indebtedness is avoided as a result of fraudulent conveyance or held unenforceable for any other reason, the holders of such debt would cease to have any claim in respect of the guarantee.

GENERAL RISK FACTORS

Mergers, acquisitions and other significant transactions that appear to be accretive may nevertheless reduce our cash from operations on a per-share basis.

Any merger, acquisition or other significant transactions involves potential risks that may include, among other things:
•inaccurate assumptions about volumes, revenues and costs, including potential synergies;
•an inability to integrate successfully the businesses we acquire;
•decrease in our liquidity as a result of our using a significant portion of our available cash or borrowing capacity to finance the acquisition;
•a significant increase in our interest expense and/or financial leverage if we incur additional debt to finance the acquisition;
•the assumption of unknown liabilities for which we are not indemnified, our indemnity is inadequate or our insurance policies may exclude from coverage;
•an inability to hire, train or retain qualified personnel to manage and operate the acquired business and assets;
•limitations on rights to indemnity from the seller;
•inaccurate assumptions about the overall costs of equity or debt;
•the diversion of management’s and employees’ attention from other business concerns;
•unforeseen difficulties operating in new product areas or new geographic areas;
•increased regulatory burdens; and
•customer or key employee losses at an acquired business.

If we consummate any future mergers or acquisitions, our capitalization and results of operations may change significantly, and investors will not have the opportunity to evaluate the economic, financial and other relevant information that we will consider in determining the application of our resources to future acquisitions.

Our future results following any potential future transactions will suffer if we do not effectively manage our expanded operations.

During the year ended December 31, 2025, we completed the EnLink Acquisition, the Delaware Basin JV Acquisition and the BridgeTex Additional Interest Acquisition. As a result, the size of our business has increased and will increase further if we complete future acquisitions. Our future success will depend, in part, upon our ability to manage this expanded business, which may pose challenges for management, including challenges related to the management and monitoring of new operations and associated increased costs and complexity. We may also face increased scrutiny from governmental authorities and/or other third parties as a result of the increase in the size of our business. There can be no assurances that we will be successful or that we will realize the expected operating efficiencies, cost savings, revenue enhancements or other benefits anticipated from these acquisitions and any potential future acquisitions.

Holders of our common stock may receive dividends that vary from anticipated amounts, or no dividends at all.

We may not have sufficient cash each quarter to pay dividends or maintain current or expected levels of dividends. The actual amount of cash we pay in the form of dividends may fluctuate from quarter to quarter and will depend on various factors, some of which are beyond our control, including our working capital needs, our ability to borrow, the restrictions contained in our indentures and credit facility, our debt-service requirements and the cost of acquisitions, if any. A failure either to pay dividends or to pay dividends at expected levels could result in a loss of investor confidence, reputational damage and a decrease in the value of our stock price.

We are exposed to the credit risk of our customers or counterparties, and our credit risk management may not be adequate to protect against such risk.

We are subject to the risk of loss resulting from nonpayment and/or nonperformance by our customers and counterparties. Our customers or counterparties may experience rapid deterioration of their financial condition as a result of changing market conditions, commodity prices or financial difficulties that could impact their creditworthiness or ability to pay us for our services. We assess the creditworthiness of our customers and counterparties and obtain collateral or contractual terms as we deem appropriate. We cannot, however, predict to what extent our business may be impacted by deteriorating market or
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financial conditions, including possible declines in our customers’ and counterparties’ creditworthiness. Our customers and counterparties may not perform or adhere to our existing or future contractual arrangements. To the extent our customers and counterparties are in financial distress or commence bankruptcy proceedings, contracts with them may be subject to renegotiation or rejection under applicable provisions of the United States Bankruptcy Code. If our risk-management policies and procedures fail to assess adequately the creditworthiness of existing or future customers and counterparties, any material nonpayment or nonperformance by our customers and counterparties due to inability or unwillingness to perform or adhere to contractual arrangements could adversely affect our business, results of operations, financial position and cash flows.

Our counterparties are primarily major integrated and independent exploration and production, pipeline, marketing and petrochemical companies and natural gas and electric utilities. Therefore, our counterparties may be similarly affected by changes in economic, regulatory or other factors that may affect our overall credit risk.

Our business requires the retention and recruitment of a skilled executive team and workforce, and difficulties in recruiting and retaining executives and other key personnel could impair our ability to develop and implement our business strategy. A shortage of skilled labor may make it difficult for us to maintain labor productivity and competitive costs.

Our success depends in part on the performance of and our ability to attract, retain and effectively manage the succession of a skilled executive team. We depend on our executive officers to develop and execute our business strategy. If we are not successful in retaining our executive officers, or replacing them, our business, financial condition or results of operations could be adversely affected.

In addition, our operations require the retention and recruitment of skilled and experienced workers with proficiency in multiple tasks. In recent years, a shortage of workers trained in various skills associated with the midstream energy business has, at times, caused us to conduct certain operations without full staff, thus hiring outside resources, which may decrease productivity and increase costs. This shortage of trained workers is the result of experienced workers reaching retirement age and increased competition for workers in certain areas, combined with the challenges of attracting new, qualified workers to the midstream energy industry. If the shortage of experienced labor continues or worsens, it could adversely affect our labor productivity and costs and our ability to expand operations in the event there is an increase in the demand for our services and products, which could adversely affect our business, results of operations, financial position and cash flows.

Our employees or directors may engage in misconduct or other improper activities, including noncompliance with regulatory standards and requirements.

As with all companies, we are exposed to the risk of employee fraud or other misconduct. Our Board of Directors has adopted a code of business conduct and ethics that applies to our directors, officers (including our principal executive and financial officers, principal accounting officer, controllers and other persons performing similar functions) and all other employees. We require all directors, officers and employees to adhere to our code of business conduct and ethics in addressing the legal and ethical issues encountered in conducting their work for our company. Our code of business conduct and ethics requires, among other things, that our directors, officers and employees avoid conflicts of interest, comply with all applicable laws and other legal requirements, conduct business in an honest and ethical manner and otherwise act with integrity and in our company’s best interest. All directors, officers and employees are required to report any conduct that they believe to be an actual or apparent violation of our code of business conduct and ethics. However, it is not always possible to identify and deter misconduct, and the precautions we take to detect and prevent this activity may not be effective in controlling unknown or unmanaged risks or losses or in protecting us from governmental investigations or other actions or lawsuits stemming from a failure to comply with such laws or regulations. If any such actions are instituted against us, and we are not successful in defending ourselves or asserting our rights, those actions could adversely affect our reputation, business, results of operations, financial position and cash flows.

An impairment of goodwill, long-lived assets, including intangible assets, and equity-method investments could reduce our earnings.

Goodwill is recorded when the purchase price of a business exceeds the fair market value of the tangible and separately measurable intangible net assets. GAAP requires us to test goodwill for impairment on an annual basis or when events or circumstances occur indicating that goodwill might be impaired. Long-lived assets, including intangible assets with finite useful lives, are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. For the investments we account for under the equity method, the impairment test considers whether the fair value of the equity investment as a whole, not the underlying net assets, has declined and whether that decline is other than temporary. For example, if a low commodity price environment persisted for a prolonged period, it could result in lower
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volumes delivered to our systems and impairments of our assets or equity-method investments. If we determine that an impairment is indicated, we would be required to take an immediate noncash charge to earnings with a correlative effect on equity and balance sheet leverage as measured by consolidated debt to total capitalization.

For further discussion of impairments of long-lived assets, goodwill and equity-method investments, see Note A of the Notes to Consolidated Financial Statements in this Annual Report.

The cost of providing pension and postretirement health care benefits to eligible employees and qualified retirees is subject to changes in pension fund values and changing demographics and may increase.

We have defined benefit pension plans for certain employees and former employees, which are closed to new participants, and postretirement welfare plans that provide postretirement medical and life insurance benefits to certain employees. The cost of providing these benefits to eligible current and former employees is subject to changes in the market value of our pension and postretirement benefit plan assets, changing demographics, including longer life expectancy of plan participants and their beneficiaries and changes in health care costs. For further discussion of our defined benefit pension plan and postretirement welfare plans, see Note L of the Notes to Consolidated Financial Statements in this Annual Report.

Any sustained declines in equity markets and reductions in bond yields may adversely affect the value of our pension and postretirement benefit plan assets. In these circumstances, additional cash contributions to our pension plans may be required, which could adversely affect our business, financial condition and cash flows.

If we fail to maintain an effective system of internal controls, we may not be able to report accurately our financial results or prevent fraud. As a result, current and potential holders of our equity and debt securities could lose confidence in our financial reporting.

Effective internal controls are necessary for us to provide reliable financial reports, prevent fraud and operate successfully as a public company. We cannot be certain that our efforts to maintain our internal controls will be successful, that we will be able to maintain adequate controls over our financial processes and reporting in the future or that we will be able to continue to comply with our obligations under Section 404 of the Sarbanes-Oxley Act of 2002. Any failure to maintain effective internal controls, or difficulties encountered in implementing or improving our internal controls, could harm our operating results or cause us to fail to meet our reporting obligations. Ineffective internal controls could also cause investors to lose confidence in our reported financial information, which would likely have a negative effect on the trading price of our equity, our access to capital markets and the cost of capital.

ITEM 1B.    UNRESOLVED STAFF COMMENTS

Not applicable.

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ITEM 1C.    CYBERSECURITY

Risk Management and Strategy - We take a cross-disciplinary approach to cybersecurity and physical security. Our annual Enterprise Risk Management (ERM) process encompasses the identification and assessment of a broad range of risks, including cybersecurity, and the development and testing of controls to mitigate these risks. Our ERM assessment is designed to enable our Board of Directors to establish a mutual understanding with management of the effectiveness of our risk-management practices and capabilities, to review our risk exposures and to elevate certain key risks for discussion at the board level. Our ERM program is overseen by our chief financial officer.

Our cybersecurity risk management program is integrated with our ERM program and shares common methodologies, reporting channels and governance processes that apply across the ERM program to other legal compliance, strategic, operational and financial risk areas. Our security program generally incorporates the guidelines of the widely utilized National Institute of Standards and Technology Cybersecurity Framework, though this does not imply we meet any particular technical standards, specifications or requirements. On a regular basis, we engage consultants, including external counsel and cybersecurity firms, to conduct penetration tests and architecture design reviews. In addition, we conduct risk assessments of new enterprise third-party software and cloud vendors by utilizing security questionnaires prior to procurement.

As of February 16, 2026, though the Company and third parties have experienced certain nonmaterial cybersecurity incidents, we are not aware of any cybersecurity threats, that have materially affected or are reasonably likely to materially affect us, including our business strategy, results of operations or financial condition. We face certain ongoing risks from cybersecurity threats that, if realized and material, may materially affect us, including our operations, business strategy, results of operations or financial condition. See Part 1, Item 1A “Risk Factors” for a discussion of risks factors related to cybersecurity.

Governance - Security is governed by the Security Advisory Team, an executive advisory committee composed of company officers, including our chief executive officer, our chief financial officer and our chief enterprise services officer. The Security Advisory Team meets regularly to evaluate ongoing security threats and incidents, to define policy and to prioritize initiatives. Identified cybersecurity threats and incidents are monitored and assessed for materiality by this cross-functional Security Advisory Team. This assessment includes whether our Board of Directors should be informed of a threat or incident. The use of emerging technologies, including the use of Cloud Services and Artificial Intelligence, is governed by our End-User Computing Policy.

The Security Advisory Team is chaired by our vice president of cybersecurity and physical security who has more than twenty years of relevant experience in the field of cyber and physical security. In his role, our vice president of cybersecurity and physical security also supervises efforts to prevent, detect, mitigate and remediate cybersecurity risks and incidents through various means, which include briefings from internal security personnel, alerts and reports produced by security tools deployed in our technology infrastructure and threat intelligence and other information obtained from governmental, public or private sources, including external cybersecurity service providers. Our vice president of cybersecurity and physical security reports to our executive vice president and chief enterprise services officer, responsible for cybersecurity, information technology, enterprise optimization and innovation, among other responsibilities. Before joining ONEOK, our executive vice president and chief enterprise services officer held information technology positions of increasing responsibility.

Cybersecurity risks are communicated and discussed with our Board of Directors at least annually in conjunction with our overall ERM program. Internal Audit provides periodic updates to the Audit Committee on testing completed to meet TSA requirements. As part of its oversight responsibilities, our Board of Directors also receives frequent updates from executive management on our company’s physical and cybersecurity efforts.

ITEM 2.    PROPERTIES

A description of our properties is included in Item 1, Business.

ITEM 3.    LEGAL PROCEEDINGS

We have elected to use a $1 million threshold for disclosing environmental proceedings.

Information about our legal proceedings is included in Note O of the Notes to Consolidated Financial Statements in this Annual Report.

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ITEM 4.    MINE SAFETY DISCLOSURES

Not applicable.

PART II

ITEM 5.    MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

Our common stock is listed on the NYSE under the trading symbol “OKE.” The corporate name ONEOK is used in stock listings.

At February 16, 2026, there were 14,660 holders of record of our 629,783,634 outstanding shares of common stock.

For information regarding our 2025 Employee Stock Award Program and other equity compensation plans, see Note K of the Notes to Consolidated Financial Statements and “Equity Compensation Plan Information” included in Part III, Item 12, Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters, in this Annual Report.

REPURCHASES OF COMMON STOCK

ISSUER PURCHASES OF EQUITY SECURITIES
Period
Total Number of Shares Purchased
Average Price Paid Per Share
Total Number of Shares Purchased as Part of the Publicly Announced Program (a)
Maximum Approximate Dollar Value of Shares That May Yet Be Purchased Under the Program
 (Millions of dollars)
October 2025 (b)611,237 $72.78 611,237 $1,766 
November 2025— $— — $1,766 
December 2025— $— — $1,766 
Total
611,237 611,237 
(a) - In January 2024, our Board of Directors authorized a share repurchase program to buy up to $2.0 billion of our outstanding common stock. The program will terminate upon completion of the repurchases of the $2.0 billion of common stock, or on January 1, 2029, whichever occurs first.
(b) - Shares reported were repurchased in September 2025 and settled in October 2025.
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PERFORMANCE GRAPH

The following performance graph compares the performance of our common stock with the S&P 500 Index, the S&P 500 Energy Index and a ONEOK Peer Group during the period beginning on December 31, 2020, and ending on December 31, 2025.

Value of a $100 Investment, Assuming Reinvestment of Distributions/Dividends,
at December 31, 2020, and at the End of Every Year Through December 31, 2025.

1541
 
Cumulative Total Return
 
Years ended December 31,
 20212022202320242025
ONEOK, Inc.$164.85 $196.00 $221.79 $333.08 $256.81 
S&P 500 Index$128.71 $105.40 $133.10 $166.40 $196.16 
S&P 500 Energy Index (a)
$154.64 $256.27 $252.87 $267.34 $290.53 
ONEOK Peer Group (b)$136.66 $175.22 $206.42 $310.39 $337.09 
(a) - The S&P 500 Energy Index is a subindex of the S&P 500 that includes those companies classified as members of the energy sector.
(b) - The ONEOK Peer Group in 2025 was composed of the following companies: Antero Midstream Corp.; Energy Transfer LP; Enterprise Products Partners L.P.; Kinder Morgan, Inc.; Kinetik Holdings Inc.; MPLX LP; Plains All American Pipeline, L.P.; Targa Resources Corp.; Western Midstream Partners, LP; and The Williams Companies, Inc.

ITEM 6.    [RESERVED]

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ITEM 7.    MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion and analysis should be read in conjunction with Part I, Item 1, Business, our audited Consolidated Financial Statements and the Notes to Consolidated Financial Statements in this Annual Report.

RECENT DEVELOPMENTS

Please refer to the “Financial Results and Operating Information” and “Liquidity and Capital Resources” sections of Management’s Discussion and Analysis of Financial Condition and Results of Operations in this Annual Report for additional information.

Acquisitions

Delaware Basin JV Acquisition - On May 28, 2025, we completed the Delaware Basin JV Acquisition for $941 million. Pursuant to the purchase agreement, we paid $550 million in cash, including post-closing adjustments, which we funded with short-term borrowings and issued approximately 4.9 million shares of ONEOK common stock to the seller with a fair value of $391 million as of the closing date. Following the completion of the transaction, it is now a wholly owned subsidiary.

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 our most recent acquisitions, see Part II, Item 8, Note B of the Notes to Consolidated Financial Statements in this Annual Report. See Part I, Item 1A “Risk Factors” for further discussion of risks related to these transactions.

Joint Ventures

Eiger Express Pipeline - 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. 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. We expect to invest a total of approximately $350 million into this project, which is expected to be completed in mid-2028.

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

Texas City Logistics and MBTC Pipeline - In February 2025, we announced definitive agreements to form 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. 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. MBTC Pipeline, the pipeline joint venture, is owned 80% by us and 20% by MPLX LP, and we will construct and operate the pipeline. We expect to invest a total of approximately $1.0 billion into these projects, which are expected to be completed in early 2028.

Market Conditions - Earnings increased in 2025, compared with 2024, 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.

One Big Beautiful Bill Act (OBBBA) - On July 4, 2025, the OBBBA was signed into law. The OBBBA makes changes to U.S. tax law and includes provisions that, beginning in January 2025, make permanent full expensing of tangible personal property and restore EBITDA-based calculations for purposes of the business interest deduction. We expect the OBBBA to reduce our cash taxes beginning with the 2025 tax year; however, we do not anticipate the OBBBA to materially impact net income.
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Capital Projects - Our primary capital projects are outlined in the table below:

Project ScopeApproximate
Cost (a)
Expected Completion
Natural Gas Gathering and Processing(In millions)
Bighorn plant
300 MMcf/d processing plant with carbon dioxide treater in the Permian Basin
$365Mid-2027
Natural Gas Liquids
Elk Creek pipeline expansionIncrease capacity to 435 MBbl/d out of the Rocky Mountain region$355
Completed
Medford fractionator
Rebuild our 210 MBbl/d NGL fractionation facility in Medford, Oklahoma
$485
(b)
Texas City Logistics export terminal (c)
400 MBbl/d liquified petroleum gas export terminal in Texas City, Texas$700
Early 2028
MBTC Pipeline 24-inch pipeline from Mont Belvieu, Texas, storage facility to the new Texas City, Texas, export terminal$280Early 2028
Natural Gas Pipelines
Eiger Express Pipeline (c)450-mile, 48-inch natural gas pipeline from the Permian Basin to Katy, Texas$350Mid-2028
   Refined Products and Crude
Greater Denver pipeline expansion
Increase total system capacity by 35 MBbl/d and additional expansion capabilities
$480
Mid-2026
(a) - Excludes capitalized interest/AFUDC. For our Texas City Logistics, MBTC Pipeline and Eiger joint venture projects, the amounts presented exclude capital contributions from the other joint venture members.
(b) - This project is expected to be completed in two phases, with the first phase expected to be completed in the fourth quarter of 2026, and the second phase completed in the first quarter of 2027.
(c) - Our investments in Texas City Logistics and Eiger are accounted for using the equity method. Spending on these projects will be recorded as contributions to unconsolidated affiliates.

In our Natural Gas Gathering and Processing segment, we are relocating a 150 MMcf/d processing plant to the Permian Basin from North Texas, which we expect to be completed in the first quarter of 2026.

For a discussion of our capital expenditures financing, see “Capital Expenditures” in the Liquidity and Capital Resources” section.

Debt Issuances - In August 2025, we completed an underwritten public offering of $3.0 billion senior unsecured notes consisting of $750 million, 4.95% senior notes due 2032; $1.0 billion, 5.4% senior notes due 2035; and $1.25 billion, 6.25% senior notes due 2055. The net proceeds, after deducting underwriting discounts, commissions and offering expenses, were $2.96 billion. The net proceeds from this offering were partially used to repay our commercial paper outstanding and repay in full at maturity our senior notes due September 2025. The remaining net proceeds from the offerings were used for general corporate purposes, including the repurchase and redemption of existing notes.

Debt Extinguishments - We completed the following debt extinguishments in 2025:
Principal
(Millions of dollars)
$250 at 3.2% due March 2025$250 
$750 at 4.15% due June 2025422 
$400 at 2.2% due September 2025387 
$600 at 5.85% due January 2026 (a)
600 
$650 at 5.0% due March 2026 (a)
650 
Open Market Repurchases (b)
789 
Total$3,098 
(a) - Amounts redeemed at 100% of principal plus accrued and unpaid interest.
(b) - In 2025, we repurchased in the open market certain of our senior notes in the principal amount of $789 million for an aggregate repurchase price of $681 million, including accrued and unpaid interest. In connection with these open market repurchases, we recognized $106 million of net gains on extinguishment of debt which is included in other income, net in our Consolidated Statement of Income for the year ended December 31, 2025.


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Share Repurchase Program - Our Board of Directors authorized a share repurchase program to buy up to $2.0 billion of our outstanding common stock. The program will terminate upon completion of the repurchase of the $2.0 billion of common stock or on January 1, 2029, whichever occurs first. For the year ended December 31, 2025, we repurchased $62 million of our outstanding common stock with cash on hand.

Dividends - During 2025, we paid common stock dividends totaling $4.12 per share, an increase of 4% compared to the 2024 dividend of $3.96 per share. In February 2026, we paid a quarterly common stock dividend of $1.07 per share ($4.28 per share on an annualized basis). Our dividend growth is due primarily to the increase in cash flows resulting from the growth of our operations. The quarterly stock dividend was paid on February 13, 2026, to shareholders of record at the close of business on February 2, 2026.

FINANCIAL RESULTS AND OPERATING INFORMATION

How We Evaluate Our Operations

Management uses a variety of financial and operating metrics to analyze our performance. Our consolidated financial metrics include: (1) operating income; (2) net income; (3) diluted EPS; and (4) adjusted EBITDA. We evaluate segment operating results using adjusted EBITDA and our operating metrics, which include various volume and rate statistics that are relevant for the respective segment. These operating metrics allow investors to analyze the various components of segment financial results in terms of volumes and rate/price. Management uses these metrics to analyze historical segment financial results and as the key inputs for forecasting and budgeting segment financial results. For additional information on our operating metrics, see the respective segment subsections of this “Financial Results and Operating Information” section.

Non-GAAP Financial Measures - Adjusted EBITDA is a non-GAAP measure of our financial performance. Adjusted EBITDA is defined as net income adjusted for interest expense, depreciation and amortization, noncash impairment charges, income taxes, noncash compensation expense and certain other noncash items. Our calculation includes adjusted EBITDA related to our unconsolidated affiliates using the same recognition and measurement methods used to record equity in net earnings from investments. Adjusted EBITDA from our unconsolidated affiliates is calculated consistently with the definition above and excludes items such as interest expense, depreciation and amortization, income taxes and other noncash items. Although the amounts related to our unconsolidated affiliates are included in the calculation of adjusted EBITDA, such inclusion should not be understood to imply that we have control over the operations and resulting revenues, expenses or cash flows of such unconsolidated affiliates.

We believe this non-GAAP financial measure is useful to investors because it and similar measures are used by many companies in our industry as a measurement of financial performance and is commonly employed by financial analysts and others to evaluate our financial performance and to compare financial performance among companies in our industry. Adjusted EBITDA should not be considered an alternative to net income, EPS or any other measure of financial performance presented in accordance with GAAP. Additionally, this calculation may not be comparable with similarly titled measures of other companies. See reconciliation of net income to adjusted EBITDA in the “Non-GAAP Financial Measures” subsection.
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Consolidated Operations

Selected Financial Results - The following table sets forth certain selected financial results for the periods indicated:
Years Ended December 31,2025 vs. 20242024 vs. 2023
Financial Results202520242023
$ Increase (Decrease)
(Millions of dollars, except per share amounts)
Revenues
Commodity sales$28,878 $17,780 $15,614 11,098 2,166 
Services and other4,751 3,918 2,063 833 1,855 
Total revenues33,629 21,698 17,677 11,931 4,021 
Cost of sales and fuel (exclusive of items shown separately below)23,373 13,311 11,929 10,062 1,382 
Operating costs2,963 2,496 1,535 467 961 
Depreciation and amortization1,514 1,134 769 380 365 
Transaction costs81 73 158 8 (85)
Other operating income, net(43)(305)(786)(262)(481)
Operating income$5,741 $4,989 $4,072 752 917 
Equity in net earnings from investments$386 $439 $202 (53)237 
Interest expense, net of capitalized interest$(1,783)$(1,371)$(866)412 505 
Net income$3,462 $3,112 $2,659 350 453 
Net income attributable to ONEOK$3,393 $3,035 $2,659 358 376 
Diluted EPS $5.42 $5.17 $5.48 0.25 (0.31)
Adjusted EBITDA$8,020 $6,784 $5,243 1,236 1,541 
Capital expenditures$3,152 $2,021 $1,595 1,131 426 

Changes in commodity prices and sales volumes affect both revenues and cost of sales and fuel and, therefore, the impact is largely offset between these line items.

Due to the Medallion Acquisition and EnLink Controlling Interest Acquisition, operating results for these two companies are included in our financial results beginning November 1, 2024, and October 15, 2024, respectively.

2025 vs. 2024 - Operating income increased $752 million primarily as a result of the following:
•Natural Gas Gathering and Processing - an increase of $469 million due primarily to the operating income of 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; and
•Natural Gas Liquids - an increase of $120 million due primarily to the operating income of EnLink, higher exchange services and higher optimization and marketing, offset partially by higher operating costs; offset by
•Natural Gas Pipelines - a decrease of $104 million due primarily to the impact of the interstate natural gas pipeline divestiture in 2024, offset partially by the operating income of EnLink and higher optimization and marketing; offset by
•Refined Products and Crude - an increase of $276 million due primarily to the operating income of Medallion and EnLink and lower operating costs.

Net income and diluted EPS increased due primarily to the items discussed above, offset partially by higher interest expense due to higher debt balances resulting from the September 2024 $7.0 billion notes offering, the August 2025 $3.0 billion notes offering, the acquired debt balances from the EnLink Controlling Interest Acquisition in 2024 and increased short-term borrowings in 2025 and higher equity in net earnings from investments in 2024.

Capital expenditures increased due primarily to the timing of our large capital projects and routine capital projects associated with the growth of our operations. Please refer to the “Recent Developments” section of Management’s Discussion and Analysis of Financial Condition and Results of Operations in this Annual Report for additional information on our capital projects.

Additional information regarding our financial results and operating information is provided in the following discussion for each of our segments.
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Selected Financial Results and Operating Information for the Year Ended December 31, 2024 vs. 2023 - The consolidated and segment financial results and operating information for the year ended December 31, 2024, compared with the year ended December 31, 2023, are included in Part II, Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations of our 2024 Annual Report on Form 10-K, which is available via the SEC’s website at www.sec.gov and our website at www.oneok.com.

Natural Gas Gathering and Processing

Capital Projects - Our Natural Gas Gathering and Processing segment invests in capital projects in natural gas and NGL-rich areas across key basins where we operate. Our growth strategy is focused on providing solutions to producer customers that expand our presence within our key operating regions. See “Capital Projects” in the “Recent Developments” section for more information on our capital projects.

For a discussion of our capital expenditure financing, see “Capital Expenditures” in the “Liquidity and Capital Resources” section.

Selected Financial Results and Operating Information - The following tables set forth certain selected financial results and operating information for our Natural Gas Gathering and Processing segment for the periods indicated:

Years Ended December 31,2025 vs. 20242024 vs. 2023
Financial Results202520242023$ Increase (Decrease)
(Millions of dollars)
NGL and condensate sales$4,372 $3,033 $2,479 1,339 554 
Residue natural gas sales2,137 1,203 1,398 934 (195)
Gathering, compression, dehydration and processing fees and other revenue1,175 353 179 822 174 
Cost of sales and fuel (exclusive of depreciation and operating costs)(4,617)(2,600)(2,364)2,017 236 
Operating costs, excluding noncash compensation adjustments(960)(583)(448)377 135 
Adjusted EBITDA from unconsolidated affiliates5 3 1 2 2 
Other26 75 (1)(49)76 
Adjusted EBITDA$2,138 $1,484 $1,244 654 240 
Capital expenditures$1,314 $492 $448 822 44 

Changes in commodity prices and sales volumes affect both revenue and cost of sales and fuel and, therefore, the impact is largely offset between these line items.

2025 vs. 2024 - Adjusted EBITDA increased $654 million primarily as a result of the following:
•an increase of $740 million due to adjusted EBITDA from EnLink; and
•an increase of $99 million from higher volumes due primarily to increased production in the Mid-Continent and Rocky Mountain regions; offset by
•a decrease of $122 million due to lower realized prices, primarily NGL prices, net of hedging; and
•a decrease of $81 million from the divestiture of certain nonstrategic assets in 2024.

Capital expenditures increased in 2025 due primarily to our routine and large capital projects, including our projects to relocate a processing plant to the Permian Basin from North Texas and construct our Bighorn processing plant in the Permian Basin.

 Years Ended December 31,
Operating Information202520242023
Natural gas processed (MMcf/d) (a)(b)
5,588 2,317 2,249 
(a) - Included volumes for consolidated entities only and excluded EnLink operating statistics for 2024 as they were not meaningful to full-year 2024 operating results.
(b) - Included volumes we processed at company-owned and third-party facilities.

2025 vs. 2024 - Our natural gas processed volumes increased in 2025 due to incremental volumes from EnLink and increased production in the Mid-Continent and Rocky Mountain regions.
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Natural Gas Liquids

Capital Projects - Our Natural Gas Liquids segment invests in capital projects to transport, fractionate, store, deliver to market centers and receive NGL supply from shale and other resource development areas. Our growth strategy is focused on connecting diversified raw feed supply basins to Purity NGL export, petrochemical and refining demand centers. See “Capital Projects” in the “Recent Developments” section for more information on our capital projects.

For a discussion of our capital expenditure financing, see “Capital Expenditures” in the “Liquidity and Capital Resources” section.

Selected Financial Results and Operating Information - The following tables set forth certain selected financial results and operating information for our Natural Gas Liquids segment for the periods indicated:
Years Ended December 31,2025 vs. 20242024 vs. 2023
Financial Results202520242023$ Increase (Decrease)
(Millions of dollars)
NGL and condensate sales$15,405 $14,446 $13,666 959 780 
Exchange service and other revenues347 514 559 (167)(45)
Transportation and storage revenues258 207 204 51 3 
Cost of sales and fuel (exclusive of depreciation and operating costs)(12,533)(11,994)(11,592)539 402 
Operating costs, excluding noncash compensation adjustments(801)(728)(637)73 91 
Adjusted EBITDA from unconsolidated affiliates101 95 67 6 28 
Other2 3 778 (1)(775)
Adjusted EBITDA$2,779 $2,543 $3,045 236 (502)
Capital expenditures$758 $987 $818 (229)169 

Changes in commodity prices and sales volumes affect both revenues and cost of sales and fuel and, therefore, the impact is largely offset between these line items.

2025 vs. 2024 - Adjusted EBITDA increased $236 million primarily as a result of the following:
•an increase of $183 million due to adjusted EBITDA from EnLink;
•an increase of $39 million in exchange services due primarily to:
◦$94 million of higher volumes in the Rocky Mountain region; and
◦$27 million of higher average fee rates in the Rocky Mountain region; offset partially by
◦$44 million of lower average fee rates in the Mid-Continent region;
◦$21 million of lower volumes in the Mid-Continent region; and
◦$20 million of higher transportation costs and higher inventory of unfractionated NGLs; and
•an increase of $31 million in optimization and marketing due primarily to higher earnings on sales of Purity NGLs held in inventory; offset by
•an increase of $16 million in operating costs due primarily to higher employee-related costs associated with the growth of our operations.

Capital expenditures decreased in 2025 due primarily to the completion of our MB-6 fractionator and pipeline expansion projects in 2024, offset partially by our Medford fractionator rebuild project.
Years Ended December 31,
Operating Information202520242023
Raw feed throughput (MBbl/d) (a)
1,496 1,309 1,359 
Average Conway-to-Mont Belvieu Oil Price Information Service price differential - ethane in ethane/propane mix ($/gallon)
$0.02 $0.01 $0.04 
(a) - Represents physical raw feed volumes for which we provided transportation and/or fractionation services, and excluded EnLink operating statistics in 2024 as they were not meaningful to full-year 2024 operating results.

We generally expect ethane volumes to increase or decrease with corresponding increases or decreases in overall NGL production. However, ethane volumes may experience growth or decline greater than corresponding growth or decline in overall NGL production due to ethane economics causing producers to recover or reject ethane.
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2025 vs. 2024 - Volumes increased in 2025 due primarily to incremental volumes from EnLink, higher ethane volumes in the Rocky Mountain region and higher volumes on short-term fractionation contracts in the Gulf Coast region, offset partially by lower ethane volumes in the Mid-Continent region.

Natural Gas Pipelines

Capital Projects - Our Natural Gas Pipelines segment invests in capital projects that provide transportation and services to end users. Our growth strategy is focused on expanding our transportation and storage capacity and services by connecting residue natural gas supply to demand markets and end users. See “Capital Projects” in the “Recent Developments” section for more information on our capital projects.

For a discussion of our capital expenditure financing, see “Capital Expenditures” in the “Liquidity and Capital Resources” section.

Interstate Natural Gas Pipeline Divestiture - On December 31, 2024, we completed the sale of three of our wholly owned interstate natural gas pipeline systems to DT Midstream, Inc.

Selected Financial Results and Operating Information - The following tables set forth certain selected financial results and operating information for our Natural Gas Pipelines segment for the periods indicated:
Years Ended December 31,2025 vs. 20242024 vs. 2023
Financial Results202520242023$ Increase (Decrease)
(Millions of dollars)
Transportation revenues$423 $523 $423 (100)100 
Storage revenues188 161 159 27 2 
Residue natural gas sales and other revenues1,235 138 41 1,097 97 
Cost of sales and fuel (exclusive of depreciation and operating costs)(1,005)(112)(28)893 84 
Operating costs, excluding noncash compensation adjustments(224)(225)(194)(1)31 
Adjusted EBITDA from unconsolidated affiliates 244 187 160 57 27 
Other— 228 (2)(228)230 
Adjusted EBITDA$861 $900 $559 (39)341 
Capital expenditures$237 $258 $228 (21)30 

Changes in commodity prices and sales volumes affect both revenues and cost of sales and fuel and, therefore, the impact is largely offset between these line items.

2025 vs. 2024 - Adjusted EBITDA decreased $39 million primarily as a result of the following:
•a decrease of $359 million due to the interstate natural gas pipeline divestiture in 2024, offset by
•an increase of $253 million due to adjusted EBITDA from EnLink;
•an increase of $33 million due to optimization and marketing activity;
•an increase of $14 million in storage services due primarily to increased storage volumes; and
•an increase of $12 million in transportation services due primarily to higher transportation rates and volumes.

Capital expenditures decreased in 2025 due primarily to the completion of capital projects in 2024, offset partially by increased growth projects primarily from EnLink.
 Years Ended December 31,
Operating Information (a)202520242023
Natural gas transportation capacity contracted (MDth/d)
7,315 8,176 7,743 
Transportation capacity contracted91 %97 %96 %
(a) - Included volumes for consolidated entities only and excluded EnLink operating statistics in 2024 as they were not meaningful to full-year 2024 operating results.

2025 vs. 2024 - Natural gas transportation capacity decreased due primarily to the interstate natural gas pipeline divestiture in 2024, offset partially by EnLink transportation capacity contracted included in 2025.

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Refined Products and Crude

Capital Projects - Our Refined Products and Crude segment invests in capital projects to transport, store and distribute Refined Products and crude oil primarily throughout the central United States. Our growth strategy is focused on expanding our core business and marketing presence. See “Capital Projects” in the “Recent Developments” section for more information on our capital projects.

For a discussion of our capital expenditure financing, see “Capital Expenditures” in the “Liquidity and Capital Resources” section.

Selected Financial Results and Operating Information - The following tables set forth certain selected financial results and operating information for our Refined Products and Crude segment for the periods indicated:
Years Ended December 31,September 25 through December 31,2025 vs. 2024
Financial Results202520242023 (a)$ Increase (Decrease)
(Millions of dollars)
Product sales$10,631 $2,258 $502 8,373 
Transportation revenues1,733 1,539 392 194 
Storage, terminals and other revenues675 663 177 12 
Cost of sales and fuel (exclusive of depreciation and operating costs)
(10,171)(1,949)(450)8,222 
Operating costs, excluding noncash compensation adjustments
(879)(857)(192)22 
Adjusted EBITDA from unconsolidated affiliates166 247 36 (81)
Other22 (9)— 31 
Adjusted EBITDA$2,177 $1,892 $465 285 
Capital expenditures$752 $216 $52 536 
(a) - The year ended December 31, 2023, included results subsequent to the Magellan Acquisition.

Changes in commodity prices and sales volumes affect both revenues and cost of sales and fuel and, therefore, the impact is largely offset between these line items.

2025 vs. 2024 - Adjusted EBITDA increased $285 million primarily as a result of the following:
•an increase of $295 million due to adjusted EBITDA from Medallion and EnLink;
•a decrease of $55 million in operating costs due primarily to $40 million of lower outside services and $13 million of lower property taxes; and
•an increase of $28 million due primarily to the sale of environmental credits generated by our liquids blending business; offset by
•a decrease of $81 million in adjusted EBITDA from unconsolidated affiliates due primarily to lower earnings on BridgeTex associated with the nonrecurring recognition of deferred revenue in 2024; and
•a decrease of $10 million in optimization and marketing due primarily to lower liquids blending margins.

Capital expenditures increased in 2025, due primarily to our routine and large capital projects, including our greater Denver Refined Products pipeline expansion project.
Years EndedThree Months Ended
December 31,December 31,
Operating Information (a)
202520242023
Refined Products volumes shipped (MBbl/d)
1,526 1,512 1,547 
Crude oil volumes shipped (MBbl/d)
1,784 783 808 
(a) - Included volumes for consolidated entities only and excluded Medallion and EnLink operating statistics in 2024 as they were not
meaningful to full-year 2024 operating results.

2025 vs. 2024 - Refined Products volumes shipped remained relatively unchanged.

Crude oil volumes shipped increased in 2025 due primarily to incremental volumes from Medallion and EnLink.

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Non-GAAP Financial Measures

The following table sets forth a reconciliation of net income, the nearest comparable GAAP financial performance measure, to adjusted EBITDA for the periods indicated:
Years Ended December 31,
(Unaudited)202520242023
Reconciliation of net income to adjusted EBITDA
(Millions of dollars)
Net income$3,462 $3,112 $2,659 
Interest expense, net of capitalized interest1,783 1,371 866 
Depreciation and amortization1,514 1,134 769 
Income taxes1,028 998 838 
Adjusted EBITDA from unconsolidated affiliates516 532 264 
Equity in net earnings from investments(386)(439)(202)
Noncash compensation expense and other (a)103 76 49 
Adjusted EBITDA (b)(c)(d)$8,020 $6,784 $5,243 
Reconciliation of segment adjusted EBITDA to adjusted EBITDA
Segment adjusted EBITDA:
Natural Gas Gathering and Processing$2,138 $1,484 $1,244 
Natural Gas Liquids (d)2,779 2,543 3,045 
Natural Gas Pipelines (c)861 900 559 
Refined Products and Crude (e)2,177 1,892 465 
Other (b)65 (35)(70)
Adjusted EBITDA (b)(c)(d)$8,020 $6,784 $5,243 
(a) - The year ended December 31, 2025, included noncash transaction costs related primarily to the EnLink Acquisition of $16 million included within noncash compensation and other.
(b) - The year ended December 31, 2025, included corporate net gains on extinguishment of debt of $106 million in connection with open market repurchases and interest income of $33 million, offset partially by transaction costs related primarily to the EnLink Acquisition of $65 million. The year ended December 31, 2024. included transaction costs related primarily to the EnLink Acquisitions and Medallion Acquisition of $73 million, offset partially by interest income of $39 million. The year ended December 31, 2023, included transaction costs related to the Magellan Acquisition of $158 million, offset partially by interest income of $49 million and corporate net gains on extinguishment of debt of $41 million in connection with open market repurchases.
(c) - The year ended December 31, 2024, included a gain of $227 million from the interstate natural gas pipeline divestiture.
(d) - The year ended December 31, 2023, included $633 million related to the Medford incident, including a settlement gain of $779 million, offset partially by $146 million of third-party fractionation costs.
(e) - The year ended December 31, 2023, included segment adjusted EBITDA for the period September 25, 2023, through December 31, 2023.

CONTINGENCIES

See Note O of the Notes to Consolidated Financial Statements in this Annual Report for a discussion of regulatory and legal matters.

Other Legal Proceedings - We are a party to various legal proceedings that have arisen in the normal course of our operations. While the results of these proceedings cannot be predicted with certainty, we believe the reasonably possible losses from such proceedings, individually and in the aggregate, are not material. Additionally, we believe the probable final outcome of such proceedings will not have a material adverse effect on our consolidated results of operations, financial position or cash flows.

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LIQUIDITY AND CAPITAL RESOURCES

General - Our primary sources of cash inflows are operating cash flows, proceeds from our commercial paper program and our $3.5 Billion Credit Agreement, debt issuances and the issuance of common stock for our liquidity and capital resource requirements.

We expect our sources of cash inflows to provide sufficient resources to finance our operations, capital expenditures, quarterly cash dividends, maturities of long-term debt, share repurchases and contributions to unconsolidated affiliates and joint ventures. We believe we have sufficient liquidity due to our $3.5 Billion Credit Agreement, which expires in February 2030, our $3.5 billion commercial paper program and access to $1.0 billion available through our “at-the-market” equity program. As of February 16, 2026, no shares have been sold through our “at-the-market” equity program.

We may manage interest-rate risk through the use of fixed-rate debt, floating-rate debt, Treasury locks and interest-rate swaps. For additional information on our interest-rate derivative instruments, see Note D of the Notes to Consolidated Financial Statements in this Annual Report.

Cash Management - At December 31, 2025, we had $78 million of cash and cash equivalents. For our wholly owned subsidiaries, we use a centralized cash management program that concentrates the cash assets of our wholly owned nonguarantor operating subsidiaries in joint accounts for the purposes of providing financial flexibility and lowering the cost of borrowing, transaction costs and bank fees. Our centralized cash management program provides that funds in excess of the daily needs of our operating subsidiaries are concentrated, consolidated or otherwise made available for use by other entities within our consolidated group. Our operating subsidiaries participate in this program to the extent they are permitted pursuant to FERC regulations or their operating agreements. Under the cash management program, depending on whether a participating subsidiary has short-term cash surpluses or cash requirements, we provide cash to the subsidiary or the subsidiary provides cash to us.

Following the completion of the EnLink Acquisition on January 31, 2025, we terminated an agreement to provide revolving unsecured loans to EnLink through a promissory note, as EnLink operating subsidiaries are wholly owned and now participate in the cash management program described above. For additional information, see Note G of the Notes to Consolidated Financial Statements in this Annual Report.

Guarantees - ONEOK, ONEOK Partners, the Intermediate Partnership, Magellan, EnLink and EnLink Partners have cross guarantees in place for ONEOK’s and ONEOK Partners’ indebtedness. These guarantees in place for our and ONEOK Partners’ indebtedness are full, irrevocable, unconditional and absolute joint and several guarantees to the holders of each series of outstanding securities. Liabilities under the guarantees rank equally in right of payment with all of the guarantors’ existing and future senior unsecured indebtedness. The Intermediate Partnership holds all of ONEOK Partners’ interests and equity in its subsidiaries, which are nonguarantors, and substantially all the assets and operations reside with nonguarantor operating subsidiaries. Magellan, EnLink and EnLink Partners hold interests in their subsidiaries, which are nonguarantors, and substantially all the assets and operations reside with nonguarantor operating subsidiaries. Therefore, as allowed under Rule 13-01 of Regulation S-X, we have excluded the summarized financial information for each issuer and guarantor as the combined financial information of subsidiary issuers and parent guarantors, excluding our ownership of all interest in ONEOK Partners, Magellan and EnLink, reflect no material assets or liabilities or results of operations apart from guaranteed indebtedness.

For additional information on our indebtedness, see Note G of the Notes to Consolidated Financial Statements in this Annual Report.

Short-term Liquidity - Our principal sources of short-term liquidity consist of cash generated from operating activities, distributions received from our unconsolidated affiliates, proceeds from our commercial paper program and our $3.5 Billion Credit Agreement. In February 2025, we amended and restated our $2.5 Billion Credit Agreement to increase the size to $3.5 billion, extend the term to February 2030 and make other nonmaterial modifications. All other terms and conditions remain substantially the same. In September 2025, we increased the size of our commercial paper program to $3.5 billion from $2.5 billion. As of February 16, 2026, we had no borrowings under our $3.5 Billion Credit Agreement, and we are in compliance with all covenants. Upon closing of the EnLink Acquisition on January 31, 2025, the EnLink Revolving Credit Facility was terminated. For additional information on the EnLink Revolving Credit Facility, see Note G of the Notes to Consolidated Financial Statements in this Annual Report.


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We had working capital (defined as current assets less current liabilities) deficits of $1.9 billion and $481 million as of December 31, 2025, and December 31, 2024, respectively, due primarily to current maturities of long-term debt and short-term borrowings at December 31, 2025, and current maturities of long-term debt at December 31, 2024. Generally, our working capital is influenced by several factors, including, among other things: (i) the timing of (a) debt and equity issuances, (b) the funding of capital expenditures, (c) scheduled debt payments, and (d) accounts receivable and payable; and (ii) the volume and cost of inventory and commodity imbalances. We may have working capital deficits in future periods as our long-term debt becomes current. We do not expect a working capital deficit of this nature to have a material adverse impact to our cash flows or operations.

For additional information on our $3.5 Billion Credit Agreement, see Note G of the Notes to Consolidated Financial Statements in this Annual Report.

Long-term Financing - In addition to our principal sources of short-term liquidity discussed above, we expect to fund our longer-term financing requirements by issuing long-term notes, as needed. Other options to obtain financing include, but are not limited to, issuing common stock, loans from financial institutions, issuance of convertible debt securities or preferred equity securities, asset securitization and the sale and lease-back of facilities.

We may, at any time, seek to retire or purchase our or ONEOK Partners’ outstanding debt through cash purchases and/or exchanges for equity or debt, in open market repurchases, privately negotiated transactions, exercise of contractual call rights, public tender offers or otherwise. Such repurchases and exchanges, if any, will be on such terms and prices as we may determine and will depend on prevailing market conditions, or liquidity requirements, contractual restrictions and other factors. The amounts involved may be material.

Debt Issuances - In August 2025, we completed an underwritten public offering of $3.0 billion senior unsecured notes consisting of $750 million, 4.95% senior notes due 2032; $1.0 billion, 5.4% senior notes due 2035; and $1.25 billion, 6.25% senior notes due 2055. The net proceeds, after deducting underwriting discounts, commissions and offering expenses, were $2.96 billion. The net proceeds from this offering were partially used to repay our commercial paper outstanding and repay in full at maturity our senior notes due September 2025. The remaining net proceeds from the offering were used for general corporate purposes, including the repurchase and redemption of existing notes.

Debt Extinguishments - We completed the following debt extinguishments in 2025:
Principal
(Millions of dollars)
$250 at 3.2% due March 2025$250 
$750 at 4.15% due June 2025422 
$400 at 2.2% due September 2025387 
$600 at 5.85% due January 2026 (a)
600 
$650 at 5.0% due March 2026 (a)
650 
Open Market Repurchases (b)
789 
Total$3,098 
(a) - Amounts redeemed at 100% of principal plus accrued and unpaid interest.
(b) - In 2025, we repurchased in the open market certain of our senior notes in the principal amount of $789 million for an aggregate repurchase price of $681 million, including accrued and unpaid interest. In connection with these open market repurchases, we recognized $106 million of net gains on extinguishment of debt which is included in other income, net in our Consolidated Statement of Income for the year ended December 31, 2025.

Equity Issuances - On May 28, 2025, we completed the Delaware Basin JV Acquisition. Pursuant to the purchase agreement, we issued approximately 4.9 million shares of ONEOK common stock to the seller with a fair value of $391 million as of the closing date.

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. There are no remaining Series B Preferred Units outstanding.

Share Repurchase Program - Our Board of Directors authorized a share repurchase program to buy up to $2.0 billion of our outstanding common stock. The program will terminate upon completion of the repurchase of the $2.0 billion of common stock or on January 1, 2029, whichever occurs first. For the year ended December 31, 2025, we repurchased $62 million of our outstanding common stock with cash on hand.
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Material Commitments - We have material cash commitments related to our capital expenditures, senior notes and corresponding interest payments, which we expect to fund through our sources of cash inflows discussed above. Our senior notes and interest payments are discussed in Note G of the Notes to Consolidated Financial Statements in this Annual Report. We also have cash commitments related to transportation, storage and other commercial contracts, as well as our financial and physical derivative obligations, which we expect to fund with cash from operations.

Capital Expenditures - We proactively monitor lead times on materials and equipment used in constructing capital projects, and we enter into procurement agreements for long-lead items for potential projects to plan for future growth. Our capital expenditures are financed typically through operating cash flows and short- and long-term debt.

The following table sets forth our capital expenditures, less allowance for equity funds used during construction, for the periods indicated:
Capital Expenditures2025
2024 (a)
2023
 
(Millions of dollars)
Natural Gas Gathering and Processing$1,314 $492 $448 
Natural Gas Liquids758 987 818 
Natural Gas Pipelines237 258 228 
Refined Products and Crude (b)
752 216 52 
Other91 68 49 
Total capital expenditures$3,152 $2,021 $1,595 
(a) - The year ended December 31, 2024, included capital expenditures for EnLink and Medallion for the period October 15, 2024, and November 1, 2024, through December 31, 2024, respectively.
(b) - The year ended December 31, 2023, included capital expenditures for Magellan for the period September 25, 2023, through December 31, 2023.

Capital expenditures increased in 2025, compared with 2024, due primarily to the timing of our large capital projects and routine capital projects associated with the growth of our operations. See discussion of our announced capital projects in the “Recent Developments” section.

We expect total capital expenditures of $2.7 - $3.2 billion in 2026.

Credit Ratings - Our credit ratings as of February 16, 2026, are shown in the table below:
Rating AgencyLong-term RatingShort-term RatingOutlook
Moody’sBaa2Prime-2Stable
S&PBBBA-2Stable
FitchBBBF2Stable
Our credit ratings, which are investment grade, may be affected by our leverage, liquidity, credit profile or potential transactions. The most common criteria for assessment of our credit ratings are the debt-to-EBITDA ratio, interest coverage, business risk profile and liquidity. If our credit ratings were downgraded, our cost to borrow funds under our $3.5 Billion Credit Agreement could increase, and a potential loss of access to the commercial paper market could occur. In the event that we are unable to borrow funds under our commercial paper program and there has not been a material adverse change in our business, we would continue to have access to our $3.5 Billion Credit Agreement, which expires in 2030. An adverse credit rating change alone is not a default under our $3.5 Billion Credit Agreement.

In the normal course of business, our counterparties provide us with secured and unsecured credit. In the event of a downgrade in our credit ratings or a significant change in our counterparties’ evaluation of our creditworthiness, we could be required to provide additional collateral in the form of cash, letters of credit or other negotiable instruments as a condition of continuing to conduct business with such counterparties. We may be required to fund margin requirements with our counterparties with cash, letters of credit or other negotiable instruments.

Dividends - Holders of our common stock share equally in any common stock dividends declared by our Board of Directors. In 2025, we paid common stock dividends totaling $4.12 per share, an increase of 4% compared to the 2024 dividend of $3.96 per share. In February 2026, we paid a quarterly common stock dividend of $1.07 per share ($4.28 per share on an annualized basis), an increase of 4% compared with the same quarter in the prior year.

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For the year ended December 31, 2025, our cash flows from operations exceeded dividends paid by $3.0 billion. We expect our cash flows from operations to continue to sufficiently fund our cash dividends. To the extent operating cash flows are not sufficient to fund our dividends, we may utilize cash on hand from other sources of short- and long-term liquidity to fund a portion of our dividends.

CASH FLOW ANALYSIS

We use the indirect method to prepare our Consolidated Statements of Cash Flows. Under this method, we reconcile net income to cash flows provided by operating activities by adjusting net income for those items that affect net income but do not result in actual cash receipts or payments during the period and for operating cash items that do not impact net income. These reconciling items can include depreciation and amortization, deferred income taxes, impairment charges, allowance for equity funds used during construction, gain or loss on sale of business and assets, net undistributed earnings from unconsolidated affiliates, share-based compensation expense, other amounts and changes in our assets and liabilities not classified as investing or financing activities.

The following table sets forth the changes in cash flows by operating, investing and financing activities for the periods indicated:
Years Ended December 31,
202520242023
(Millions of dollars)
Total cash provided by (used in):
Operating activities$5,599 $4,888 $4,421 
Investing activities(3,751)(6,612)(6,404)
Financing activities(2,503)2,119 2,101 
Change in cash and cash equivalents(655)395 118 
Cash and cash equivalents at beginning of period733 338 220 
Cash and cash equivalents at end of period$78 $733 $338 

Operating Cash Flows - Operating cash flows are affected by earnings from our business activities and changes in our operating assets and liabilities. Changes in commodity prices and demand for our services or products, whether because of general economic conditions, changes in supply, changes in demand for the end products that are made with our products or increased competition from other service providers, could affect our earnings and operating cash flows. Our operating cash flows can also be impacted by changes in our inventory balances, which are driven primarily by commodity prices, supply, demand and the operation of our assets.

2025 vs. 2024 - Cash flows from operating activities, before changes in operating assets and liabilities increased $1.0 billion for the year ended December 31, 2025, compared with the same period in 2024, due primarily to the impact of the EnLink and Medallion Acquisitions as discussed in “Financial Results and Operating Information.”

The changes in operating assets and liabilities decreased operating cash flows $380 million for the year ended December 31, 2025, compared with a decrease of $43 million for the same period in 2024. This change is due primarily to changes in accounts receivable resulting from the growth of our operations and the timing of the receipt of cash from counterparties and from inventory, both of which vary from period to period, and with changes in commodity prices. These changes were offset partially by changes in accounts payable resulting from the growth of our operations and the timing of payments to vendors, suppliers and other third parties, which vary from period to period, and with changes in commodity prices.

Investing Cash Flows

2025 vs. 2024 - Cash used in investing activities for the year ended December 31, 2025, decreased $2.9 billion compared with the same period in 2024, due primarily to cash paid to acquire EnLink and Medallion in 2024, offset partially by proceeds received from the interstate natural gas pipeline divestiture in 2024, an increase in capital expenditures related to our capital projects in 2025 and cash paid for the BridgeTex Additional Interest Acquisition.

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Financing Cash Flows

2025 vs. 2024 - Cash from financing activities for the year ended December 31, 2025, decreased $4.6 billion compared with the same period in 2024, due primarily to the issuance of senior unsecured notes associated with acquisitions in 2024, increased extinguishment of long-term debt in 2025, cash paid for the Delaware Basin JV Acquisition and increased dividends paid in 2025, offset partially by the issuance of senior unsecured notes in August 2025 and an increase in short-term borrowings in 2025.

Cash Flow Analysis for the Year Ended December 31, 2024 vs. 2023 - The cash flow analysis for the year ended December 31, 2024, compared with the year ended December 31, 2023, is included in Part II, Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations of our 2024 Annual Report on Form 10-K, which is available via the SEC’s website at www.sec.gov and our website at www.oneok.com.

IMPACT OF NEW ACCOUNTING STANDARDS

Information about the impact of new accounting standards is included in Note A of the Notes to Consolidated Financial Statements in this Annual Report.

CRITICAL ACCOUNTING ESTIMATES

The preparation of our Consolidated Financial Statements and related disclosures in accordance with GAAP requires us to make estimates and assumptions with respect to values or conditions that cannot be known with certainty that affect the reported amounts of assets and liabilities, and the disclosure of contingent assets and liabilities at the date of the Consolidated Financial Statements. These estimates and assumptions also affect the reported amounts of revenue and expenses during the reporting period. Although we believe these estimates and assumptions are reasonable, actual results could differ from our estimates.

The following is a summary of our most critical accounting estimates, which are defined as those estimates most important to the portrayal of our financial condition and results of operations and requiring management’s most difficult, subjective or complex judgment, particularly because of the need to make estimates concerning the impact of inherently uncertain matters. We have discussed the development and selection of our critical accounting estimates with the Audit Committee of our Board of Directors. See Note A of the Notes to Consolidated Financial Statements in this Annual Report for the description of our accounting policies.

Derivatives and Risk-management Activities - We utilize derivatives to reduce our market-risk exposure to commodity price and interest-rate fluctuations and to achieve more predictable cash flows. The accounting for changes in the fair value of a derivative instrument depends on whether it qualifies and has been designated as part of a hedging relationship. When possible, we implement effective hedging strategies using derivative financial instruments that qualify as hedges for accounting purposes. We have not used derivative instruments for trading purposes. For a derivative designated as a cash flow hedge, the gain or loss from a change in fair value of the derivative instrument is deferred in accumulated other comprehensive loss until the forecasted transaction affects earnings, at which time the fair value of the derivative instrument is reclassified into earnings.

We assess hedging relationships at the inception of the hedge and periodically thereafter, to determine whether the hedging relationship is, and is expected to remain, highly effective. We do not believe that changes in our fair value estimates of our derivative instruments have a material impact on our results of operations, as the majority of our derivatives are accounted for as effective cash flow hedges. However, if a derivative instrument is ineligible for cash flow hedge accounting or if we elect not to designate it as a cash flow hedge, changes in fair value of the derivative instrument would be recorded currently in earnings. Additionally, if a cash flow hedge ceases to qualify for hedge accounting treatment because it is no longer probable that the forecasted transaction will occur, the change in fair value of the derivative instrument would be recognized in earnings. For more information on commodity price sensitivity and a discussion of the market risk of pricing changes, see Item 7A, Quantitative and Qualitative Disclosures about Market Risk.

See Notes A, C and D of the Notes to Consolidated Financial Statements in this Annual Report for additional discussion of fair value measurements and derivatives and risk-management activities.

Impairment of Goodwill, Long-Lived Assets, Including Intangible Assets and Equity Method Investments - We assess our goodwill for impairment at least annually as of July 1, unless events or changes in circumstances indicate an impairment may have occurred before that time. As part of our goodwill impairment test, we may first assess qualitative factors (including macroeconomic conditions, industry and market considerations, cost factors and overall financial performance) to determine
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whether it is more likely than not that the fair value of each of our reporting units was less than its carrying amount. If further testing is necessary, or a quantitative test is elected, we perform a Step 1 analysis for goodwill impairment.

In a Step 1 analysis, an assessment is made by comparing the fair value of a reporting unit with its carrying amount, including goodwill. If the carrying value of a reporting unit exceeds its fair value, an impairment loss is recognized in an amount equal to that excess, limited to the total amount of goodwill allocated to that reporting unit.

We assess our long-lived asset groups, including intangible assets, for impairment whenever events or changes in circumstances indicate that an asset group’s carrying amount may not be recoverable. An impairment is indicated if the carrying amount of a long-lived asset group exceeds the sum of the undiscounted future cash flows expected to result from the use and eventual disposition of the asset group. If an impairment is indicated, we record an impairment loss equal to the difference between the carrying value and the fair value of the long-lived asset group.

We evaluate equity method investments in unconsolidated affiliates for impairment whenever events or circumstances indicate that there is an other-than-temporary loss in value of the investment. When evidence of loss in value has occurred, we compare our estimate of fair value of the investment to the carrying value of the investment to determine whether an impairment has occurred. If the estimated fair value is less than the carrying value and we consider the decline in value to be other-than-temporary, the excess of the carrying value over the fair value is recognized in our consolidated financial statements as an impairment charge.

Our impairment tests require the use of assumptions and estimates, such as industry economic factors and the profitability of future business strategies. To estimate undiscounted future cash flows of long-lived assets we may apply a probability-weighted approach that incorporates different assumptions and potential outcomes related to the underlying long-lived assets. The evaluation is performed at the lowest level for which separately identifiable cash flows exist. To estimate the fair value of these assets, we use two generally accepted valuation approaches, an income approach and a market approach. Under the income approach, our discounted cash flow analysis includes the following inputs that are not readily available: a discount rate reflective of industry cost of capital, our estimated contract rates, volumes, operating margins, operating and maintenance costs and capital expenditures. Under the market approach, our inputs include EBITDA multiples, which are estimated from recent peer acquisition transactions, and forecasted EBITDA, which incorporates inputs similar to those used under the income approach. If actual results are not consistent with our assumptions and estimates or our assumptions and estimates change due to new information, we may be exposed to future impairment charges.

See Notes A, E, F and N of the Notes to Consolidated Financial Statements in this Annual Report for additional discussion of goodwill and intangible assets, long-lived assets and investments in unconsolidated affiliates.

Depreciation Methods and Estimated Useful Lives of Property, Plant and Equipment - Our property, plant and equipment are depreciated using the straight-line method that incorporates management assumptions regarding useful economic lives and residual values. As we place additional assets in service or acquire assets as a result of an acquisition or asset purchase, our estimates related to depreciation expense have become more significant and changes in estimated useful lives of our assets could have a material effect on our results of operations. At the time we place our assets in service, we believe such assumptions are reasonable; however, circumstances may develop that would cause us to change these assumptions, which would change our depreciation expense prospectively. Examples of such circumstances include changes in (i) competition, (ii) laws and regulations that limit the estimated economic life of an asset, (iii) technology that render an asset obsolete, (iv) expected salvage values, (v) results of rate cases or rate settlements on regulated assets and (vi) forecasts of the remaining economic life for the resource basins where our assets are located, if any. For the fiscal years presented in this Form 10-K, no changes were made to the determinations of useful lives that would have a material effect on the timing of depreciation expense in future periods.

See Note E of the Notes to Consolidated Financial Statements in this Annual Report for additional discussion of property, plant and equipment.

ITEM 7A.    QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Our exposure to market risk, discussed below, includes forward-looking statements and represents an estimate of possible changes in future earnings that could occur assuming hypothetical future movements in interest rates or commodity prices within our derivative portfolio. Our views on market risk are not necessarily indicative of actual results that may occur and do not represent the maximum possible gains and losses that may occur since actual gains and losses will differ from those estimated based on actual fluctuations in interest rates or commodity prices and the timing of transactions.

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We are exposed to market risk due to commodity price and interest-rate volatility. Market risk is the risk of loss arising from adverse changes in market rates and prices. We may use financial instruments, including forward sales, swaps, options and futures, to manage the risks of certain identifiable or anticipated transactions and achieve more predictable cash flows. Our risk-management function follows policies and procedures established by our Risk Oversight and Strategy Committee to monitor our natural gas, NGL, Refined Products, condensate and crude oil marketing activities and interest rates to ensure our hedging activities mitigate market risks and comply with approved thresholds or limits. We do not use financial instruments for trading purposes.

We utilize a sensitivity analysis model to assess the risk associated with our derivative portfolio. The sensitivity analysis measures the potential change in fair value of our derivative instruments based upon a hypothetical 10% movement in the underlying commodity prices or interest rates. In addition to these variables, the fair value of our derivative portfolio is influenced by fluctuations in the notional amounts of the instruments and the discount rates used to determine the present values. Because we enter into these derivative instruments for the purpose of mitigating the risks that accompany certain of our business activities, as described below, the change in the market value of our derivative portfolio would typically be offset largely by a corresponding gain or loss on the hedged item.

See Note A of the Notes to Consolidated Financial Statements in this Annual Report for a discussion on our accounting policies for our derivative instruments and the impact on our Consolidated Financial Statements.

COMMODITY PRICE RISK

As part of our hedging strategy, we use commodity derivative financial instruments and physical-forward contracts described in Note D of the Notes to Consolidated Financial Statements in this Annual Report to reduce the impact of near-term price fluctuations of natural gas, NGLs, Refined Products, condensate and crude oil.

The following table presents the effect a hypothetical 10% change in the underlying commodity prices would have on the estimated fair value of our commodity derivative instruments as of the dates indicated:
December 31,
Commodity Contracts20252024
(Millions of dollars)
Refined Products, crude oil and NGLs$80 $61 
Natural gas9 9 
Total change in estimated fair value of commodity contracts$89 $70 

Our sensitivity analysis represents an estimate of the reasonably possible gains and losses that would be recognized on our commodity derivative contracts assuming hypothetical movements in future market prices and is not necessarily indicative of actual results that may occur. Actual gains and losses may differ from estimates due to actual fluctuations in market prices, as well as changes in our commodity derivative portfolio during the year.

INTEREST-RATE RISK

We are exposed to interest-rate risk through borrowings under our $3.5 Billion Credit Agreement, commercial paper program and long-term debt issuances. Future increases in commercial paper rates or bond yields could expose us to increased interest costs on future borrowings. We may manage interest-rate risk through the use of fixed-rate debt, floating-rate debt, Treasury locks and interest-rate swaps.

Treasury locks are agreements to pay the difference between the benchmark Treasury rate and the rate that is designated in the terms of the agreement. In the third quarter and second quarter of 2025, we entered into $300 million notional quantity and $700 million notional quantity, respectively, of Treasury locks to hedge the variability of interest payments on a portion of our forecasted debt issuances. In the third quarter of 2025, we settled all of the outstanding $1.0 billion notional quantity of Treasury locks in connection with our underwritten public offering of $3.0 billion senior unsecured notes in August 2025. All of our Treasury locks were designated as cash flow hedges.

At December 31, 2025, and December 31, 2024, we had no outstanding interest-rate derivative instruments.

See Note D of the Notes to Consolidated Financial Statements in this Annual Report for more information on our hedging activities.

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COUNTERPARTY CREDIT RISK

We assess the creditworthiness of our counterparties on an ongoing basis and require security, including prepayments, letters of credit, liens and other forms of collateral, when appropriate. Certain of our counterparties may be impacted by a relatively low commodity price environment and could experience financial problems, which could result in nonpayment and/or nonperformance, which could adversely impact our results of operations. Following our acquisitions in 2024, we now transact with the counterparties of EnLink and Medallion. A substantial portion of EnLink and Medallion counterparties are rated investment-grade by S&P or provide a letter of credit or other collateral.

Natural Gas Gathering and Processing - Our Natural Gas Gathering and Processing segment derives fees for services primarily from major and independent crude oil and natural gas producers, which include both large integrated and independent exploration and production companies. In this segment, our downstream commodity sales customers are primarily utilities, large industrial companies, marketing companies and our NGL affiliate. We are not typically exposed to material credit risk with producers under fee with POP contracts as we sell the commodities and remit a portion of the sales proceeds back to the producer less our contractual fees. In 2025 and 2024, excluding EnLink in 2024, approximately 75% and 85%, respectively, of the downstream commodity sales in our Natural Gas Gathering and Processing segment were made to customers rated investment-grade by S&P, approved through comparable internal counterparty analysis or were secured by letters of credit or other collateral.

Natural Gas Liquids - Our Natural Gas Liquids segment’s counterparties are primarily NGL and natural gas gathering and processing companies; major and independent crude oil and natural gas production companies; utilities; large industrial companies; natural gasoline distributors; propane distributors; municipalities; and petrochemical, refining and marketing companies. We charge fees to NGL and natural gas gathering and processing counterparties and NGL pipeline transportation customers. We are not typically exposed to material credit risk on the majority of our exchange services fees, as we purchase NGLs from our gathering and processing counterparties and deduct our fee from the amounts we remit. We also earn sales revenue on the downstream sales of Purity NGLs. In 2025 and 2024, excluding EnLink in 2024, approximately 95% and 90%, respectively, of this segment’s commodity sales were made to customers rated investment-grade by S&P, approved through comparable internal counterparty analysis or were secured by letters of credit or other collateral. In addition, the majority of our Natural Gas Liquids segment’s pipeline tariffs provide us the ability to require security from shippers.

Natural Gas Pipelines - Our Natural Gas Pipelines segment’s customers are primarily local natural gas distribution companies, electric-generation facilities, large industrial companies, municipalities, producers, processors and marketing companies. In 2025 and 2024, excluding EnLink in 2024, approximately 80% and 90%, respectively, of our revenues in this segment were from customers rated investment-grade by S&P, approved through comparable internal counterparty analysis or were secured by letters of credit or other collateral. In addition, the majority of our pipeline tariffs in this segment provide us the ability to require security from shippers.

Refined Products and Crude - Our Refined Products and Crude segment’s customers include refiners, wholesalers, retailers, traders, railroads, airlines and regional farm cooperatives. In 2025 and 2024, excluding EnLink and Medallion in 2024, approximately 85% and 70%, respectively, of our revenues in this segment were from customers rated investment-grade by S&P, approved through comparable internal counterparty analysis or were secured by letters of credit, liens, or other collateral.
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ITEM 8.    FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

Report of Independent Registered Public Accounting Firm

To the Board of Directors and Shareholders of ONEOK, Inc.

Opinions on the Financial Statements and Internal Control over Financial Reporting

We have audited the accompanying consolidated balance sheets of ONEOK, Inc. and its subsidiaries (the "Company") as of December 31, 2025 and 2024, and the related consolidated statements of income, of comprehensive income, of equity and of cash flows for each of the three years in the period ended December 31, 2025, including the related notes (collectively referred to as the "consolidated financial statements"). We also have audited the Company's internal control over financial reporting as of December 31, 2025, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of the Company as of December 31, 2025 and 2024, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2025, in conformity with accounting principles generally accepted in the United States of America. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2025, based on criteria established in Internal Control - Integrated Framework (2013) issued by the COSO.

Basis for Opinions

The Company's management is responsible for these consolidated financial statements, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in Management’s Report on Internal Control over Financial Reporting appearing under Item 9A. Our responsibility is to express opinions on the Company’s consolidated financial statements and on the Company's internal control over financial reporting based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud, and whether effective internal control over financial reporting was maintained in all material respects.

Our audits of the consolidated financial statements included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.

Definition and Limitations of Internal Control over Financial Reporting

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

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Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

Critical Audit Matters

The critical audit matter communicated below is a matter arising from the current period audit of the consolidated financial statements that was communicated or required to be communicated to the audit committee and that (i) relates to accounts or disclosures that are material to the consolidated financial statements and (ii) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.

Revenue Recognition – Liquids Commodity Sales

As described in Note A to the consolidated financial statements, the Company records revenue from liquids commodity sales when the commodity is delivered to the customer as this represents the point in time when control of the product is transferred to the customer. Revenue is recorded based on the contracted selling price, which is generally index-based and settled daily or monthly. The Company recognized liquids commodity sales of $25,566 million for the year ended December 31, 2025.

The principal consideration for our determination that performing procedures relating to revenue recognition for liquids commodity sales is a critical audit matter is a high degree of auditor effort in performing procedures related to the Company’s revenue recognition.

Addressing the matter involved performing procedures and evaluating audit evidence in connection with forming our overall opinion on the consolidated financial statements. These procedures included testing the effectiveness of controls relating to the revenue recognition process for liquids commodity sales. These procedures also included, among others, (i) testing revenue recognized for a sample of liquids commodity sales revenue transactions by obtaining and inspecting source documents, such as contracts, settlement statements, invoices, and payments receipts and (ii) confirming a sample of outstanding customer invoices balances as of December 31, 2025, and for confirmations not returned, obtaining and inspecting source documents, such as contracts, settlement statements, invoices, and subsequent payment receipts.

s/ PricewaterhouseCoopers LLP
Tulsa, Oklahoma
February 24, 2026

We have served as the Company’s auditor since 2007.



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ONEOK, Inc. and Subsidiaries
CONSOLIDATED STATEMENTS OF INCOME
Years Ended December 31,
202520242023
(Millions of dollars, except per share amounts)
Revenues
Commodity sales$28,878 $17,780 $15,614 
Services and other4,751 3,918 2,063 
Total revenues (Note Q)33,629 21,698 17,677 
Cost of sales and fuel (exclusive of items shown separately below)23,373 13,311 11,929 
Operations and maintenance2,585 2,162 1,319 
Depreciation and amortization1,514 1,134 769 
General taxes378 334 216 
Transaction costs (Note B)81 73 158 
Other operating income, net (Notes A and B)(43)(305)(786)
Operating income5,741 4,989 4,072 
Equity in net earnings from investments (Note N)386 439 202 
Other income, net146 53 89 
Interest expense (net of capitalized interest of $68, $62 and $43, respectively)
(1,783)(1,371)(866)
Income before income taxes4,490 4,110 3,497 
Income taxes (Note M)(1,028)(998)(838)
Net income3,462 3,112 2,659 
Less: Net income attributable to noncontrolling interests69 77 — 
Net income attributable to ONEOK3,393 3,035 2,659 
Less: Preferred stock dividends— 1 1 
Net income available to common shareholders$3,393 $3,034 $2,658 
Basic EPS (Note J)$5.43 $5.19 $5.49 
Diluted EPS (Note J)$5.42 $5.17 $5.48 
Average shares (millions)
Basic624.8 584.6 484.3 
Diluted625.9 586.5 485.4 

See accompanying Notes to Consolidated Financial Statements.

ONEOK, Inc. and Subsidiaries  
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME 
 Years Ended December 31,
 202520242023
 (Millions of dollars)
Net income$3,462 $3,112 $2,659 
Other comprehensive income (loss), net of tax
Change in fair value of derivatives, net of tax of $(19), $16 and $(46), respectively
59 (53)155 
Derivative amounts reclassified to net income, net of tax of $1, $5 and $21,
 respectively
(2)(16)(66)
Changes in benefit plan obligations and other, net of tax of $(3), $(2) and $3,
 respectively
12 6 (14)
Total other comprehensive income (loss), net of tax69 (63)75 
Comprehensive income3,531 3,049 2,734 
Less: Comprehensive income attributable to noncontrolling interests69 77 — 
Comprehensive income attributable to ONEOK$3,462 $2,972 $2,734 
See accompanying Notes to Consolidated Financial Statements.
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ONEOK, Inc. and Subsidiaries
CONSOLIDATED BALANCE SHEETS
December 31,
20252024
Assets(Millions of dollars)
Current assets
Cash and cash equivalents$78 $733 
Accounts receivable, net3,010 2,326 
Inventories948 748 
Other current assets452 431 
Total current assets4,488 4,238 
Property, plant and equipment
Property, plant and equipment55,489 52,274 
Accumulated depreciation and amortization7,628 6,339 
Net property, plant and equipment (Note E)47,861 45,935 
Other assets
Investments in unconsolidated affiliates (Note N)2,889 2,316 
Goodwill (Note F)8,058 8,091 
Intangible assets, net (Note F)2,901 3,039 
Other assets444 450 
Total other assets14,292 13,896 
Total assets$66,641 $64,069 
Liabilities and equity
Current liabilities
Current maturities of long-term debt (Note G)$1,241 $1,059 
Short-term borrowings (Note G)820 — 
Accounts payable2,838 2,187 
Commodity imbalances217 260 
Accrued interest499 511 
Other current liabilities750 702 
Total current liabilities6,365 4,719 
Long-term debt, excluding current maturities (Note G)30,755 31,018 
Deferred credits and other liabilities
Deferred income taxes (Note M)6,349 5,451 
Other deferred credits603 748 
Total deferred credits and other liabilities6,952 6,199 
Commitments and contingencies (Note O)
Equity (Note H)
Preferred stock, $0.01 par value:
 authorized 100,000,000 shares; issued and outstanding 0 shares at December 31, 2025; issued and outstanding 20,000 shares at December 31, 2024
— — 
Common stock, $0.01 par value:
 authorized 1,200,000,000 shares; issued 655,909,018 shares and outstanding 629,707,691 shares at
 December 31, 2025; issued 609,713,834 shares and outstanding 583,110,633 shares at December 31, 2024
7 6 
Paid-in capital20,961 16,354 
Accumulated other comprehensive loss(27)(96)
Retained earnings2,373 1,579 
Treasury stock, at cost: 26,201,327 shares at December 31, 2025, and 26,603,201 shares at
 December 31, 2024
(829)(807)
Total ONEOK shareholders' equity22,485 17,036 
Noncontrolling interests in consolidated subsidiaries 84 5,097 
Total equity22,569 22,133 
Total liabilities and equity$66,641 $64,069 
See accompanying Notes to Consolidated Financial Statements.
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ONEOK, Inc. and Subsidiaries
CONSOLIDATED STATEMENTS OF CASH FLOWS
Years Ended December 31,
202520242023
(Millions of dollars)
Operating activities
Net income$3,462 $3,112 $2,659 
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization1,514 1,134 769 
Equity in net earnings from investments (Note N)(386)(439)(202)
Distributions received from unconsolidated affiliates397 390 202 
Deferred income taxes (Note M)957 889 829 
Gain on sale of business (Note B)— (227)— 
Medford settlement gain (Note A)— — (779)
Medford settlement proceeds (Note A)— — 502 
Other, net35 72 83 
Changes in assets and liabilities:
Accounts receivable(683)49 107 
Inventories, net of commodity imbalances(263)17 118 
Accounts payable671 114 (62)
Other assets and liabilities, net(105)(223)195 
Cash provided by operating activities5,599 4,888 4,421 
Investing activities
Capital expenditures (less allowance for equity funds used during construction)(3,152)(2,021)(1,595)
Cash paid for acquisitions, net of cash acquired(25)(5,829)(5,015)
Proceeds from the sale of business (Note B)— 1,200 — 
Purchases of and contributions to unconsolidated affiliates (Note N)(622)(111)(207)
Medford settlement proceeds (Note A)— — 328 
Other, net48 149 85 
Cash used in investing activities(3,751)(6,612)(6,404)
Financing activities
Dividends paid(2,583)(2,313)(1,839)
Short-term borrowings, net820 — — 
Issuance of long-term debt, net of discounts (Note G)2,989 7,094 5,298 
Debt financing costs(32)(67)(71)
Repurchase of common stock (Note H)(75)(159)— 
Delaware Basin JV Acquisition (Note B)(550)— — 
Extinguishment of long-term debt (Note G)(2,979)(2,003)(1,300)
Repurchase of EnLink's Series C Preferred Units— (365)— 
Other, net(93)(68)13 
Cash provided by (used in) financing activities(2,503)2,119 2,101 
Change in cash and cash equivalents(655)395 118 
Cash and cash equivalents at beginning of period733 338 220 
Cash and cash equivalents at end of period $78 $733 $338 
Supplemental cash flow information:
Cash paid for interest, net of amounts capitalized$1,732 $1,297 $653 
See accompanying Notes to Consolidated Financial Statements.
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ONEOK, Inc. and Subsidiaries
CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY
ONEOK Shareholders' Equity
Preferred StockCommon StockPaid-in CapitalAOCL*Retained EarningsTreasury StockNoncontrolling InterestsTotal Equity
(Millions of dollars)
January 1, 2023$— $5 $7,253 $(108)$50 $(706)$— $6,494 
Net income— — — — 2,659 — — 2,659 
Other comprehensive income— — — 75 — — — 75 
Preferred stock dividends - $55.00 per share
— — — — (1)— — (1)
Magellan Acquisition consideration (Note B)— 1 9,061 — — — — 9,062 
Common stock issued— — 9 — — 29 — 38 
Common stock dividends - $3.82 per share (Note H)
— — — — (1,839)— — (1,839)
Other, net— — (3)— (1)— — (4)
December 31, 2023— 6 16,320 (33)868 (677)— 16,484 
Net income— — — — 3,035 — 77 3,112 
Other comprehensive loss— — — (63)— — — (63)
Preferred stock dividends - $55.00 per share
——— —(1)— — (1)
Common stock issued— — 25 — — 42 — 67 
Common stock dividends - $3.96 per share (Note H)
— — — — (2,318)— — (2,318)
Repurchase of common stock (Note H)——— —— (172)— (172)
EnLink Controlling Interest Acquisition (Note B)——— — — — 5,076 5,076 
Distributions to noncontrolling interests(66)(66)
Contributions from noncontrolling interests——— — — — 3 3 
Other, net——9 — (5)— 7 11 
December 31, 2024— 6 16,354 (96)1,579 (807)5,097 22,133 
Net income— — — — 3,393 — 69 3,462 
Other comprehensive income— — — 69 — — — 69 
Preferred stock dividends - $13.75 per share
— — — — — — — — 
Common stock issued— — (9)— — 40 — 31 
Common stock dividends - $4.12 per share (Note H)
— — — — (2,596)— — (2,596)
Repurchase of common stock (Note H)— — — — — (62)— (62)
EnLink Acquisition (Note B)— 1 4,377 — — — (4,378)— 
Delaware Basin JV Acquisition (Note B)— — 185 — — — (678)(493)
Distributions to noncontrolling interests— — — — — — (47)(47)
Contributions from noncontrolling interests— — — — — — 19 19 
Other, net— — 54 — (3)— 2 53 
December 31, 2025$— $7 $20,961 $(27)$2,373 $(829)$84 $22,569 
*Accumulated other comprehensive loss

See accompanying Notes to Consolidated Financial Statements.

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ONEOK, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

A.    SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Organization and Nature of Operations - We are a corporation incorporated under the laws of the state of Oklahoma.

Our Natural Gas Gathering and Processing segment provides midstream services to producers in the Rocky Mountain region, the Mid-Continent region and the Permian Basin. 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.

In our Natural Gas Liquids segment, NGLs are extracted at our own and third-party natural gas processing plants and 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.

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 (Louisiana Gulf Coast) 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 support capital projects and low-cost expansions that position us well to provide additional services to our customers when needed.

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. 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. Throughout our distribution system, terminals play a key role in facilitating product movements and marketing by providing storage, distribution, blending and other ancillary services. 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.

Basis of Presentation - Our accompanying Consolidated Financial Statements have been prepared pursuant to the rules and regulations of the SEC. These statements have been prepared in accordance with GAAP.

Consolidation - Our Consolidated Financial Statements include our accounts and the accounts of our subsidiaries over which we have control or are the primary beneficiary. Third-party ownership interests in our controlled subsidiaries are presented as noncontrolling interests. All intercompany balances and transactions have been eliminated in consolidation.

We account for investments where we control the investment using the consolidation method of accounting. Under this method, we consolidate all assets and liabilities of an investment on our Consolidated Balance Sheets and record noncontrolling interests for the portion of the investment we do not own. We include all of the investment’s results of operations on our Consolidated Statements of Income and record income attributable to noncontrolling interests for the portion of the investment that we do not own. As of December 31, 2025, noncontrolling interests in our Consolidated Balance Sheets related to Ascension and MBTC Pipeline. As a result of the Delaware Basin JV Acquisition and the EnLink Acquisition, these entities are now wholly owned subsidiaries and are no longer recorded as noncontrolling interests in our Consolidated Balance Sheets as of December 31, 2025. As of December 31, 2024, noncontrolling interests in our Consolidated Balance Sheets were
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composed of the approximately 57% of outstanding EnLink Units we did not own, Series B Preferred Units and the partially owned consolidated subsidiaries of EnLink.

See Note H for disclosures of our noncontrolling interests.

Investments in unconsolidated affiliates are accounted for using the equity method if we have the ability to exercise significant influence over operating and financial policies of our investee. Under this method, an investment is carried at its acquisition cost and adjusted each period for contributions made, distributions received and our share of the investee’s comprehensive income. The difference between the carrying value of an investment and our share of the investment’s underlying equity in net assets is referred to as a basis difference. Basis differences related to depreciable or amortizable assets are amortized through equity in net earnings from investments. The premium or excess cost over underlying fair value of net assets is referred to as equity-method goodwill. The portion of the basis difference that is attributable to our equity-method goodwill is not amortized. Impairment of equity investments is recorded when the impairments are other than temporary. These amounts are recorded as investments in unconsolidated affiliates on our accompanying Consolidated Balance Sheets.

See Note N for disclosures of our unconsolidated affiliates.

Distributions paid to us from our unconsolidated affiliates are classified as operating activities on our Consolidated Statements of Cash Flows until the cumulative distributions exceed our proportionate share of income from the unconsolidated affiliate since the date of our initial investment. Cumulative distributions paid to us from the unconsolidated affiliate that exceed our cumulative proportionate share of income from the unconsolidated affiliate in each period represents a return of investment and is classified as an investing activity on our Consolidated Statements of Cash Flows.

Variable Interest Entities (VIEs) - We evaluate all legal entities in which we hold an ownership interest to determine if the entity is a VIE. Variable interests are ownership interests in an entity that change with changes in the fair value of the VIE’s assets. When we conclude that we hold an interest in a VIE, we must determine if we are the entity’s primary beneficiary. A primary beneficiary is deemed to have the power to direct the activities of the VIE that most significantly impact the VIE’s economic performance. We consolidate any VIE when we determine that we are the primary beneficiary.

Significant judgment is exercised in determining that a legal entity is a VIE and in evaluating our interest in a VIE. We use primarily a qualitative analysis to determine if an entity is a VIE. We evaluate our interests in a VIE to determine whether we are the primary beneficiary. We continually monitor our interests in legal entities for changes in the design or activities of an entity and changes in our interests, including our status as the primary beneficiary to determine if the changes require us to revise our previous conclusions.

See Note I for our VIE disclosures.

Use of Estimates - The preparation of our Consolidated Financial Statements and related disclosures in accordance with GAAP requires us to make estimates and assumptions with respect to values or conditions that cannot be known with certainty that affect the reported amounts on our Consolidated Financial Statements. Items that may be estimated include, but are not limited to, the economic useful life of assets, fair value of assets, liabilities, derivative instruments and equity-method investments, obligations under employee benefit plans, allowance for credit losses, expenses for services received but for which no invoice has been received, provision for income taxes, including any deferred tax valuation allowances, the results of litigation, environmental remediation and various other recorded or disclosed amounts. In addition, a portion of our revenues and cost of sales and fuel are recorded based on current month prices and estimated volumes. The estimates are reversed in the following month when we record actual volumes.

We evaluate our estimates on an ongoing basis using historical experience, consultation with experts and other methods we consider reasonable based on the particular circumstances. Nevertheless, actual results may differ significantly from the estimates. Any effects on our financial position or results of operations from revisions to these estimates are recorded in the period when the facts that give rise to the revision become known.

Fair Value Measurements - For our fair value measurements, we utilize market prices, third-party pricing services, present value methods and standard option valuation models to determine the price we would receive from the sale of an asset or the transfer of a liability in an orderly transaction at the measurement date. We measure the fair value of a group of financial assets and liabilities consistent with how a market participant would price the net risk exposure at the measurement date.

Most of the contracts in our derivative portfolio are executed in liquid markets where price transparency exists. Our financial commodity derivatives are primarily settled through a NYMEX or Intercontinental Exchange clearing broker account with daily
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margin requirements. We validate our valuation inputs with third-party information and settlement prices from other sources, where available.

We compute the fair value of our derivative portfolio by discounting the projected future cash flows from our derivative assets and liabilities to present value using interest-rate yields to calculate present-value discount factors derived from the implied forward SOFR yield curve. The fair value of our forward-starting interest-rate swaps is determined using financial models that incorporate the implied forward SOFR yield curve for the same period as the future interest-rate swap settlements. We consider current market data in evaluating counterparties’, as well as our own, nonperformance risk, net of collateral, by using counterparty-specific bond yields. Although we use our best estimates to determine the fair value of the derivative contracts we have executed, the ultimate market prices realized could differ materially from our estimates.

Fair Value Hierarchy - At each balance sheet date, we utilize a fair value hierarchy to classify fair value amounts recognized or disclosed in our financial statements based on the observability of inputs used to estimate such fair value. The levels of the hierarchy are described below:
•Level 1 - fair value measurements are based on unadjusted quoted prices for identical securities in active markets. These balances are composed predominantly of exchange-traded derivative contracts for natural gas, Refined Products and crude oil.
•Level 2 - fair value measurements are based on significant observable pricing inputs, including quoted prices for similar assets and liabilities in active markets and inputs from third-party pricing services supported with corroborative evidence. These balances are composed of exchange cleared and over-the-counter derivatives to hedge natural gas, NGLs, Refined Products and crude oil price risk and over-the-counter interest-rate derivatives.
•Level 3 - fair value measurements are based on inputs that may include one or more unobservable inputs.

Determining the appropriate classification of our fair value measurements within the fair value hierarchy requires management’s judgment regarding the degree to which market data is observable or corroborated by observable market data. We categorize derivatives based on the lowest level input that is significant to the fair value measurement in its entirety.

See Note C for our fair value measurements disclosures.

Cash and Cash Equivalents - Cash equivalents consist of highly liquid investments, which are readily convertible into cash and have original maturities of three months or less.

Revenue Recognition - Revenues are recognized when control of the promised goods or services is transferred to our customers in an amount that reflects the consideration we expect to be entitled to receive in exchange for those goods or services. Our payment terms vary by customer and contract type, including requiring payment before products or services are delivered to certain customers. However, the term between customer prepayments, completion of our performance obligations, invoicing and receipt of payment due is generally not significant.

Performance Obligations and Revenue Sources - Revenue sources are disaggregated in Note R and are derived from commodity sales and services revenues, as described below:

Commodity Sales (all segments) - We contract to deliver residue natural gas, unfractionated NGLs and/or Purity NGLs, Refined Products, condensate and crude oil to customers at a specified delivery point. Our sales agreements may be daily or longer-term contracts for a specified volume. We consider the sale and delivery of each unit of a commodity an individual performance obligation as the customer is expected to control, accept and benefit from each unit individually. We record revenue when the commodity is delivered to the customer as this represents the point in time when control of the product is transferred to the customer. Revenue is recorded based on the contracted selling price, which is generally index-based and settled daily or monthly. Occasionally, we sell unfractionated NGLs to customers at an index-based price less third-party fractionation costs. These costs are included as a reduction to commodity sales revenue.

Services

Gathering only contracts (Natural Gas Gathering and Processing segment) - Under this type of contract, we charge fees for providing midstream services, which include gathering and treating our customers’ natural gas. Our performance obligation begins with delivery of raw natural gas to our system. This service is treated as one performance obligation that is satisfied over time. We use the output method based on delivery of product to our system as the measure of progress, as our services are performed simultaneously.

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Fee with POP contracts with producer take-in-kind rights (Natural Gas Gathering and Processing segment) - Under this type of contract, we do not control the stream of unprocessed natural gas that we receive at the wellhead due to the producer’s take-in-kind rights. We purchase commodities that the producer does not take-in-kind and charge fees for providing midstream services, which include gathering, treating, compressing and processing our customers’ natural gas. After performing these services, we return certain commodities to the producer, sell any remaining commodities and remit a portion of the commodity sales proceeds to the producer less our contractual fees. Our performance obligation begins with delivery of raw natural gas to our system. This service is treated as one performance obligation that is satisfied over time. We use the output method based on delivery of product to our system as the measure of progress, as our services are performed simultaneously.

Transportation, exchange and terminal service contracts (Natural Gas Liquids and Refined Products and Crude segments) - Under this type of contract, we charge fees for providing midstream services, which may include a bundled combination of one or more of the following services: gathering, transporting, terminalling, fractionation or other ancillary services. Our performance obligation begins with delivery of product to our system. These services represent a series of distinct services that are treated as one performance obligation that is satisfied over time. We use the output method based on delivery of product to our system as the measure of progress, as our services are performed simultaneously. For transportation services under a tariff on our transportation pipelines, fees are recorded when our delivery obligation is complete. We have certain contracts that require counterparties to ship a minimum volume over an agreed-upon time period, which are contracted as minimum dollar or volume commitments. Revenue pursuant to these take-or-pay contracts is initially deferred and subsequently recognized when the customers utilize their committed volumes or when the likelihood of meeting the minimum volume commitment becomes remote.

Storage contracts (Natural Gas Liquids, Refined Products and Crude and Natural Gas Pipelines segments) - We reserve a stated storage capacity and inject/withdraw/store commodities for our customers. As these services represent a stand-ready obligation provided on a daily basis over the life of the agreement, the fixed capacity reservation fees are allocated and evenly recognized in revenue over the contract term. Capacity reservation fees that vary based on a stated or implied economic index and correspond with the costs to provide our services are recognized in revenue as invoiced to our customers. We use the output method based on the passage of time to measure satisfaction of the performance obligation associated with our daily stand-ready services. Other fees are recognized in revenue as those services are provided and are dependent on the volume moved, which is at our customers’ discretion.

Firm service transportation contracts (Natural Gas Pipelines segment) - We reserve a stated transportation capacity and transport commodities for our customer. The capacity reservation and transportation services are considered a bundled service, as we integrate them into one stand-ready obligation provided on a daily basis over the life of the agreement and satisfied over time. Fixed capacity reservation fees are allocated and evenly recognized in revenue. Capacity reservation fees that vary based on a stated or implied economic index and correspond with the costs to provide our services are recognized in revenue based on a daily effective fee rate. If the capacity reservation fees vary solely as a contract feature, contract assets or liabilities are recorded for the difference between the amount recorded in revenue and the amount billed to the customer. Transportation fees are recognized in revenue as those services are provided and are dependent on the volume transported by our customer, which is at our customers’ discretion. We use the output method based on the passage of time to measure satisfaction of the performance obligation associated with our daily stand-ready services.

Interruptible transportation contracts (Natural Gas Pipelines segment) - We agree to transport natural gas on our pipelines between the customers’ specified nominated-receipt and delivery points if capacity is available after satisfying firm transportation service obligations. The transaction price is based on the transportation fees times the volumes transported. We use the output method based on delivery of product to the customer to measure satisfaction of the performance obligation. The total consideration for delivered volumes is recorded in revenue at the time of delivery, when the customer obtains control.

Many of the contract types described above contain additional fees or charges payable by customers for nonperformance (e.g., minimum volume commitments or product specifications), which are considered to be variable consideration. These fees and charges are not recorded until it is probable that a significant reversal of the associated revenue will not occur.

Receivables from Customers - Substantially all of the balances in accounts receivable on our Consolidated Balance Sheets at December 31, 2025, and December 31, 2024, are related to customer receivables.

See Note Q for our revenue disclosures.

Contract Assets and Contract Liabilities - Contract assets and contract liabilities are recorded when the amount of revenue recognized from a contract with a customer differs from the amount billed to the customer and recorded in accounts receivable. Our contract asset balances at the beginning and end of the period primarily related to our firm service transportation contracts
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with tiered rates, which are not material. Our contract liabilities at the beginning and end of the period primarily related to deferred revenue on Refined Products and crude oil transportation contracts, NGL storage contracts and contributions in aid of construction received from customers, which were not material.

Cost of Sales and Fuel - Cost of sales and fuel primarily includes (i) the cost of purchased commodities, including natural gas, NGLs, Refined Products, condensate and crude oil, (ii) fees incurred for third-party transportation, fractionation and storage of commodities, (iii) fuel and power costs incurred to operate our own facilities that gather, process, transport and store commodities, (iv) product gains and losses and (v) an offset from the contractual fees deducted from the cost of purchased commodities under the contract types below:

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

Purchase with fee (Natural Gas Liquids and Refined Products and Crude segments) - Under this type of contract, we purchase product at an index price and charge fees for providing midstream services, which may include a bundled combination of gathering, transporting and/or fractionation.

Operations and Maintenance - Operations and maintenance primarily includes (i) payroll and benefit costs, (ii) third-party costs for operations, maintenance and integrity management, regulatory compliance and environmental and safety, and (iii) other business-related service costs.

Accounts Receivable - Accounts receivable represent valid claims against nonaffiliated customers for products sold or services rendered. We present accounts receivable net of an allowance for credit losses to reflect the net amount expected to be collected. We assess the creditworthiness of our counterparties on an ongoing basis and require security, including prepayments and other forms of collateral, when appropriate. Outstanding customer receivables are reviewed regularly for possible nonpayment indicators, and allowances for credit losses are recorded based upon management’s estimate of collectability, current conditions and supportable forecasts at each balance sheet date. At December 31, 2025, our allowance for credit losses was not material.

Inventory - The values of current NGLs, natural gas, Refined Products and crude oil in storage are determined using the lower of weighted-average cost or net realizable value. Materials and supplies are valued at average cost.

Commodity Imbalances - In our Natural Gas Gathering and Processing, Natural Gas Liquids and Natural Gas Pipelines segments, commodity imbalances represent amounts payable or receivable for NGL exchange contracts and natural gas pipeline imbalances and are valued at market prices. Under the majority of our NGL exchange agreements, we physically receive volumes of unfractionated NGLs, including the risk of loss and legal title to such volumes, from the exchange counterparty. In turn, we deliver Purity NGLs back to the customer and charge gathering, transportation and fractionation fees. To the extent that the volumes we receive under such agreements differ from those we deliver, we record a net exchange receivable or payable position with the counterparties. These net exchange receivables and payables are generally settled with movements of Purity NGLs rather than with cash. Natural gas pipeline imbalances are settled in cash or in-kind, subject to the terms of the pipelines’ tariffs or by agreement.

In our Refined Products and Crude segment, commodity imbalances represent differences in product volumes in our pipeline systems and terminals, compared to the volumes of our customers’ inventories, as we do not take legal title to the majority of the products on our pipeline systems and terminals. To the extent the product volumes differ from the volumes of our customers’ book inventories, we record adjustments to our product inventories. When product shortages cause a net short inventory position in a product, a liability is recorded based on market prices. Refined Products and crude oil imbalances are generally settled in-kind through product purchases and sales.

Derivatives and Risk Management - We utilize derivatives to reduce our market-risk exposure to commodity price and interest-rate fluctuations and to achieve more predictable cash flows. We record all derivative instruments at fair value, with the exception of normal purchases and normal sales transactions that are expected to result in physical delivery. Commodity price and interest-rate volatility may have a significant impact on the fair value of derivative instruments as of a given date. The accounting for changes in the fair value of a derivative instrument depends on whether it has been designated and qualifies as part of a hedging relationship and, if so, the reason for holding it.
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The table below summarizes the various ways in which we account for our derivative instruments and the impact on our Consolidated Financial Statements:
  Recognition and Measurement
Accounting TreatmentBalance Sheet Income Statement
Normal purchases and
normal sales		-Fair value not recorded-Change in fair value not recognized in earnings
Mark-to-market-Recorded at fair value-Change in fair value recognized in earnings
Cash flow hedge-The gain or loss on the
derivative instrument is reported initially as a
component of accumulated other
comprehensive income (loss)		-The gain or loss on the derivative instrument is reclassified out of accumulated other comprehensive income (loss) into earnings when the forecasted transaction affects earnings
Fair value hedge-Recorded at fair value-The gain or loss on the derivative instrument is
recognized in earnings
 -Change in fair value of the hedged item is
recorded as an adjustment to book value		-Change in fair value of the hedged item is
recognized in earnings

To reduce our exposure to fluctuations in natural gas, NGLs, Refined Products, condensate and crude oil prices, we periodically enter into futures, forward purchases and sales, options or swap transactions in order to hedge anticipated purchases and sales of natural gas, NGLs, Refined Products, condensate and crude oil. Treasury locks and interest-rate swaps are used from time to time to manage interest-rate risk. Under certain conditions, we designate our derivative instruments as a hedge of exposure to changes in fair values or cash flows. We formally document all relationships between hedging instruments and hedged items, as well as risk-management objectives and strategies for undertaking various hedge transactions, and methods for assessing and testing hedge effectiveness. We specifically identify the forecasted transaction that has been designated as the hedged item in a cash flow hedge relationship. We assess hedging relationships at the inception of the hedge, and periodically thereafter, to determine whether the hedging relationship is, and is expected to remain, highly effective. We also document our normal purchases and normal sales transactions that we expect to result in physical delivery and that we elect to exempt from derivative accounting treatment.

The realized revenues and purchase costs of our derivative instruments not considered held for trading purposes and derivatives that qualify as normal purchases or normal sales that are expected to result in physical delivery are reported on a gross basis.

Cash flows from futures, forwards, options and swaps that are accounted for as hedges are included in the same category as the cash flows from the related hedged items in our Consolidated Statements of Cash Flows.

See Notes C and D for disclosures of our fair value measurements and risk-management and hedging activities, respectively.

Property, Plant and Equipment - Our properties are stated at cost, including AFUDC and capitalized interest. In some cases, the cost of regulated property retired or sold, plus removal costs, less salvage, is charged to accumulated depreciation. Gains and losses from sales or transfers of nonregulated properties or an entire operating unit or system of our regulated properties are recognized in income. Maintenance and repairs are charged directly to expense.

The interest portion of AFUDC and capitalized interest represent the cost of borrowed funds used to finance construction activities for regulated and nonregulated projects, respectively. We capitalize interest costs during the construction or upgrade of qualifying assets. These costs are recorded as a reduction to interest expense. The equity portion of AFUDC represents the capitalization of the estimated average cost of equity used during the construction of major projects and is recorded in the cost of our regulated properties and as a credit to the allowance for equity funds used during construction.

Our properties are depreciated using the straight-line method over their estimated useful lives. Generally, we estimate the useful lives of individual assets or apply depreciation rates to functional groups of property having similar economic lives. We periodically conduct depreciation studies to assess the economic lives of our assets. For our regulated assets, these depreciation studies are completed as a part of our rate proceedings or tariff filings, and the changes in economic lives, if applicable, are implemented prospectively as of the approved effective date. For our nonregulated assets, if it is determined that the estimated economic life changes, the changes are made prospectively. Changes in the estimated economic lives of our property, plant and equipment could have a material effect on our financial position or results of operations.

Property, plant and equipment on our Consolidated Balance Sheets includes construction work in process for capital projects that have not yet been placed in service and therefore are not being depreciated. Assets are transferred out of construction work in process when they are substantially complete and ready for their intended use.

See Note E for our property, plant and equipment disclosures.
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Impairment of Goodwill and Long-Lived Assets, Including Intangible Assets and Equity Method Investments - We assess our goodwill for impairment at least annually as of July 1, unless events or changes in circumstances indicate an impairment may have occurred before that time. Our qualitative goodwill impairment analysis performed as of July 1, 2025, did not result in an impairment charge nor did our analysis reflect any reporting units at risk, and subsequent to that date, no event has occurred indicating that the implied fair value of our reporting units are less than the carrying value of their net assets.

Goodwill - As part of our goodwill impairment test, we assess qualitative factors (including macroeconomic conditions, industry and market considerations, cost factors and overall financial performance) to determine whether it was more likely than not that the fair value of our reporting units are less than their carrying amount. If further testing is necessary, or a quantitative test is elected, we perform a Step 1 analysis. In a Step 1 analysis, an assessment is made by comparing the fair value of a reporting unit with its carrying amount, including goodwill. If the carrying value of a reporting unit exceeds its fair value, an impairment loss is recognized in an amount equal to that excess, limited to the total amount of goodwill allocated to that reporting unit.

To estimate the fair value of our reporting units, we use two generally accepted valuation approaches, an income approach and a market approach, using assumptions consistent with a market participant’s perspective. Under the income approach, we use anticipated cash flows over a period of years plus a terminal value and discount these amounts to their present value using appropriate discount rates. The forecasted cash flows are based on probability weighted-average possible future cash flows for a reporting unit over a period of years. Under the market approach, we apply EBITDA multiples to forecasted EBITDA. The multiples used are consistent with recent market transactions.

Long-lived assets - We assess our long-lived asset groups for impairment whenever events or changes in circumstances indicate that an asset group’s carrying amount may not be recoverable. An impairment is indicated if the carrying amount of a long-lived asset group exceeds the sum of the undiscounted future cash flows expected to result from the use and eventual disposition of the asset group. If an impairment is indicated, we record an impairment loss equal to the difference between the carrying value and the fair value of the long-lived asset group.

Investments in unconsolidated affiliates - The impairment test for equity-method investments considers whether the fair value of the equity investment as a whole, not the underlying net assets, has declined and whether that decline is other than temporary. Therefore, we periodically evaluate the amount at which we carry our equity-method investments to determine whether current events or circumstances warrant adjustments to our carrying values.

See Notes E, F and N for our disclosures related to long-lived assets, goodwill and intangible assets and investments in unconsolidated affiliates, respectively.

Leases - We lease certain buildings, warehouses, office space, compression, land and equipment, including pipeline equipment, pipeline capacity, rail cars and information technology equipment. Our office space lease arrangements typically include variable lease cost related to utility expenses, which are determined based on our pro-rata share of building expenses each month and are expensed as incurred. Our lease payments are generally straight-line and the exercise of lease renewal options, which vary in term, is at our sole discretion. We include renewal periods in a lease term if we are reasonably certain to exercise available renewal options. Our lease agreements do not include any residual value guarantees or material restrictive covenants. We apply the short-term policy election, which allows us to exclude from recognition leases with an initial term of 12 months or less. Our weighted-average discount rates represent the rate implicit in the lease or our incremental borrowing rate for a term equal to the remaining term of the lease. Our finance lease assets and liabilities are not material.

Our lessor arrangements primarily include capacity, storage and service contracts and are not material. We have made an accounting policy election for both our lessee and lessor arrangements to combine lease and non-lease components. This election is applied to all of our lease arrangements as our non-lease components do not result in significant timing differences in the recognition of rental expenses or income.

Regulation - Depending on the specific service provided, our natural gas transmission pipelines, NGL, Refined Products and crude oil pipelines and certain natural gas storage facilities are subject to rate regulation and/or accounting requirements by one or more of the FERC, Oklahoma Corporation Commission, Kansas Corporation Commission, Louisiana Public Service Commission, Railroad Commission of Texas, Wyoming Public Service Commission and Colorado Public Utilities Commission. Accordingly, portions of our Natural Gas Liquids and Natural Gas Pipelines segments follow the accounting and reporting guidance for regulated operations as defined pursuant to Financial Accounting Standards Board’s (FASB) Accounting Standards Codification 980, Regulated Operations. During the rate-making process for certain of our assets, regulatory authorities set the framework for what we can charge customers for our services and establish the manner that our costs are accounted for, including allowing us to defer recognition of certain costs and permitting recovery of the amounts through rates
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over time as opposed to expensing such costs as incurred. Certain examples of types of regulatory guidance include costs for fuel and losses, acquisition costs, contributions in aid of construction, charges for depreciation, and gains or losses on disposition of assets. This allows us to stabilize rates over time rather than passing such costs on to the customer for immediate recovery. Actions by regulatory authorities could have an effect on the amounts we may charge our customers. Any difference in the amount recoverable and the amount deferred is recorded as income or expense at the time of the regulatory action. A write-off of regulatory assets and costs not recovered may be required if all or a portion of the regulated operations have rates that are no longer (i) established by independent, third-party regulators and (ii) set at levels that will recover our costs when considering the demand and competition for our services.

Retirement and Other Postretirement Employee Benefits - 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 sponsor health and welfare plans that provide postretirement medical and life insurance benefits to certain legacy ONEOK employees hired prior to 2017 and certain legacy Magellan employees who retire after a specified age with at least five years of service and satisfy certain other conditions. The expense and liability related to these plans is calculated using statistical and other factors that attempt to anticipate future events. These factors include assumptions about the discount rate, expected return on plan assets, rate of future compensation increases, interest credit rating, mortality and employment length. In determining the projected benefit obligations and costs, assumptions can change from period to period and may result in changes in the costs and liabilities we recognize.

See Note L for our retirement and other postretirement employee benefits disclosures.

Income Taxes - Deferred income taxes are provided for the difference between the financial statement and income tax basis of assets and liabilities and carryforward items based on income tax laws and rates existing at the time the temporary differences are expected to reverse. Generally, the effect of a change in tax rates on deferred tax assets and liabilities is recognized in income in the period that includes the enactment date of the rate change.

We utilize a more-likely-than-not recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position that is taken or expected to be taken in a tax return. We reflect penalties and interest as part of income tax expense as they become applicable for tax provisions that do not meet the more-likely-than-not recognition threshold and measurement attribute. For all periods presented, we had no uncertain tax positions that required the establishment of a material reserve.

We utilize the “with-and-without” approach for intra-period tax allocation for purposes of allocating total tax expense (or benefit) for the year among the various financial statement components.

We file numerous consolidated and separate income tax returns with federal tax authorities of the United States along with the tax authorities of several states. EnLink Midstream Operating, LP and EnLink Partners are both in the process of federal review by the Internal Revenue Service for the calendar years ended December 31, 2019, and December 31, 2020, and statute waivers are in place for these years. At this time, we believe the audits will close without a material impact. No other ONEOK entity is under any United States federal audits or statute waivers at this time.

See Note M for our income tax disclosures.

Asset Retirement Obligations - Asset retirement obligations represent legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction, development and/or normal use of the asset. Certain of our gathering and processing and pipeline facilities are subject to agreements or regulations that give rise to our asset retirement obligations for removal or other disposition costs associated with retiring the assets in place upon the discontinued use of the assets. We recognize the fair value of a liability for an asset retirement obligation in the period when it is incurred if a reasonable estimate of the fair value can be made. We are not able to estimate reasonably the fair value of the asset retirement obligations for portions of our assets, primarily certain pipeline assets, because the settlement dates are indeterminable given our expected continued use of the assets with proper maintenance. We expect our pipeline assets, for which we are unable to estimate reasonably the fair value of the asset retirement obligation, will continue in operation as long as supply and demand for natural gas, NGLs, Refined Products and crude oil exist. Based on the widespread use of these products in the medical, transportation, synthetics and agriculture industries, as well as for residential and industrial customers and electric generation, we expect supply and demand to exist for the foreseeable future.

For assets in which we are able to make an estimate, the fair value of the liability is added to the carrying amount of the associated asset, and this additional carrying amount is depreciated over the life of the asset. The liability is accreted at the end
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of each period through charges to operating expense. If the obligation is settled for an amount other than the carrying amount of the liability, we will recognize a gain or loss on settlement. The depreciation and accretion expense are immaterial to our Consolidated Financial Statements.

Contingencies - Our accounting for contingencies covers a variety of business activities, including contingencies for legal and environmental exposures. We accrue these contingencies when our assessments indicate that it is probable that a liability has been incurred or an asset will not be recovered, and an amount can be estimated reasonably. We expense legal fees as incurred and base our legal liability estimates on currently available facts and our estimates of the ultimate outcome or resolution. Accruals for estimated losses from environmental remediation obligations generally are recognized no later than completion of a remediation feasibility study. Our expenditures for environmental evaluation, mitigation, remediation and compliance to date have not been material in relation to our financial position or results of operations, and our expenditures related to environmental matters did not have a material effect on earnings or cash flows during 2025, 2024 and 2023. Actual results may differ from our estimates resulting in an impact, positive or negative, on earnings.

See Note O for additional discussion of contingencies.

Share-Based Payments - We expense the fair value of share-based payments net of estimated forfeitures. We estimate forfeiture rates based on historical forfeitures under our share-based payment plans.

See Note K for our share-based payments disclosures.

Earnings per Common Share - Basic EPS is calculated based on the daily weighted-average number of shares of common stock outstanding during the period, vested restricted and performance units that have been deferred and share awards deferred under the compensation plan for non-employee directors. Diluted EPS is calculated based on the daily weighted-average number of shares of common stock outstanding during the period plus potentially dilutive components. The dilutive components are calculated based on the dilutive effect for each quarter. For fiscal-year periods, the dilutive components for each quarter are averaged to arrive at the fiscal year-to-date dilutive component.

See Note J for our EPS disclosures.

Segment Reporting - In accordance with the “Segment Reporting” Topic 280, our chief operating decision-maker has been identified as the chief executive officer, who reviews the financial performance of each of our four segments to make decisions about allocating resources and assessing our financial performance as a whole, on a regular basis. Adjusted EBITDA by segment is the single measure of profit and loss utilized in this evaluation by our chief executive officer and is provided through monthly and quarterly review packages. Forecasted and actual adjusted EBITDA is used in the evaluation and approval of capital projects. We believe this financial measure is useful because it and similar measures are used by many companies in our industry as a measurement of financial performance and are commonly employed by financial analysts and others to evaluate our financial performance and to compare financial performance among companies in our industry. Adjusted EBITDA for each segment is defined as net income adjusted for interest expense, depreciation and amortization, noncash impairment charges, income taxes, noncash compensation expense and certain other noncash items. Adjusted EBITDA from our unconsolidated affiliates is calculated consistently with the definition above and excludes items such as interest expense, depreciation and amortization, income taxes and other noncash items. Although the amounts related to our unconsolidated affiliates are included in the calculation of adjusted EBITDA, such inclusion should not be understood to imply that we have control over the operations and resulting revenues, expenses or cash flows of such unconsolidated affiliates. This calculation may not be comparable with similarly titled measures of other companies.

See Note R for our segments disclosures.

Medford Insurance Proceeds - In 2022, a fire occurred at our 210 MBbl/d Medford, Oklahoma, NGL fractionation facility. In the first quarter of 2023, we reached an agreement with our insurers to settle all claims for physical damage and business interruption related to the Medford incident. Under the terms of the settlement agreement, we agreed to resolve the claims for total insurance payments of $930 million, $100 million of which was received in 2022. The remaining $830 million was received in the first quarter of 2023. The proceeds serve as settlement for property damage, business interruption claims to the date of the settlement and as payment in lieu of future business interruption insurance claims. We applied the $830 million received to our outstanding insurance receivable at December 31, 2022, of $51 million, and recorded an operational gain for the remaining $779 million in other operating income, net, within the Consolidated Statement of Income for the year ended December 31, 2023. We classified proceeds received within the Consolidated Statement of Cash Flows based on our assessment of the nature of the loss (property and business interruption) included in the settlement.

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Recently Issued Accounting Standards Update - Changes to GAAP are established by the FASB in the form of Accounting Standards Update (ASUs) to the FASB Accounting Standards Codification. We consider the applicability and impact of all ASUs. ASUs not discussed herein were assessed and determined to be either not applicable or clarifications of ASUs previously issued. Except as discussed below, there have been no new accounting pronouncements that have become effective or have been issued that are of significance or potential significance to us.

In December 2023, the FASB issued ASU 2023-09, Income Taxes (Topic 740): Improvements to Income Tax Disclosures, which requires public entities, on an annual basis, to provide disclosure of specific disaggregated information about the reporting entity’s effective tax rate reconciliation as well as information on income taxes paid. ASU 2023-09 is effective for fiscal years beginning after December 15, 2024, with early adoption permitted. We adopted this standard in 2025 and updated our income tax disclosures retrospectively. See Note M.

In November 2024, the FASB issued ASU 2024-03, Income Statement - Reporting Comprehensive Income - Expense Disaggregation Disclosures (Subtopic 220-40), which requires public entities to provide disaggregated information for certain types of costs and expenses included in each income statement caption, such as inventory purchases, employee compensation, depreciation, intangible asset amortization and depletion. ASU 2024-03 is effective for fiscal years beginning after December 15, 2026, and interim periods beginning after December 15, 2027, with early adoption permitted. We are currently evaluating the impact of this standard on our disclosures.

In November 2025, the FASB issued ASU 2025-09, Derivatives and Hedging – Hedge Accounting Improvements (Topic 815), which is intended to enhance or clarify Topic 815 to better align hedge accounting with the economics of an entity’s risk management activities, allow hedging of groups of forecasted transactions and expand the types of hedge transactions that can be aggregated. Additionally, the guidance allows entities to designate a variable price component of a nonfinancial forecasted transaction, facilitate hedge accounting on variable-rate debt and provides clarification related to reference rate reform. ASU 2025-09 is effective for fiscal years beginning after December 15, 2026, with early adoption permitted. We elected to adopt this guidance beginning in the first quarter 2026. The adoption of this standard did not materially impact us.

B.     ACQUISITIONS AND DIVESTITURES

BridgeTex Additional Interest Acquisition - On July 22, 2025, we completed the BridgeTex Additional Interest Acquisition. Pursuant to the purchase agreement, we paid approximately $270 million in cash, which we funded with short-term borrowings. Following the completion of the transaction, we now have a 60% ownership interest in BridgeTex. Our investment in BridgeTex will continue to be accounted for using the equity method as we continue to have the ability to exercise significant influence over the operating and financial policies of BridgeTex, although we do not have the ability to exercise control.

Delaware Basin JV Acquisition - On May 28, 2025, we completed the Delaware Basin JV Acquisition for $941 million. Pursuant to the purchase agreement, we paid $550 million in cash, including post-closing adjustments, which we funded with short-term borrowings and issued approximately 4.9 million shares of ONEOK common stock to the seller with a fair value of $391 million as of the closing date. Following the completion of the transaction, it is now a wholly owned subsidiary.

As we controlled the Delaware Basin JV at December 31, 2024, prior to the Delaware Basin JV Acquisition, the change in our ownership interest was accounted for as an equity transaction, and no gain or loss was recognized in our Consolidated Statement of Income from the acquisition. The Delaware Basin JV Acquisition was a taxable exchange. The transaction resulted in a decrease to the carrying value of noncontrolling interests in consolidated subsidiaries at the acquisition date of $678 million and an increase to paid-in capital of $185 million, including deferred tax assets.

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 a result of the completion of the EnLink Acquisition, common units of EnLink are no longer publicly traded, and EnLink is now a wholly owned subsidiary.

As we controlled EnLink at December 31, 2024, prior to the EnLink Acquisition, the change in our ownership interest was accounted for as an equity transaction. The carrying value of the noncontrolling interests in consolidated subsidiaries at the acquisition date was $4.4 billion. The difference between the equity consideration and the carrying value of the noncontrolling interests in consolidated subsidiaries at the acquisition date was recognized as an adjustment to paid-in capital.

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Supplemental Cash Flow Information - Our noncash balance sheet activity related to the EnLink Acquisition is as follows (in millions):

Common stock$1 
Paid-in capital$4,377 
Noncontrolling interests in consolidated subsidiaries$(4,378)

EnLink Controlling Interest Acquisition - On October 15, 2024, we completed the EnLink Controlling Interest Acquisition, acquiring GIP’s interest in EnLink consisting of approximately 43% of the outstanding EnLink Units for $14.90 in cash per unit and 100% of the outstanding limited liability company interests in the managing member of EnLink for $300 million, for total cash consideration of $3.3 billion. Through our 100% ownership of the managing member of EnLink, we obtained control of EnLink. We used a portion of the proceeds from our September 2024 underwritten public offering of $7.0 billion senior unsecured notes to fund this acquisition. For additional information on our long-term debt, see Note G.

This acquisition meaningfully increased our scale and integrated value chain within the growing Permian Basin while expanding and extending our asset bases in the Mid-Continent, North Texas and Louisiana regions.

The EnLink Controlling Interest Acquisition was accounted for using the acquisition method of accounting for business combinations pursuant to Accounting Standards Codification 805, “Business Combinations,” which requires, among other things, assets acquired and liabilities assumed to be recorded at their fair value on the acquisition date. Determining the fair value of acquired assets and liabilities assumed required management to make estimates, assumptions and judgments, and in some cases, management also utilized third-party specialists to assist and advise on those estimates.

The following tables set forth the acquisition consideration and final purchase price allocation of assets acquired and liabilities assumed:
October 15, 2024
(Millions of dollars and units, except per unit data)
EnLink Units outstanding
43% of EnLink Units outstanding
200.3 
Cash consideration per EnLink unit$14.90
Cash consideration for EnLink Units$2,985 
100% of the outstanding liability company interests in the managing member of EnLink
300 
Total cash consideration$3,285 
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October 15, 2024
Assets acquired:(Millions of dollars)
Cash and cash equivalents$446 
Accounts receivables, net
551 
Inventories87 
Other current assets38 
Property, plant and equipment 11,447 
Investments in unconsolidated affiliates342 
Intangible assets 1,051 
Other assets
129 
Total assets acquired14,091 
Liabilities assumed:
Current maturities of long-term debt
758 
Accounts payable465 
Other current liabilities (a)
532 
Long-term debt, excluding current maturities4,577 
Deferred income taxes
1,988 
Other deferred credits and liabilities
90 
Total liabilities assumed8,410 
Noncontrolling interests
5,076 
Total identifiable net assets605 
Goodwill 2,680 
Total purchase price$3,285 
(a) - Included obligation to repay Series C Preferred Units. See Note H.

In 2025, there were no material changes to the preliminary purchase price allocation as disclosed in our 2024 Annual Report.

Property, plant and equipment:
Property, plant and equipment consisted primarily of pipeline and rights of way, pipeline-related equipment and processing plant and fractionators and will be depreciated on a straight-line basis over the estimated useful lives of the assets.

Intangible assets:
Net identifiable intangible assets related to customer relationships that will be amortized over the period of expected benefit.

Long-term debt, excluding current maturities:
We utilized publicly traded prices to estimate the fair value. The debt comprised senior unsecured obligations with varying maturities and interest rates as outlined in Note G. Recognizing the debt at its acquisition date fair value resulted in a discount from the notional value. The discount was immaterial and will be amortized into interest expense over the remaining life of the debt.

Deferred income taxes:
The EnLink Controlling Interest Acquisition resulted in a difference between the carrying value of the underlying assets acquired and the carryover tax basis of assets, which resulted in a deferred tax liability recorded as part of the purchase price allocation.

Goodwill:
We established deferred income tax liabilities resulting from carryover tax basis, which increased goodwill. The remainder of the goodwill balance primarily represented commercial synergies. Goodwill will not be deductible for tax purposes. For additional information on goodwill, see Note F.

Noncontrolling interest:
Represented the approximately 57% of EnLink Units not acquired in the EnLink Controlling Interest Acquisition, valued at the acquisition date closing price of EnLink, the Series B Preferred Units and partially owned consolidated subsidiaries.




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Results of operations:
The results of operations attributable to the EnLink Controlling Interest Acquisition have been included in our Consolidated Financial Statements since the date of acquisition. Revenue and income before income taxes attributable to the net assets acquired for the period October 15, 2024, through December 31, 2024, were $1.5 billion and $173 million, respectively.

Medallion Acquisition - On October 31, 2024, we completed the Medallion Acquisition with GIP, acquiring all of the equity interests in Medallion for total cash consideration of $2.6 billion, inclusive of the purchase of additional interests in a Medallion joint venture owned by a separate third party. We used a portion of the proceeds from our September 2024 underwritten public offering of $7.0 billion senior unsecured notes to fund this acquisition. For additional information on our long-term debt, see Note G.

This acquisition expanded our midstream services for crude oil and condensate in West Texas, specifically the Midland Basin. The assets of Medallion included crude oil gathering and transportation pipelines and crude oil storage facilities. Medallion’s assets and operations are reported in our Refined Products and Crude segment.

The Medallion Acquisition was accounted for using the acquisition method of accounting for business combinations pursuant to Accounting Standards Codification 805, “Business Combinations,” which requires, among other things, assets acquired and liabilities assumed to be recorded at their fair value on the acquisition date. Determining the fair value of acquired assets and liabilities assumed required management to make estimates, assumptions and judgments, and in some cases, management also utilized third-party specialists to assist and advise on those estimates.

The following table sets forth the final purchase price allocation of assets acquired and liabilities assumed:

October 31, 2024
Assets acquired:(Millions of dollars)
Cash and cash equivalents$36 
Accounts receivables, net
114 
Other current assets22 
Property, plant and equipment 1,596 
Intangible assets 730 
Other assets
2 
Total assets acquired2,500 
Liabilities assumed:
Accounts payable103 
Other current liabilities3 
Other deferred credits and liabilities
40 
Total liabilities assumed146 
Total identifiable net assets2,354 
Goodwill 263 
Total purchase price$2,617 

In 2025, there were no material changes to the preliminary purchase price allocation as disclosed in our 2024 Annual Report.

Property, plant and equipment:
Property, plant and equipment consisted primarily of pipeline and pump station equipment and will be depreciated on a straight-line basis over the estimated useful lives of the assets.

Intangible assets:
Net identifiable intangible assets related to customer relationships that will be amortized over the period of expected benefit.

Goodwill:
Goodwill represented commercial synergies and is expected to be fully deductible for tax purposes. For additional information on goodwill, see Note F.
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Results of operations:
The results of operations attributable to the Medallion Acquisition have been included in our Consolidated Financial Statements since the date of acquisition. Revenue and income before income taxes attributable to the net assets acquired for the period November 1, 2024, through December 31, 2024, were $256 million and $43 million, respectively.

Gulf Coast NGL Pipelines Acquisition - On June 17, 2024, we completed the acquisition of a system of NGL pipelines from Easton Energy, a Houston-based midstream company, for approximately $280 million. This acquisition in our Natural Gas Liquids segment included approximately 450 miles of liquids products pipelines located in the strategic Gulf Coast market centers for NGLs, Refined Products and crude oil.

Interstate Natural Gas Pipeline Divestiture - On December 31, 2024, we sold three of our wholly owned interstate natural gas pipeline systems to DT Midstream, Inc. for total cash consideration of $1.2 billion and recognized a gain of $227 million in other operating income, net, within the Consolidated Statement of Income for the year ended December 31, 2024. This transaction aligned and enhanced our capital allocation priorities within our integrated value chain. These pipeline systems were previously reported in our Natural Gas Pipelines segment.

Magellan Acquisition - On September 25, 2023, we completed the Magellan Acquisition. This acquisition strategically diversified our complementary asset base and allows for significant expected synergies as a combined entity. Each common unit of Magellan was exchanged for a fixed ratio of 0.667 shares of ONEOK common stock and $25.00 of cash, for a total consideration of $14.1 billion. A total of approximately 135 million shares of common stock were issued, with a fair value of approximately $9.0 billion as of the closing date of the Magellan Acquisition. We funded the cash portion of this acquisition with an underwritten public offering of $5.25 billion senior unsecured notes. For additional information on our long-term debt, please see Note G.

The Magellan Acquisition was accounted for using the acquisition method of accounting for business combinations pursuant to Accounting Standards Codification 805, “Business Combinations,” which requires, among other things, assets acquired and liabilities assumed to be recorded at their fair value on the acquisition date. Determining the fair value of acquired assets and liabilities assumed required management to make estimates, assumptions and judgments, and in some cases, management also utilized third-party specialists to assist and advise on those estimates.

The following tables set forth the acquisition consideration and final purchase price allocation of assets acquired and liabilities assumed:
September 25, 2023
(Millions of dollars and shares/units, except per share/unit data)
Magellan public common units outstanding
202.1 
Cash consideration per Magellan unit
$25.00
Cash consideration$5,052 
Magellan public common units outstanding
202.1 
ONEOK exchange ratio per Magellan unit
0.667 
Shares of ONEOK common stock issued
134.8 
ONEOK common stock closing price on September 25, 2023$66.54
Fair value of common stock issued
$8,969 
Fair value of Magellan replacement equity awards
93 
Equity consideration
$9,062 
Total consideration
$14,114 

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September 25, 2023
Assets acquired:(Millions of dollars)
Cash and cash equivalents$37 
Accounts receivables, net
333 
Inventories352 
Other current assets140 
Property, plant and equipment 11,644 
Investments in unconsolidated affiliates922 
Intangible assets 1,124 
Other assets
121 
Total assets acquired14,673 
Liabilities assumed:
Accounts payable213 
Other current liabilities 721 
Long-term debt, excluding current maturities4,013 
Other deferred credits and liabilities
201 
Total liabilities assumed5,148 
Total identifiable net assets9,525 
Goodwill 4,589 
Total purchase price$14,114 

Intangible assets:
The preliminary value of net identifiable intangible assets related to customer relationships that will be amortized over the period of expected benefit.

Goodwill:
Goodwill primarily represented expected tax benefits from future depreciation and amortization of acquired assets and commercial synergies, and is expected to be fully deductible for tax purposes. For additional information on goodwill, see Note F.

Transaction Costs - The following table sets forth the impact of acquisition-related transaction costs in our Consolidated Statements of Income as of the periods indicated:
Years Ended
December 31,
 2025 (a)2024 (b)2023 (c)
 
(Millions of dollars)
Transaction costs
$81 $73 $158 
Interest expense
— 23 21 
Total
$81 $96 $179 
(a) - Primarily nonrecurring costs including $65 million related primarily to advisory fees and severance and $16 million of noncash compensation expense related to the settlement of share-based awards for certain EnLink employees associated with the EnLink Acquisition.
(b) - Primarily nonrecurring costs related to advisory fees and bridge commitment fees associated with the EnLink Controlling Interest Acquisition and Medallion Acquisition.
(c) - Primarily nonrecurring costs related to advisory fees, severance and settlement of share-based awards for certain Magellan employees and integration costs, as well as bridge facility commitment fees associated with the Magellan Acquisition.



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Pro Forma Financial Information (unaudited)

The following table sets forth the unaudited supplemental pro forma financial information for the years ended December 31, 2024 and 2023, as if we had completed the Magellan Acquisition on January 1, 2022, and the EnLink Controlling Interest Acquisition and the Medallion Acquisition on January 1, 2023:

Year Ended December 31, 2024
Pro Forma
EnLink Controlling Interest Acquisition		Pro Forma Medallion AcquisitionPro Forma Combined
 As reported
 (Millions of dollars)
Revenues$21,698 $4,579 $1,078 $27,355 
Net income$3,112 $288 $81 $3,481 


Year Ended December 31, 2023
Pro Forma EnLink Controlling Interest AcquisitionPro Forma Medallion AcquisitionPro Forma Magellan AcquisitionPro Forma Combined
 As reported
 (Millions of dollars)
Revenues$17,677 $6,239 $947 $2,322 $27,185 
Net income$2,659 $383 $(16)$232 $3,258 

The summarized unaudited pro forma information reflects the following adjustments:
•Reflects depreciation and amortization based on the final fair values of property, plant and equipment, and intangible assets;
•Reflects nonrecurring transaction costs incurred presented above that were reclassified and included in pro forma net income as if they had been incurred as of the earliest period presented for each respective acquisition;
•Reflects interest expense related to the underwritten public offerings of senior unsecured notes used to fund the cash consideration and other costs related to the acquisitions;
•Reflects the amortization of excess fair value of Magellan and EnLink share-based awards;
•Reflects the income tax effect of the pro forma adjustments;
•Reflects the elimination of historical activity between ONEOK, Magellan, EnLink and Medallion.

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C.    FAIR VALUE MEASUREMENTS

Recurring Fair Value Measurements - The following tables set forth our recurring fair value measurements as of the dates indicated:

December 31, 2025
Level 1Level 2Level 3Total - GrossNetting (a)Total - Net
(Millions of dollars)
Derivative assets
Commodity contracts$60 $69 $— $129 $(67)$62 
Total derivative assets$60 $69 $— $129 $(67)$62 
Derivative liabilities
Commodity contracts$(21)$(46)$— $(67)$67 $— 
Total derivative liabilities$(21)$(46)$— $(67)$67 $— 
(a) - Derivative assets and liabilities are presented in our Consolidated Balance Sheets on a net basis. We net derivative assets and liabilities when a legally enforceable master-netting arrangement exists between the counterparty to a derivative contract and us. At December 31, 2025, we held no cash and posted cash of $4 million with a counterparty, which is included in other current assets in our Consolidated Balance Sheets.

December 31, 2024
Level 1Level 2Level 3Total - GrossNetting (a)Total - Net
(Millions of dollars)
Derivative assets
Commodity contracts$41 $34 $— $75 $(72)$3 
Total derivative assets$41 $34 $— $75 $(72)$3 
Derivative liabilities
Commodity contracts$(40)$(46)$— $(86)$81 $(5)
Total derivative liabilities$(40)$(46)$— $(86)$81 $(5)
(a) - Derivative assets and liabilities are presented in our Consolidated Balance Sheets on a net basis. We net derivative assets and liabilities when a legally enforceable master-netting arrangement exists between the counterparty to a derivative contract and us. At December 31, 2024, we held no cash and posted cash of $45 million with a counterparty, including $10 million of cash collateral that is offsetting derivative net liability positions under master-netting arrangements in the table above. The remaining $35 million of cash collateral in excess of derivative liability positions is included in other current assets in our Consolidated Balance Sheets.

Other Financial Instruments - The approximate fair value of cash and cash equivalents, accounts receivable, accounts payable and short-term borrowings is equal to book value due to the short-term nature of these items. Our cash and cash equivalents are composed of bank and money market accounts and are classified as Level 1. Our short-term borrowings are classified as Level 2 since the estimated fair value of the short-term borrowings can be determined using information available in the commercial paper market. We have investments associated with our supplemental executive retirement plan and nonqualified deferred compensation plan that are carried at fair value and primarily are composed of mutual funds, municipal bonds and other fixed income securities classified as Level 1 and Level 2.

The book value of our consolidated long-term debt, including current maturities, was $32.0 billion and $32.1 billion at December 31, 2025 and 2024, respectively. At December 31, 2025 and 2024, the estimated fair value of our consolidated long-term debt, including current maturities, was $32.7 billion and $31.9 billion, respectively. For comparability to the book value of our consolidated long-term debt, the unamortized debt discounts and issuance costs at December 31, 2025 and 2024, totaled $1.2 billion and $1.1 billion, respectively, which resulted in the estimated fair value, net of unamortized debt discounts and issuance costs, of $31.5 billion and $30.8 billion, respectively. The estimated fair value of the aggregate senior notes outstanding was determined using quoted market prices for similar issues with similar terms and maturities. The estimated fair value of our consolidated long-term debt is classified as Level 2.

D.    RISK-MANAGEMENT AND HEDGING ACTIVITIES USING DERIVATIVES

Risk-management Activities - We are sensitive to changes in the prices of natural gas, NGLs, Refined Products and crude oil, principally as a result of contractual terms under which these commodities are processed, purchased and sold. We are also
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subject to the risk of interest-rate fluctuation in the normal course of business. We use physical-forward purchases and sales and financial derivatives to secure a certain price for a portion of our natural gas, NGLs, Refined Products, condensate and crude oil purchases and sales; to reduce our exposure to commodity price and interest-rate fluctuations; and to achieve more predictable cash flows. Additionally, we may use physical-forward purchases and financial derivatives to reduce commodity price risk associated with power and natural gas used to operate our facilities. We follow established policies and procedures to assess risk and approve, monitor and report our risk-management activities. We have not used these instruments for trading purposes.

Commodity price risk - Commodity price risk refers to the risk of loss in cash flows and future earnings arising from adverse changes in the price of natural gas, NGLs, Refined Products and crude oil. We may use the following commodity derivative instruments to reduce the near-term commodity price risk associated with a portion of our forecasted purchases and sales of these commodities:
•Futures contracts - Standardized contracts to purchase or sell natural gas and crude oil for future delivery or settlement under the provisions of exchange regulations;
•Forward contracts - Nonstandardized commitments between two parties to purchase or sell natural gas, NGLs, Refined Products, condensate and crude oil for future physical delivery. These contracts are typically nontransferable and can only be canceled with the consent of both parties;
•Swaps - Exchange of one or more payments based on the value of one or more commodities. These instruments transfer the financial risk associated with a future change in value between the counterparties of the transaction, without also conveying ownership interest in the asset or liability;
•Options - Contractual agreements that give the holder the right, but not the obligation, to buy or sell a fixed quantity of a commodity at a fixed price within a specified period of time. Options may either be standardized and exchange-traded or customized and nonexchange-traded; and
•Collars - Combination of a purchased put option and a sold call option, which places a floor and ceiling price for commodity sales being hedged.

We may also use other instruments to mitigate commodity price risk.

In our Natural Gas Gathering and Processing segment, we are exposed to commodity price risk as a result of retaining a portion of the commodity sales proceeds associated with our fee with POP contracts. Under certain fee with POP contracts, our fees and POP percentage may increase or decrease if production volumes, delivery pressures or commodity prices change relative to specified thresholds. We also are exposed to basis risk between the various production and market locations where we buy and sell commodities. As part of our hedging strategy, we use the previously described commodity derivative financial instruments and physical-forward contracts to reduce the impact of price fluctuations related to natural gas, NGLs and condensate.

In our Natural Gas Liquids segment, we are primarily exposed to commodity price risk resulting from the relative values of the various Purity NGLs to each other, the value of NGLs in storage and the relative value of NGLs to natural gas. We are also exposed to location price differential risk as a result of the relative value of NGL purchases at one location and sales at another location, primarily related to our optimization and marketing business. As part of our hedging strategy, we utilize physical-forward contracts and commodity derivative financial instruments to reduce the impact of price fluctuations related to NGLs.

In our Natural Gas Pipelines segment, we are primarily exposed to commodity price risk on our intrastate pipelines because they consume natural gas in operations and retain natural gas from our customers for operations or as part of our fee for compression services provided. When the amount consumed in operations differs from the amount provided by our customers, our pipelines must buy or sell natural gas, or store or use natural gas inventory, which can expose this segment to commodity price risk depending on the regulatory treatment for this activity. To the extent that commodity price risk in our Natural Gas Pipelines segment is not mitigated by fuel cost-recovery mechanisms, we may use physical-forward sales or purchases to reduce the impact of natural gas price fluctuations. We are also exposed to location price differential risk as a result of the relative value of natural gas purchases at one location and sales at another location, primarily related to our optimization and marketing business. As part of our hedging strategy, we utilize physical-forward contracts and commodity derivative financial instruments to reduce the impact of price fluctuations related to natural gas.

In our Refined Products and Crude segment, we are primarily exposed to commodity price risk from our liquids blending and marketing activities, as well as product retained during the operations of our pipelines and terminals. As part of our hedging strategy, we use the previously described commodity derivative financial instruments and physical-forward contracts to reduce the impact of price fluctuations related to NGLs, Refined Products and crude oil.

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Interest-rate risk - We may manage interest-rate risk through the use of fixed-rate debt, floating-rate debt, Treasury locks and interest-rate swaps. Treasury locks are agreements to pay the difference between the benchmark Treasury rate and the rate that is designated in the terms of the agreement. In the third quarter and second quarter of 2025, we entered into $300 million notional quantity and $700 million notional quantity, respectively, of Treasury locks to hedge the variability of interest payments on a portion of our forecasted debt issuances. In the third quarter of 2025, we settled all of the outstanding $1.0 billion notional quantity of Treasury locks in connection with our underwritten public offering of $3.0 billion senior unsecured notes in August 2025. All of our Treasury locks were designated as cash flow hedges.

At December 31, 2025, and December 31, 2024, we had no outstanding interest-rate derivative instruments.

Fair Values of Derivative Instruments - See Note A for a discussion of the inputs associated with our fair value measurements. The following table sets forth the fair values of our derivative instruments presented on a gross basis as of the dates indicated:
December 31, 2025December 31, 2024
Location in our Consolidated Balance SheetsAssets(Liabilities)Assets(Liabilities)
(Millions of dollars)
Derivatives designated as hedging instruments
Commodity contracts (a)(b)Other current assets$112 $(50)$39 $(47)
Total derivatives designated as hedging instruments112 (50)39 (47)
Derivatives not designated as hedging instruments
Commodity contracts (a)(b)Other current assets/liabilities17 (17)36 (33)
Other deferred credits— — — (6)
Total derivatives not designated as hedging instruments17 (17)36 (39)
Total derivatives$129 $(67)$75 $(86)
(a) - Derivative assets and liabilities are presented in our Consolidated Balance Sheets on a net basis when a legally enforceable master-netting arrangement exists between the counterparty to a derivative contract and us.
(b) - At December 31, 2024, our derivative net liability positions under master-netting arrangements for financial commodity contracts were offset by cash collateral of $10 million.

Notional Quantities for Derivative Instruments - The following table sets forth the notional quantities for our derivative instruments, consisting of futures and swaps, held as of the dates indicated:
December 31, 2025December 31, 2024
Net Purchased/Payor
(Sold/Receiver)
Derivatives designated as hedging instruments:
Cash flow hedges
   Fixed price
    - Natural gas (Bcf)
(19.4)(12.2)
    - NGLs, Refined Products and crude oil (MMBbl)
(22.1)(12.2)
   Basis
    - Natural gas (Bcf)
(17.9)(11.2)
    - NGLs, Refined Products and crude oil (MMBbl)
(0.6)— 
Derivatives not designated as hedging instruments:
   Fixed price
    - Natural gas (Bcf)
(4.1)(8.0)
    - NGLs, Refined Products and crude oil (MMBbl)
0.1 (2.7)
   Basis
    - Natural gas (Bcf)
(0.2)(3.7)
    - NGLs, Refined Products and crude oil (MMBbl)
— (0.2)
   Swing Swaps
    - Natural gas (Bcf)
(0.6)(0.2)


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Cash Flow Hedges - At December 31, 2025 and 2024, the accumulated other comprehensive income (loss) relating to risk-management assets and liabilities, net of taxes, was $19 million and $(38) million, respectively. Corresponding unrealized gains (losses) related to risk-management assets and liabilities at December 31, 2025 and 2024, are not material.

The following table sets forth the unrealized change in fair value of cash flow hedges in other comprehensive income (loss) for the periods indicated:

Years Ended December 31,
202520242023
 
(Millions of dollars)
Commodity contracts$83 $(50)$147 
Interest-rate contracts(5)(19)54 
Total unrealized change in fair value of cash flow hedges in other comprehensive income (loss)$78 $(69)$201 

The following table sets forth the effect of cash flow hedges on net income for the periods indicated:

Derivatives in Cash Flow
Hedging Relationships		Location of Gain (Loss) Reclassified from
Accumulated Other Comprehensive Loss into
Net Income		  
Years Ended December 31,
202520242023
  
(Millions of dollars)
Commodity contractsCommodity sales revenues$53 $60 $201 
Cost of sales and fuel(34)(19)(93)
Interest-rate contractsInterest expense(16)(20)(21)
Total change in fair value of cash flow hedges reclassified from accumulated other comprehensive loss into net income on derivatives
$3 $21 $87 

Credit Risk - We monitor the creditworthiness of our counterparties and compliance with policies and limits established by our Risk Oversight and Strategy Committee. We maintain credit policies with regard to our counterparties that we believe minimize credit risk. These policies include an evaluation of potential counterparties’ financial condition (including credit ratings, bond yields and credit default swap rates), collateral requirements under certain circumstances and the use of standardized master-netting agreements that allow us to net the positive and negative exposures associated with a single counterparty. We use internally developed credit ratings for counterparties that do not have a credit rating.

Our financial commodity derivatives are primarily settled through a NYMEX or Intercontinental Exchange clearing broker account with daily margin requirements. However, we may enter into financial derivative instruments that contain provisions that require us to maintain an investment-grade credit rating from S&P, Fitch and/or Moody’s. If our credit ratings on our senior unsecured long-term debt were to decline below investment grade, the counterparties to the derivative instruments could request collateralization on derivative instruments in net liability positions.

The counterparties to our derivative contracts typically consist of major energy companies, financial institutions and commercial and industrial end users. This concentration of counterparties may affect our overall exposure to credit risk, either positively or negatively, in that the counterparties may be affected similarly by changes in economic, regulatory or other conditions. Based on our policies, exposures, credit and other reserves, we do not anticipate a material adverse effect on our financial position or results of operations as a result of counterparty nonperformance.

At December 31, 2025, the credit exposure from our derivative assets is with investment-grade companies in the financial services sector.

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E.    PROPERTY, PLANT AND EQUIPMENT

The following table sets forth our property, plant and equipment by property type, as of the dates indicated:
Estimated Useful
Lives (Years)		December 31,
2025		December 31,
2024
  
(Millions of dollars)
Gathering pipelines and related equipment
3 to 47
$13,219 $11,643 
Processing and fractionation and related equipment
3 to 40
12,594 12,406 
Storage and related equipment
5 to 54
3,770 3,684 
Transmission pipelines and related equipment
3 to 87
21,756 21,315 
General plant and other
2 to 60
1,171 1,316 
Land—416 592 
Construction work in process—2,563 1,318 
Property, plant and equipment 55,489 52,274 
Accumulated depreciation and amortization (7,628)(6,339)
Net property, plant and equipment $47,861 $45,935 

The depreciation expense for the years ended December 31, 2025, 2024 and 2023 was $1.4 billion, $1.1 billion and $736 million, respectively.

We incurred costs for construction work in process that had not been paid at December 31, 2025, 2024 and 2023, of $173 million, $179 million and $242 million, respectively. Such amounts are not included in capital expenditures (less AFUDC) on the Consolidated Statements of Cash Flows.

EnLink Controlling Interest Acquisition - In October 2024, we completed the EnLink Controlling Interest Acquisition and acquired property, plant and equipment, which primarily include pipeline and rights of way, pipeline-related equipment, processing plants and fractionators, valued at $11.4 billion.

Medallion Acquisition - In October 2024, we completed the Medallion Acquisition and acquired property, plant and equipment, which primarily include pipeline and pump station equipment, valued at $1.6 billion.

Interstate Natural Gas Pipeline Divestiture - In December 2024, we completed the sale of three of our wholly owned interstate natural gas pipeline systems to DT Midstream, Inc. These assets, which are primarily transmission pipelines and related equipment, had a gross cost basis of $1.3 billion.


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F.    GOODWILL AND INTANGIBLE ASSETS

Goodwill - The following table sets forth our goodwill, by segment, for the periods indicated:

Natural Gas
Gathering and
Processing		Natural Gas
Liquids		Natural Gas
Pipelines		Refined Products and CrudeTotal
(Millions of dollars)
Gross goodwill$639 $1,863 $353 $5,389 $8,244 
Accumulated impairment losses(153)— — — (153)
December 31, 2024486 1,863 353 5,389 8,091 
EnLink Controlling Interest Acquisition adjustment8 (45)2 (2)(37)
Medallion Acquisition adjustment— — — 4 4 
December 31, 2025$494 $1,818 $355 $5,391 $8,058 

Intangible Assets - Our intangible assets relate primarily to acquired customer relationships from our recent acquisitions and are being amortized on a straight-line basis over a weighted average life of 26 years. Amortization expense for intangible assets was $138 million in 2025, $62 million in 2024 and $33 million in 2023. The amortization expense for each of the next five years is estimated to be $135 million. The following table reflects the gross carrying amount and accumulated amortization of intangible assets as of the dates presented:
December 31,
20252024
(Millions of dollars)
Gross intangible assets$3,290 $3,290 
Accumulated amortization(389)(251)
Intangible assets, net$2,901 $3,039 
.

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G.    DEBT
The following table sets forth our consolidated debt as of the dates indicated:
December 31, 2025December 31, 2024
(Millions of dollars)
Commercial paper outstanding, bearing a weighted-average interest rate of 3.91% as of December 31, 2025 (a)
$820 $— 
Senior unsecured obligations:
$250 at 3.2% due March 2025
— 250 
$750 at 4.15% due June 2025 (b)
— 422 
$400 at 2.2% due September 2025
— 387 
$600 at 5.85% due January 2026
— 600 
$650 at 5.0% due March 2026
— 650 
$500 at 4.85% due July 2026 (b)
491 491 
$750 at 5.55% due November 2026
750 750 
$500 at 4.0% due July 2027
500 500 
$1,250 at 4.25% due September 2027
1,250 1,250 
$500 at 5.625% due January 2028 (b)
500 500 
$800 at 4.55% due July 2028
800 800 
$100 at 6.875% due September 2028
100 100 
$750 at 5.650% due November 2028
750 750 
$700 at 4.35% due March 2029
700 700 
$500 at 5.375% due June 2029 (b)
499 499 
$750 at 3.4% due September 2029
714 714 
$600 at 4.4% due October 2029
600 600 
$850 at 3.1% due March 2030
780 780 
$500 at 3.25% due June 2030
500 500 
$1,000 at 6.5% due September 2030 (b)
1,000 1,000 
$500 at 5.8% due November 2030
500 500 
$600 at 6.35% due January 2031
600 600 
$1,250 at 4.75% due October 2031
1,250 1,250 
$750 at 4.95% due October 2032
750 — 
$750 at 6.1% due November 2032
750 750 
$1,500 at 6.05% due September 2033
1,500 1,500 
$500 at 5.65% due September 2034 (b)
500 500 
$1,600 at 5.05% due November 2034
1,600 1,600 
$400 at 6.0% due June 2035
400 400 
$1,000 at 5.4% due October 2035
1,000 — 
$600 at 6.65% due October 2036
600 600 
$250 at 6.4% due May 2037
250 250 
$600 at 6.85% due October 2037
600 600 
$650 at 6.125% due February 2041
650 650 
$250 at 4.2% due December 2042
250 250 
$400 at 6.2% due September 2043
400 400 
$550 at 5.15% due October 2043
550 550 
$350 at 5.6% due April 2044 (b)
340 340 
$250 at 4.2% due March 2045
250 250 
$450 at 5.05% due April 2045 (b)
413 413 
$500 at 4.25% due September 2046
500 500 
$500 at 5.45% due June 2047 (b)
448 448 
$700 at 4.95% due July 2047
407 564 
$500 at 4.2% due October 2047
500 500 
$1,000 at 5.2% due July 2048
753 919 
$500 at 4.85% due February 2049
500 500 
$750 at 4.45% due September 2049
380 576 
$500 at 4.5% due March 2050
271 443 
$800 at 3.95% due March 2050
797 797 
$300 at 7.15% due January 2051
300 300 
$1,750 at 6.625% due September 2053
1,750 1,750 
$1,500 at 5.7% due November 2054
1,480 1,500 
$1,250 at 6.25% due October 2055
1,250 — 
$800 at 5.85% due November 2064
722 800 
Total debt33,965 33,243 
Unamortized debt discounts(979)(1,000)
Unamortized debt issuance costs and terminated swaps(170)(166)
Current maturities of long-term debt(1,241)(1,059)
Short-term borrowings (a)(820)— 
Long-term debt$30,755 $31,018 
(a) - Individual issuances of commercial paper under our commercial paper program generally mature in 90 days or less.
(b) - As of December 31, 2024, amounts represent EnLink and EnLink Partners’ debt acquired in the EnLink Controlling Interest Acquisition on October 15, 2024. At the completion of the EnLink Acquisition on January 31, 2025, ONEOK assumed the outstanding debt of EnLink and EnLink Partners.
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Commercial Paper Program - In September 2025, we increased the size of our commercial paper program to $3.5 billion from $2.5 billion.

$3.5 Billion Credit Agreement - In February 2025, we amended and restated our $2.5 Billion Credit Agreement to increase the size to $3.5 billion, extend the term to February 2030 and make other nonmaterial modifications. Our $3.5 Billion Credit Agreement is a revolving credit facility and contains certain customary conditions for borrowing, as well as customary financial, affirmative and negative covenants. Among other things, these covenants include maintaining a ratio of consolidated net indebtedness to adjusted EBITDA (EBITDA, as defined in our $3.5 Billion Credit Agreement, adjusted for all noncash items and increased for projected EBITDA from certain lender-approved capital expansion projects). In addition, adjusted EBITDA as defined in our $3.5 Billion Credit Agreement allows inclusion of the trailing 12 months of consolidated adjusted EBITDA of an acquired business. In December 2025, we completed the acquisition of a system of gas gathering assets, which allowed us to effectively extend the acquisition adjustment period under our $3.5 Billion Credit Agreement and, as a result, our leverage ratio covenant of 5.5 to 1 was extended through the quarter ending June 30, 2026, after which it will decrease to 5.0 to 1.

The $3.5 Billion Credit Agreement includes a $100 million sublimit for the issuance of standby letters of credit and a $200 million sublimit for swingline loans. Under the terms of the $3.5 Billion Credit Agreement, we may request up to an aggregate $1.0 billion increase in the size of the facility, upon satisfaction of customary conditions, including receipt of commitments from new lenders or increased commitments from existing lenders. The $3.5 Billion Credit Agreement contains provisions for an applicable margin rate and an annual facility fee, both of which adjust with changes in our credit ratings. Borrowings, if any, will accrue at Term SOFR plus an applicable margin based on our credit ratings at the time of determination plus an adjustment of 10 basis points. Under our current credit ratings, the applicable margin on any borrowings would be 110 basis points. We are required to pay an annual facility fee equal to the daily amount of aggregate commitments under the $3.5 Billion Credit Agreement times an applicable rate based on our credit rating at the time of determination. Under our current credit ratings, the applicable rate is 15 basis points. We have the option to request two additional one-year maturity extensions, subject to lender approvals. The $3.5 Billion Credit Agreement also contains various customary events of default, the occurrence of which could result in a termination of the lenders’ commitments and the acceleration of all of our obligations thereunder. As of December 31, 2025, we had no outstanding borrowings, our ratio of consolidated indebtedness to adjusted EBITDA was 4.3 to 1, and we were in compliance with all covenants under our $3.5 Billion Credit Agreement.

EnLink Acquisitions - In October 2024, we completed the EnLink Controlling Interest Acquisition and, as a result, we acquired the EnLink Revolving Credit Facility. The EnLink Revolving Credit Facility, which would have matured in June 2027, was a $1.4 billion unsecured revolving credit facility that included a $500 million letter of credit subfacility. Borrowings under the EnLink Revolving Credit Facility bore interest at Term SOFR plus a Term SOFR spread adjustment of 0.10% per annum and an applicable margin (ranging from 1.125% to 2.00%) or the Base Rate (the highest of the federal funds rate plus 0.50%, one-month Adjusted Term SOFR plus 1.0% or the administrative agent’s prime rate) plus an applicable margin (ranging from 0.125% to 1.00%). Upon closing of the EnLink Acquisition on January 31, 2025, the EnLink Revolving Credit Facility was terminated.

In October 2024, we completed the EnLink Controlling Interest Acquisition and, as a result, we acquired the $500 million EnLink AR Facility. In December 2024, EnLink terminated the EnLink AR Facility, and we entered into an agreement to provide revolving unsecured loans to EnLink through a promissory note at an interest rate of 4.85% at December 31, 2024. This was a floating rate agreement, which bore interest at ONEOK’s current short-term borrowing rate plus 0.25%. At December 31, 2024, we held a promissory note receivable of $510 million, which was eliminated in consolidation. Interest earned from this agreement was not material. Upon closing of the EnLink Acquisition on January 31, 2025, we terminated the agreement to provide revolving unsecured loans to EnLink through a promissory note.

Senior Unsecured Obligations - All notes are senior unsecured obligations, ranking equally in right of payment with all of our existing and future unsecured senior indebtedness, and are structurally subordinate to any of the existing and future debt and other liabilities of any nonguarantor subsidiaries.

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Debt Issuances - We completed the following underwritten public offerings for the periods presented:

2025 (a)2024 (b)2023 (c)
PrincipalInterestPrincipalInterestPrincipalInterest
(Millions of dollars, except for percentages)
3 year note$1,250 4.25%$750 5.55%
5 year note600 4.4%750 5.65%
7 year note$750 4.95%1,250 4.75%500 5.80%
10 year note1,000 5.4%1,600 5.05%1,500 6.05%
30 year note1,250 6.25%1,500 5.7%1,750 6.625%
40 year note8005.85%
Total$3,000 $7,000 $5,250 
(a) - The net proceeds, after deducting underwriting discounts, commissions and offering expenses, were $2.96 billion. The net proceeds from this offering were partially used to repay our commercial paper outstanding and repay in full at maturity our senior notes due September 2025. The remaining net proceeds from the offering were used for general corporate purposes, including the repurchase and redemption of existing notes.
(b) - The net proceeds, after deducting underwriting discounts, commissions and offering expenses, were $6.9 billion. The net proceeds from this offering were used to fund the EnLink Controlling Interest Acquisition and the Medallion Acquisition, purchase additional interests in a Medallion joint venture owned by a separate third party, to pay fees and expenses related to the acquisitions and to repay outstanding indebtedness.
(c) - The net proceeds, after deducting underwriting discounts, commissions and offering expenses, were $5.2 billion. The net proceeds were used to fund the cash consideration and other costs related to the Magellan Acquisition.

Debt Extinguishments - We completed the following debt extinguishments for the periods presented:

202520242023
PrincipalPrincipalPrincipal
(Millions of dollars, except for percentages)
$250 at 3.2% due March 2025
$250 
$500 at 2.75% due September 2024
$484 
$500 at 7.5% due September 2023 (a)
$500 
$750 at 4.15% due June 2025
422 
$500 at 4.9% due March 2025 (a)
500 
$425 at 5.0% due September 2023 (a)
425 
$400 at 2.2% due September 2025
387 Guardian Term Loan Agreement120 Open Market Repurchases (c)322 
$600 at 5.85% due January 2026 (a)
600 Viking Term Loan Agreement60 
$650 at 5.0% due March 2026 (a)
650 EnLink Revolving Credit Facility465 
Open Market Repurchases (b)
789 EnLink AR Facility 374 
Total
$3,098 $2,003 $1,247 
(a) - Amounts redeemed at 100% of principal plus accrued and unpaid interest.
(b) - In 2025, we repurchased in the open market certain of our senior notes in the principal amount of $789 million for an aggregate repurchase price of $681 million, including accrued and unpaid interest. In connection with these open market repurchases, we recognized $106 million of net gains on extinguishment of debt which is included in other income, net in our Consolidated Statement of Income for the year ended December 31, 2025.
(c) - In 2023, we repurchased in the open market certain of our senior notes in the principal amount of $322 million for an aggregate repurchase price of $280 million, including accrued and unpaid interest. In connection with these open market repurchases, we recognized $41 million of net gains on extinguishment of debt which is included in other income, net in our Consolidated Statement of Income for the year ended December 31, 2023.

The aggregate maturities of long-term debt outstanding and interest payments on total debt outstanding as of December 31, 2025, for the years 2026 through 2030 are shown below:
Senior
Unsecured
Obligations		Interest
Obligations
on Debt		Total
 (Millions of dollars)
2026$1,241 $1,739 $2,980 
2027$1,750 $1,668 $3,418 
2028$2,150 $1,566 $3,716 
2029$2,513 $1,451 $3,964 
2030$2,780 $1,341 $4,121 

Compliance with Debt Covenants - As of December 31, 2025, we were in compliance with the covenants contained in our various debt agreements.

Other - We amortize premiums, discounts and expenses incurred in connection with the issuance of long-term debt consistent with the terms of the respective debt instrument.
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Debt Guarantees - At the completion of the EnLink Acquisition on January 31, 2025, ONEOK assumed the outstanding debt of EnLink and EnLink Partners (the “Assumed Debt”). EnLink and EnLink Partners were released as primary obligors from all debt obligations under the Assumed Debt, but each entity provided a guarantee for our and ONEOK Partners’ indebtedness to the holders of each series of outstanding securities, including for the Assumed Debt.

ONEOK, ONEOK Partners, the Intermediate Partnership, Magellan, EnLink and EnLink Partners have cross guarantees in place for ONEOK’s and ONEOK Partners’ indebtedness.

H.    EQUITY

Noncontrolling Interests - As of December 31, 2025, noncontrolling interests in our Consolidated Balance Sheets related to Ascension and MBTC Pipeline. On February 4, 2025, we announced a definitive agreement to form the MBTC Pipeline joint venture, of which we own 80%. As a result of the Delaware Basin JV Acquisition and the EnLink Acquisition, these entities are now wholly owned subsidiaries and are no longer recorded as noncontrolling interests in our Consolidated Balance Sheets as of December 31, 2025.

In October 2024, we completed the EnLink Controlling Interest Acquisition, acquiring GIP’s interest in EnLink consisting of approximately 43% of the outstanding EnLink Units. In connection with the EnLink Controlling Interest Acquisition, we recorded noncontrolling interests with a fair value of $5.1 billion representing the approximately 57% of outstanding EnLink Units we did not own, the Series B Preferred Units and partially owned consolidated subsidiaries of EnLink.

As of December 31, 2024, included within noncontrolling interests are Series B Preferred Units, which were issued under EnLink Partners’ partnership agreement and represent noncontrolling ownership interests in EnLink Partners. EnLink Partners was a controlled subsidiary of EnLink in which EnLink owned all of the outstanding common units. Series B Preferred Units were exchangeable for EnLink Units in an amount equal to the number of outstanding Series B Preferred Units multiplied by an exchange ratio of 1.15, subject to certain adjustments. The exchange was subject to our option to pay cash instead of issuing additional EnLink common units.

As of December 31, 2024, $515 million of noncontrolling interest on our Consolidated Balance Sheets related to Series B Preferred Units, and there were 27.4 million units outstanding. There were no Series B Preferred Units converted or redeemed during the ownership period of October 15, 2024, through December 31, 2024. Distributions made on Series B Preferred Units were not material.

As of December 31, 2024, EnLink owned a 50.1% interest in the Delaware Basin JV, which owns processing facilities located in the Delaware Basin in Texas. Noncontrolling interests included the other owner’s minority interest in the Delaware Basin JV. As of December 31, 2024, $684 million of noncontrolling interests on our Consolidated Balance Sheets related to the Delaware Basin JV and the other partially owned consolidated subsidiary of EnLink was not material.

Series A and B Convertible Preferred Stock - There are no shares of Series A or Series B Preferred Stock currently issued or outstanding.

EnLink Series C Preferred Units - Series C Preferred Units represented noncontrolling ownership interests in EnLink Partners. In September 2024, EnLink gave notice to redeem all of its outstanding Series C Preferred Units, and reclassified the obligation to a liability on their Consolidated Balance Sheets. On October 17, 2024, EnLink redeemed all outstanding Series C Preferred Units at $1,000 per Series C Preferred Unit, plus $8.28 per Series C Preferred Unit of unpaid distributions, for $365 million with proceeds received from borrowings under the EnLink Revolving Credit Facility. As of December 31, 2024, there were no remaining Series C Preferred Units outstanding.

Equity Issuances - On May 28, 2025, we completed the Delaware Basin JV Acquisition. Pursuant to the purchase agreement, we issued approximately 4.9 million shares of ONEOK common stock to the seller with a fair value of $391 million as of the closing date.

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. There are no remaining Series B Preferred Units outstanding.

In September 2023, we completed the Magellan Acquisition. Pursuant to the Magellan Merger Agreement, each common unit of Magellan was exchanged for a fixed ratio of 0.667 shares of ONEOK common stock and $25.00 of cash. We issued
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approximately 135 million shares of common stock, with a fair value of approximately $9.0 billion as of the closing date of the Magellan Acquisition.

We have an “at-the-market” equity program for the offer and sale from time to time of our common stock up to an aggregate offering price of $1.0 billion. The program allows us to offer and sell common stock at prices we deem appropriate through a sales agent, in forward sales transactions through a forward seller or directly to one or more of the program’s managers acting as principals. Sales of our common stock may be made by means of ordinary brokers’ transactions on the NYSE, in block transactions or as otherwise agreed to between us and the sales agent. We are under no obligation to offer and sell common stock under the program. As of December 31, 2025, no shares have been sold through our “at-the-market” program.

Share Repurchase Program - In January 2024, our Board of Directors authorized a share repurchase program to buy up to $2.0 billion of our outstanding common stock. We expect shares to be acquired from time to time in open market transactions or through privately negotiated transactions at our discretion, subject to market conditions and other factors. The program will terminate upon completion of the repurchase of the $2.0 billion of common stock or on January 1, 2029, whichever occurs first. For the year ended December 31, 2025, we repurchased $62 million of our outstanding common stock under the program with cash on hand. For the year ended December 31, 2024, we repurchased $172 million of our outstanding common stock under the program with cash on hand and short-term borrowings.

Dividends - Holders of our common stock share equally in any common stock dividends declared by our Board of Directors. Dividends paid totaled $2.6 billion, $2.3 billion and $1.8 billion for 2025, 2024 and 2023, respectively. The following table sets forth the quarterly dividends per share paid on our common stock in the periods indicated:
 Years Ended December 31,
 202520242023
First Quarter$1.03 $0.99 $0.955 
Second Quarter1.03 0.99 0.955 
Third Quarter1.03 0.99 0.955 
Fourth Quarter1.03 0.99 0.955 
Total$4.12 $3.96 $3.82 

Additionally, a quarterly common stock dividend of $1.07 per share ($4.28 per share on an annualized basis) was declared for shareholders of record at the close of business on February 2, 2026, and paid on February 13, 2026.

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I.    VARIABLE INTEREST ENTITIES

Consolidated Variable Interest Entities (VIEs) - As of December 31, 2024, we consolidated EnLink, Delaware Basin JV and Ascension VIEs. As a result of the Delaware Basin JV Acquisition and the EnLink Acquisition, these respective entities are no longer considered VIEs.

As of December 31, 2025, we consolidated the following VIEs:

MBTC Pipeline - On February 4, 2025, we announced a definitive agreement with MPLX LP to form the MBTC Pipeline joint venture, which will construct and operate a 24-inch pipeline from our Mont Belvieu, Texas, storage facility to a new liquified petroleum gas export terminal in Texas City, Texas. We own an 80% interest in MBTC Pipeline, and we are the operator. MBTC Pipeline is a VIE because the nonmanaging member does not have substantive rights (except in the case of default and other triggering events) to remove the managing member or participating rights over the managing member. As the managing member, we are the primary beneficiary because we control the decisions that most significantly impact MBTC Pipeline.

Ascension - We own a 50% interest in Ascension, which owns an NGL transmission pipeline that connects our Riverside fractionator to the other owner’s refinery. Ascension is a VIE because the nonmanaging member does not have substantive rights (except in the case of default and other triggering events) to remove us as the managing member. They also do not have the ability to participate or block our decisions as the managing member, which makes us the primary beneficiary because we control the decisions that most significantly impact Ascension.

As of December 31, 2025, the assets and liabilities of our consolidated VIEs were not material. The following table presents the balance sheet information for the assets and liabilities that are only for the use or obligation of our consolidated VIEs, which were included in our Consolidated Balance Sheets as of December 31, 2024:
December 31,
2024
(Millions of dollars)
Assets:
Cash and cash equivalents$46 
Accounts receivable, net735 
Inventories54 
Other current assets39 
Net property, plant and equipment11,397 
Investments in unconsolidated affiliates317 
Goodwill2,717 
Intangible assets, net1,047 
Other assets134 
Liabilities:
Current maturities of long-term debt$422 
Accounts payable639 
Commodity imbalances10 
Accrued interest73 
Other current liabilities90 
Long-term debt, excluding current maturities4,693 
Deferred income taxes2,041 
Other deferred credits97 


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J.    EARNINGS PER SHARE

The following tables set forth the computation of basic and diluted EPS for the periods indicated:

Year Ended December 31, 2025
IncomeSharesPer Share Amount
(Millions, except per share amounts)
Basic EPS
Net income attributable to ONEOK available for common stock$3,393 624.8 $5.43 
Diluted EPS
Effect of dilutive securities— 1.1 
Net income attributable to ONEOK available for common stock and common stock equivalents$3,393 625.9 $5.42 

Year Ended December 31, 2024
IncomeSharesPer Share Amount
(Millions, except per share amounts)
Basic EPS
Net income attributable to ONEOK available for common stock$3,034 584.6 $5.19 
Diluted EPS
Effect of dilutive securities— 1.9 
Net income attributable to ONEOK available for common stock and common stock equivalents$3,034 586.5 $5.17 

Year Ended December 31, 2023
IncomeSharesPer Share Amount
(Millions, except per share amounts)
Basic EPS
Net income available for common stock$2,658 484.3 $5.49 
Diluted EPS
Effect of dilutive securities— 1.1 
Net income available for common stock and common stock equivalents$2,658 485.4 $5.48 

K.    SHARE-BASED PAYMENTS

Our Equity Incentive Plan (EIP) provides for the granting of stock-based compensation to eligible employees and non-employee directors, including restricted stock units, performance units, director stock awards and other awards. In May 2025, our shareholders approved the 2025 Equity Incentive Plan (2025 EIP), which replaced the EIP approved by our shareholders in 2018. All new equity awards are issued under the 2025 EIP. There were 19.1 million shares of common stock authorized for issuance under the 2025 EIP and at December 31, 2025, we had 18.6 million shares available for issuance. This calculation of available shares reflects shares issued and estimated shares expected to be issued upon vesting of outstanding awards granted under the 2025 EIP, excluding estimated forfeitures expected to be returned to the plan.

EnLink Acquisitions - As discussed in Note B, we completed the EnLink Controlling Interest Acquisition on October 15, 2024. EnLink had previously issued restricted incentive units and performance units that vest at the end of a designated period, typically three years. The fair value of these awards attributable to pre-combination service was allocated to consideration transferred and was included as part of the purchase price. The portion attributable to post-combination service is being recognized as compensation expense on a straight-line basis over the remaining vesting period of the awards. Upon completion of the EnLink Acquisition on January 31, 2025, each outstanding unit-based award was converted into a restricted stock unit with respect to shares of our common stock and measured at their acquisition date fair value as if they were vested and issued on the acquisition date. Converted restricted stock unit awards accrue dividend equivalents that are paid out in cash quarterly.

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Magellan Acquisition - As discussed in Note B, we completed the Magellan Acquisition on September 25, 2023. Prior to the acquisition, Magellan had previously issued unit-based awards consisting of time-vested phantom units and performance phantom units, that vested at the end of a designated period, typically three years. Pursuant to the terms of the Magellan Merger Agreement, each outstanding unit-based award was converted into a restricted stock unit with respect to shares of our common stock and measured at their acquisition date fair value as if they were vested and issued on the acquisition date. The fair value attributable to pre-combination service was allocated to consideration transferred and was included as part of the purchase price. The portion attributable to post-combination service is being recognized as compensation expense on a straight-line basis over the remaining vesting period of the awards. Converted restricted stock unit awards accrue dividend equivalents that are paid out in cash at vesting.

Restricted Stock Units - We have granted restricted stock units to key employees that vest at the end of a designated period, typically three years, and entitle the grantee to receive shares of our common stock. Restricted stock unit awards are measured at fair value as if they were vested and issued on the grant date and adjusted for estimated forfeitures. Restricted stock unit awards accrue dividend equivalents in the form of additional restricted stock units prior to vesting. Compensation expense is recognized on a straight-line basis over the vesting period of the award.

Performance Unit Awards - We have granted performance unit awards to key employees that vest at the end of a three-year period. Upon vesting, a holder of outstanding performance units is entitled to receive a number of shares of our common stock equal to a percentage (0% to 200%) of the performance units granted, based on our total shareholder return over the performance period, compared with the total shareholder return of a peer group of other energy companies over the same period. Performance unit awards are measured at fair value on the grant date based on a Monte Carlo model and adjusted for estimated forfeitures. Performance unit awards accrue dividend equivalents in the form of additional performance units prior to vesting. Compensation expense is recognized on a straight-line basis over the vesting period of the award.

Stock Compensation for Non-Employee Directors - The 2025 EIP provides for the granting of director stock awards and other awards to non-employee directors, up to $1.0 million per year for each such director when combined with any cash fees.

General - For all awards outstanding, we used a 3% forfeiture rate based on historical forfeitures under our share-based payment plans. We currently use treasury stock to satisfy our share-based payment obligations.

Compensation expense, exclusive of those recognized within transaction costs, for our share-based payment plans was $92 million, $102 million and $63 million during 2025, 2024 and 2023, respectively, before related tax benefits of $31 million, $36 million and $14 million, respectively.

Restricted Stock Unit Activity - As of December 31, 2025, we had $87 million of total unrecognized compensation cost related to our nonvested restricted stock unit awards, which is expected to be recognized over a weighted-average period of 1.9 years. The following tables set forth activity and various statistics for our restricted stock unit awards:

Number
of Units		Weighted Average Price
Nonvested December 31, 20241,360,122 $68.71 
    Granted (a)1,605,626 $88.80 
    Released to participants (b)(938,789)$75.33 
    Forfeited (b)(77,622)$85.70 
Nonvested December 31, 20251,949,337 $81.40 
(a) - Included 480,280 unvested restricted stock unit awards converted in conjunction with the EnLink Acquisition.
(b) - Included 348,019 restricted stock unit awards released to participants and forfeited in conjunction with the EnLink Acquisition.
202520242023
Weighted-average grant date fair value (per share)$88.80 $75.42 $66.50 
Grant date fair value of units granted (millions of dollars)$143 $39 $111 

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Performance Unit Activity - As of December 31, 2025, we had $39 million of total unrecognized compensation cost related to the nonvested performance unit awards, which is expected to be recognized over a weighted-average period of 1.7 years. The following tables set forth activity and various statistics related to the performance unit awards and the assumptions used in the valuations at the respective grant dates:
Number
of Units		Weighted Average Price
Nonvested December 31, 20241,099,699 $84.25 
    Granted449,020 $80.55 
    Released to participants(332,706)$79.21 
    Forfeited(50,905)$84.55 
Nonvested December 31, 20251,165,108 $84.25 
202520242023
Volatility (a)27.17%29.00%63.30%
Dividend yield4.15%5.40%5.75%
Risk-free interest rate4.30%4.46%4.43%
(a) - Volatility was based on historical volatility over three years using daily stock price observations.
202520242023
Weighted-average grant date fair value (per share)$80.55 $85.69 $87.46 
Grant date fair value of units granted (millions of dollars)$36 $39 $32 

Employee Stock Purchase Plan - We have reserved a total of 13.1 million shares of common stock for issuance under our Employee Stock Purchase Plan (the ESPP). Subject to certain exclusions, all employees are eligible to participate in the ESPP. Employees can choose to have up to 10% of their base pay withheld from each paycheck during the offering period to purchase our common stock, subject to the terms and limitations of the plan. The purchase price of the stock is 85% of the lower of its grant date or exercise date market price. Approximately 58%, 59% and 69% of employees participated in the plan in 2025, 2024 and 2023, respectively. Under the plan, we sold 356,745 shares at a weighted average of $65.34 per share in 2025, 275,874 shares at a weighted average of $64.38 per share in 2024 and 236,108 shares at a weighted average of $52.70 per share in 2023.

Employee Stock Award Program - Under our Employee Stock Award Program (the ESAP), we issued, for no monetary consideration, to all eligible employees one share of our common stock when the per-share closing price of our common stock on the NYSE is at or above each one-dollar increment above its previous high closing price. We authorized a total of 900,000 shares of common stock under the ESAP. The ESAP terminated as of November 7, 2024, and no additional grants were made under the program after such date. In May 2025, our shareholders approved the 2025 Employee Stock Award Program (the 2025 ESAP), which issues shares of our common stock in the same manner as the ESAP and permits our Board of Directors to issue additional shares of our common stock in its discretion. A total of 700,000 shares of common stock were authorized for issuance under the 2025 ESAP. Shares issued to employees under these programs during 2025 and 2024 totaled 66,916 and 127,825, respectively. Employees have received awards through the $117 milestone. No shares were issued to employees under these programs in 2023.

Deferred Compensation Plan for Non-Employee Directors - Our Deferred Compensation Plan for Non-Employee Directors provides our non-employee directors the option to defer all or a portion of their compensation for their service on our Board of Directors. Under the plan, directors may elect either a cash deferral option or a phantom stock option. Under the cash deferral option, directors may elect to defer the receipt of all or a portion of their annual retainer fees (other than their stock retainer fees), which will be credited with interest during the deferral period. Under the phantom stock option, directors may defer all or a portion of their annual retainer fees and receive such fees on a deferred basis in the form of shares of common stock under our EIP or 2025 EIP, which earn the equivalent of dividends declared on our common stock. Shares are distributed to non-employee directors at the fair market value of our common stock at the date of distribution.

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L.    EMPLOYEE BENEFIT PLANS

Retirement and Other Postretirement Benefit Plans

ONEOK Retirement Plan - We maintain the ONEOK Retirement Plan, a defined benefit pension plan covering certain legacy ONEOK employees, which closed to new participants in 2005. In addition, we have a supplemental executive retirement plan for the benefit of certain officers who participate in the ONEOK Retirement Plan. Our supplemental executive retirement plan is closed to new participants. We fund our defined benefit pension plan at a level needed to maintain or exceed the minimum funding levels required by the Employee Retirement Income Security Act of 1974, as amended.

Magellan Retirement Plans - As a result of the Magellan Acquisition in 2023, we assumed two defined benefit pension plans covering certain legacy Magellan employees, including the Magellan Pension Plan, which closed to new participants upon the closing of the acquisition, and the Magellan Pension Plan for USW Employees, which closed to new participants in January 2024. We fund these defined benefit pension plans at a level needed to maintain or exceed the minimum funding levels required by the Employee Retirement Income Security Act of 1974, as amended.

Other Postretirement Benefit Plans - We sponsor health and welfare plans that provide postretirement medical and life insurance benefits to certain legacy ONEOK employees hired prior to 2017 and certain legacy Magellan employees who retire after a specified age with at least five years of service and satisfy certain other conditions. The postretirement medical plan for pre-Medicare participants is contributory, with retiree contributions adjusted periodically, and contains other cost-sharing features such as deductibles and coinsurance. The postretirement medical plan for Medicare-eligible participants is an account-based plan under which participants may elect to purchase private insurance policies under a private exchange and/or seek reimbursement of other eligible medical expenses and is not available to legacy Magellan employees.

Obligations and Funded Status - The following table sets forth our retirement and other postretirement benefit plans benefit obligations and fair value of plan assets for the periods indicated:
Retirement BenefitsOther Postretirement Benefits
December 31,December 31,
 2025202420252024
Change in benefit obligation
(Millions of dollars)
Benefit obligation, beginning of period$689 $702 $46 $51 
Service cost15 21 — — 
Interest cost39 37 3 2 
Plan participants’ contributions— — 1 1 
Actuarial loss (gain)
2 (35)(1)(5)
Benefits paid(38)(36)(4)(3)
Benefit obligation, end of period (a)707 689 45 46 
Change in plan assets  
Fair value of plan assets, beginning of period535 554 15 16 
Actual return on plan assets60 12 2 1 
Employer contributions29 5 — — 
Plan participants’ contributions— — 1 1 
Benefits paid(38)(36)(4)(3)
Fair value of plan assets, end of period (b)586 535 14 15 
Balance at December 31$(121)$(154)$(31)$(31)
Current liabilities$(5)$(5)$— $— 
Noncurrent liabilities(116)(149)(31)(31)
Balance at December 31$(121)$(154)$(31)$(31)
(a) - The benefit obligation for Retirement Benefits at December 31, 2025 and 2024, included the supplemental executive retirement plan obligation.
(b) - Fair value of plan assets for Retirement Benefits excluded the assets of our supplemental executive retirement plan, which totaled $90 million and $92 million at December 31, 2025 and 2024, respectively, and are included in other assets on the Consolidated Balance Sheets. These assets are maintained in a rabbi trust and are not treated as assets of the supplemental executive retirement plan.

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The accumulated benefit obligation for our retirement plans was $648 million and $628 million at December 31, 2025 and 2024, respectively.

The components of net periodic benefit cost and related assumptions, and amounts recognized in other comprehensive income related to our retirement and other postretirement benefit plans are not material. The balance in accumulated other comprehensive loss at December 31, 2025 and 2024, was $46 million and $58 million, respectively. This balance is expected to be amortized over the average remaining service period of employees participating in these plans.

Actuarial Assumptions - The following table sets forth the weighted-average assumptions used to determine benefit obligations for retirement and other postretirement benefits for the periods indicated:
Retirement BenefitsOther Postretirement Benefits
December 31,December 31,
 2025202420252024
Discount rate5.70%5.80%5.70%5.80%
Compensation increase rate3.48%3.65%NANA
Interest credit rating (a)
4.84%4.78%NANA
(a) - This actuarial assumption is only applicable to the pension plans assumed with the Magellan Acquisition.

We determine our discount rates annually utilizing portfolios of high-quality bonds matched to the estimated benefit cash flows of our retirement and other postretirement benefit plans. Bonds selected to be included in the portfolios are only those rated by S&P or Moody’s as an AA or Aa2 rating or better and exclude callable bonds, bonds with less than a minimum issue size, yield outliers and other filtering criteria to remove unsuitable bonds.

Plan Assets - Our investment strategy is to invest plan assets in accordance with sound investment practices that emphasize long-term fundamentals. The goal of this strategy is to maximize investment returns while managing risk in order to meet the plan’s current and projected financial obligations. The investment allocation for our ONEOK Retirement Plan follows a glide path approach of liability-driven investing that shifts a higher portfolio weighting to fixed income as the plan’s funded status increases. A majority of the assets of the Magellan Pension Plan and the Magellan Pension Plan for USW Employees are allocated to fixed income securities and invested to match the duration of the plans’ short, intermediate and long-term liabilities, with the remaining amount allocated to equity securities. Our pension plans utilize a diversified mix of investments that may include domestic and international equities, short, intermediate and long-term corporate and government obligations, real estate and hedge funds. The combined target allocation for the assets of our pension plans as of December 31, 2025, is as follows:

Domestic and international equities30 %
Long duration fixed income58 %
Return-seeking credit4 %
Hedge funds5 %
Real estate funds3 %
Total100 %
As part of our risk management for the plans, minimums and maximums have been set for each of the asset classes listed above.

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The fair value of the plan assets for our other postretirement benefit plans as of December 31, 2025, are not material. The following tables set forth the plan assets by fair value category as of the measurement date for our defined benefit pension plans:
Pension Benefits
December 31, 2025
Asset CategoryLevel 1Level 2Level 3SubtotalMeasured at NAV (d)Total
 
(Millions of dollars)
Investments:    
Equity securities$73 $— $— $73 $— $73 
Cash and money market funds8 — — 8 — 8 
Government obligations
34 — — 34 — 34 
Corporate obligations
122 — — 122 — 122 
Common/collective trusts
Equity securities (a)— — — — 102 102 
Real estate funds— — — — 17 17 
Government obligations— — — — 66 66 
Corporate obligations (b)— — — — 130 130 
Short-term investments— — — — 6 6 
Other investments (c)— — — — 28 28 
Fair value of plan assets$237 $— $— $237 $349 $586 
(a) - This category represents securities of the respective market sector from diverse industries.
(b) - This category represents bonds from diverse industries.
(c) - This category represents alternative investments in limited partnerships, which can be redeemed with a 30-day notice with no further restrictions. There were no unfunded capital commitments. These limited partnerships invest through multi-strategy programs in broadly diversified portfolios of private investment funds, hedge funds and/or separate accounts to seek equity-like returns with low market correlation, reduced volatility and limited risk.
(d) - Plan asset investments measured at fair value using the net asset value per share.
Pension Benefits
December 31, 2024
Asset CategoryLevel 1Level 2Level 3SubtotalMeasured at NAV (d)Total
 
(Millions of dollars)
Investments:    
Equity securities$64 $— $— $64 $— $64 
Cash and money market funds7 — — 7 — 7 
Government obligations
36 — — 36 — 36 
Corporate obligations
101 — — 101 — 101 
Common/collective trusts
Equity securities (a)— — — — 107 107 
Real estate funds— — — — 18 18 
Government obligations— — — — 50 50 
Corporate obligations (b)— — — — 118 118 
Short-term investments— — — — 5 5 
Other investments (c)— — — — 29 29 
Fair value of plan assets$208 $— $— $208 $327 $535 
(a) - This category represents securities of the respective market sector from diverse industries.
(b) - This category represents bonds from diverse industries.
(c) - This category represents alternative investments in limited partnerships, which can be redeemed with a 30-day notice with no further restrictions. There were no unfunded capital commitments. These limited partnerships invest through multi-strategy programs in broadly diversified portfolios of private investment funds, hedge funds and/or separate accounts to seek equity-like returns with low market correlation, reduced volatility and limited risk.
(d) - Plan asset investments measured at fair value using the net asset value per share.


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Contributions - During 2025, we contributed $9 million to our ONEOK Retirement Plan, $17 million to our Magellan Pension Plan and $3 million to our Magellan Pension Plan for USW Employees, all of which were related to the 2024 plan year. We do not expect contributions to our defined benefit pension plans to be material in 2026. We do not expect to make any contributions to other postretirement benefit plans in 2026.

Pension and Other Postretirement Benefit Payments - Benefit payments for our defined benefit pensions and other postretirement benefit plans for the period ending December 31, 2025, were $38 million and $4 million, respectively. The following table sets forth the defined benefit pension and other postretirement benefits payments expected to be paid in 2026 through 2035:
 Pension
Benefits		Other Postretirement
Benefits
Benefits to be paid in:
(Millions of dollars)
2026$47 $4 
2027$47 $4 
2028$49 $4 
2029$52 $4 
2030$53 $4 
2031 through 2035$280 $17 

The expected benefits to be paid are based on the same assumptions used to measure our benefit obligation at December 31, 2025, and include estimated future employee service.

Other Employee Benefit Plans

401(k) Plan - The ONEOK 401(k) Plan covers all employees, and employee contributions are discretionary. We match 100% of employee 401(k) Plan contributions up to 6% of each participant’s eligible compensation, subject to certain conditions and limits. 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. Our contributions made to the plan, including profit-sharing contributions, were $128 million, $66 million and $44 million in 2025, 2024 and 2023, respectively.

EnLink terminated the EnLink 401(k) Plan effective January 30, 2025, prior to the closing of the EnLink Acquisition. Legacy EnLink employees were permitted to roll their EnLink 401(k) Plan account balance to the ONEOK 401(k) Plan, an individual retirement account or take a distribution. The EnLink 401(k) Plan was liquidated and closed in December 2025.

Medallion terminated the Medallion 401(k) Plan effective October 30, 2024, prior to the closing of the Medallion Acquisition on October 31, 2024. Legacy Medallion employees were permitted to roll their Medallion 401(k) Plan account balance to the ONEOK 401(k) Plan or an individual retirement account or take a distribution. The Medallion 401(k) Plan was liquidated and closed in September 2025.

Magellan terminated the Magellan 401(k) Plan effective September 24, 2023, prior to the closing of the Magellan Acquisition. Legacy Magellan employees were given the option to roll their Magellan 401(k) Plan account balance to the ONEOK 401(k) Plan or an individual retirement account or take a distribution. The Magellan 401(k) Plan was liquidated and closed in September 2024.

Nonqualified Deferred Compensation Plan - The 2020 Nonqualified Deferred Compensation Plan and its predecessor nonqualified deferred compensation plans (collectively, the NQDC Plan) provide a select group of management and highly compensated employees, as approved by our chief executive officer, with the option to defer portions of their compensation and receive notional employer contributions that generally are not available due to limitations on employer and employee contributions to qualified defined contribution plans under federal tax laws. Our investments which are included in other assets on the Consolidated Balance Sheets related to the NQDC Plan were not material. These investments are maintained in a rabbi trust. Our contributions to the plan were not material.

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M.    INCOME TAXES

The following table sets forth our provision for income taxes for the periods indicated:
 Years Ended December 31,
 202520242023
 (Millions of dollars)
Current tax expense (benefit)
Federal$49 $89 $(3)
State22 20 12 
Total current tax expense71 109 9 
Deferred tax expense
Federal888 792 739 
State69 97 90 
Total deferred tax expense957 889 829 
Total provision for income taxes$1,028 $998 $838 

The following table is a reconciliation of our income tax provision for the periods indicated:
Years Ended December 31,
 202520242023
(Millions of dollars, except for percentages)
 (b)(b)(b)
Income before income taxes
$4,490 $4,110 $3,497 
Federal statutory income tax rate21.0 %21.0 %21.0 %
Provision for federal income taxes943 21.0 %863 21.0 %734 21.0 %
State income taxes, net of federal tax benefit (a)91 2.0 %125 3.0 %102 2.9 %
Nontaxable or nondeductible items(6)(0.1)%3 0.1 %(1)— %
Other, net— — %7 0.2 %3 0.1 %
Income tax provision$1,028 22.9 %$998 24.3 %$838 24.0 %
(a) - Our operations are primarily apportioned across Oklahoma, Texas, Kansas and North Dakota for state income tax purposes.
(b) - Represents percent of income before income taxes.

The following table sets forth cash paid for income taxes, net of refunds, for the periods indicated:
 Years Ended December 31,
 202520242023
 (Millions of dollars)
Federal$52 $85 $27 
State22 17 10 
Total cash paid for income taxes, net of refunds$74 $102 $37 
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The following table sets forth the tax effects of temporary differences that gave rise to significant portions of the deferred tax assets and liabilities as of the dates indicated:

December 31,
2025		December 31,
2024
Deferred tax assets
(Millions of dollars)
Employee benefits and other accrued liabilities$98 $99 
Federal net operating loss2,570 2,818 
Federal tax credit6 — 
State net operating loss and benefits546 515 
Derivative instruments— 15 
Interest expense limitation237 407 
Other17 39 
Total deferred tax assets3,474 3,893 
Valuation allowance for state net operating loss and tax credits
Carryforward expected to expire prior to utilization(267)(252)
Net deferred tax assets3,207 3,641 
Deferred tax liabilities
Excess of tax over book depreciation92 58 
Derivative instruments5 — 
Investment in partnerships (a)9,459 9,034 
Total deferred tax liabilities9,556 9,092 
Net deferred tax liabilities$6,349 $5,451 
(a) Due primarily to excess of tax over book depreciation.

On January 31, 2025, we completed the EnLink Acquisition by acquiring all of the remaining and outstanding publicly held EnLink Units. EnLink is now a wholly owned subsidiary and included in our consolidated income tax returns.

As of December 31, 2025, we have federal net operating loss carryforwards of $12.2 billion, which have an indefinite carryforward period. We expect to generate taxable income and utilize these net operating loss carryforwards in future periods. We also have loss and credit carryovers in multiple states, $13.2 billion of which, have an indefinite carryforward period and $1.2 billion of which will expire between 2029 and 2043. We have deferred tax assets related to federal and state net operating loss and credit carryforwards of $3.1 billion and $3.3 billion in 2025 and 2024, respectively. We believe that it is more likely than not that the tax benefits of certain state carryforwards will not be utilized; therefore, we recorded a valuation allowance, which was increased by $15 million, $12 million and $165 million in 2025, 2024 and 2023, respectively, through net income.

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N.    UNCONSOLIDATED AFFILIATES

Investments in Unconsolidated Affiliates - The following table sets forth our investments in unconsolidated affiliates as of the dates indicated:
Net Ownership InterestDecember 31,
2025		December 31, 2024
(Millions of dollars)
BridgeTex (a)60%$504 $250 
Northern Border50%444 333 
Overland Pass50%391 400 
Saddlehorn 40%361 373 
Matterhorn (b)15%272 248 
MVP25%228 235 
Roadrunner50%181 183 
Texas City Logistics50%162 — 
OtherVarious346 294 
  Investments in unconsolidated affiliates (c)$2,889 $2,316 
(a) - In July 2025, we purchased an additional 30% interest in BridgeTex, resulting in a 60% ownership interest.
(b) - As of December 31, 2025, the 15% interest represented ONEOK’s ownership interest in Matterhorn as a result of the EnLink Acquisition on January 31, 2025. As of December 31, 2024, the 15% interest represented EnLink’s ownership interest in Matterhorn.
(c) - Included basis differences of $431 million and $368 million at December 31, 2025, and 2024, respectively, related to property, plant and equipment and equity-method goodwill (Note A).

Equity in Net Earnings from Investments - The following table sets forth our equity in net earnings from investments for the periods indicated:
Years Ended December 31,
202520242023
(Millions of dollars)
Northern Border$105 $95 $75 
Overland Pass91 86 56 
Saddlehorn (a)50 50 10 
BridgeTex (a)(c)41 127 (1)
Roadrunner41 40 43 
Matterhorn (b)24 8 — 
MVP (a)13 14 4 
Other21 19 15 
Equity in net earnings from investments$386 $439 $202 
(a) - The year ended December 31, 2023, included equity in net earnings from the period September 25, 2023, through December 31, 2023.
(b) - The year ended December 31, 2024, included equity in net earnings from the period October 15, 2024, through December 31, 2024.
(c) - The year ended December 31, 2024, included equity in net earnings of $88 million on BridgeTex associated with the nonrecurring recognition of deferred revenue.

We incurred expenses in transactions with unconsolidated affiliates of $280 million, $254 million and $132 million for 2025, 2024 and 2023, respectively, primarily related to Overland Pass, Matterhorn and Northern Border. Revenue earned and accounts receivable from, and accounts payable to, our unconsolidated affiliates were not material.

We have agreements with our unconsolidated affiliates which provide that distributions to members are made, primarily, on a pro rata basis according to each member’s ownership interest.

We are the operator of Roadrunner, BridgeTex, MVP and Saddlehorn. In each case, we have operating agreements that provide for reimbursement or payment to us for management services and certain operating costs. Reimbursements and payments included in operating income in our Consolidated Statements of Income for all periods presented were not material.



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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. 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. Our investment in Eiger is accounted for using the equity method as we have the ability to exercise significant influence over the operating and financial policies of Eiger, although we do not have the ability to exercise control.

On July 22, 2025, we completed the BridgeTex Additional Interest Acquisition. Pursuant to the purchase agreement, we paid approximately $270 million in cash, which we funded with short-term borrowings. Following the completion of the transaction, we now have a 60% ownership interest in BridgeTex. Our investment in BridgeTex continues to be accounted for using the equity method as we continue to have the ability to exercise significant influence over the operating and financial policies of BridgeTex, although we do not have the ability to exercise control.

On February 4, 2025, we announced definitive agreements to form 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. 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. Our investment in Texas City Logistics is accounted for using the equity method as we have the ability to exercise significant influence over the operating and financial policies of Texas City Logistics, although we do not have the ability to exercise control.

In 2025, we made equity contributions to Texas City Logistics and Northern Border of $160 million and $101 million, respectively, which, in combination with equal contributions from our joint venture partners, were primarily used for funding capital projects. In 2024, we acquired an additional 10% interest in Saddlehorn, resulting in a total ownership interest of 40%. In 2023, we made an equity contribution of $105 million to Roadrunner, which, in combination with an equal contribution from our joint venture partner, was used to repay Roadrunner’s outstanding debt. Also in 2023, we made an equity contribution of $91 million to Northern Border, which, in combination with an equal contribution from our joint venture partner, was used to partially repay the outstanding balance of its revolving credit facility and fund capital projects.

O.    COMMITMENTS AND CONTINGENCIES

Commitments - The following table sets forth our transportation, volume and storage commitments for the periods indicated:
Commitments
(Millions of dollars)
2026$286 
2027272 
2028253 
2029238 
2030229 
Thereafter870 
Total$2,148 

Regulatory, Environmental and Safety Matters - The operation of pipelines, terminals, plants and other facilities for the gathering, processing, fractionation, transportation and storage of products is subject to numerous and complex laws and regulations pertaining to health, safety and the environment. As an owner and/or operator of these facilities, we must comply with laws and regulations that relate to air and water quality, hazardous and solid waste management and disposal, cultural resource protection and other environmental and safety matters. The cost of planning, designing, constructing and operating pipelines, terminals, plants and other facilities must incorporate compliance with these laws, regulations and safety standards. Failure to comply with these laws and regulations may trigger a variety of administrative, civil and potentially criminal enforcement measures, including citizen suits, which can include the assessment of monetary penalties, the imposition of remedial requirements and the issuance of injunctions or restrictions on operation or construction. Management does not believe that, based on currently known information, a material risk of noncompliance with these laws and regulations exists that will adversely affect our consolidated results of operations, financial condition or cash flows.

Legal Proceedings - We are a party to various legal proceedings that have arisen in the normal course of our operations. While the results of these proceedings cannot be predicted with certainty, we believe the reasonably possible losses from such proceedings, individually and in the aggregate, are not material. Additionally, we believe the probable final outcome of such proceedings will not have a material adverse effect on our consolidated results of operations, financial position or cash flows.

109
P.    LEASES

Lessee activity - The following table sets forth information about our operating lease assets and liabilities included in our Consolidated Balance Sheets as of the dates indicated:
LeasesLocation in our Consolidated Balance SheetsDecember 31,
2025		December 31,
2024
 
(Millions of dollars)
Operating lease assets
Other assets$245 $220 
Operating lease liabilities
Current
Other current liabilities
$54 $62 
Noncurrent
Other deferred credits
183 154 
Total operating lease liabilities
$237 $216 
The weighted average remaining lease term for our operating leases was 11.0 years and 9.1 years at December 31, 2025 and 2024, respectively. The weighted average discount rate for our operating leases was 5.52% and 5.51% at December 31, 2025 and 2024, respectively. Our weighted-average discount rates represent the rate implicit in the lease or our incremental borrowing rate for a term equal to the remaining term of the lease.

The following table sets forth the maturity of our lease liabilities as of December 31, 2025:
Operating
Leases
(Millions of dollars)
2026$61 
202739 
202834 
202929 
203022 
2031 and beyond130 
Total lease payments315 
Less: Interest78 
Present value of lease liabilities$237 
Our lease costs and supplemental cash flow information related to our leases for the periods ended December 31, 2025 and 2024, are not material.

Q.    REVENUES

Unsatisfied Performance Obligations - We do not disclose the value of unsatisfied performance obligations for (i) contracts with an original expected length of one year or less and (ii) variable consideration on contracts for which we recognize revenue at the amount to which we have the right to invoice for services performed.

The following table presents aggregate value allocated to unsatisfied performance obligations as of December 31, 2025, and the amounts we expect to recognize in revenue in future periods, related primarily to firm transportation and storage contracts with remaining contract terms ranging from one month to 20 years:
Expected Period of Recognition in Revenue
(Millions of dollars)
2026$1,259 
20271,162 
2028985 
2029845 
2030 and beyond2,810 
Total$7,061 

The table above excludes variable consideration allocated entirely to wholly unsatisfied performance obligations, wholly unsatisfied promises to transfer distinct goods or services that are part of a single performance obligation and consideration we
110
determine to be fully constrained. Information on the nature of the variable consideration excluded and the nature of the performance obligations to which the variable consideration relates can be found in the description of the major contract types discussed in Note A. The amounts we determined to be fully constrained relate to future sales obligations under long-term sales contracts where the value is not known and certain minimum volume agreements, which we consider to be fully constrained until invoiced.

R.    SEGMENTS

Segment Descriptions - Our operations are divided into four reportable business segments, as follows:
•our Natural Gas Gathering and Processing segment gathers, compresses, treats, processes and markets natural gas;
•our Natural Gas Liquids segment gathers, treats, fractionates and transports NGLs and stores, markets and distributes Purity NGLs;
•our Natural Gas Pipelines segment transports, stores and markets natural gas; and
•our Refined Products and Crude segment gathers, transports, stores, distributes, blends and markets Refined Products and crude oil.

On October 15, 2024, we completed the EnLink Controlling Interest Acquisition. Our 2024 results include the impact of the EnLink Controlling Interest Acquisition from the period of October 15, 2024, to December 31, 2024, across all four of our existing operating segments. On October 31, 2024, we completed the Medallion Acquisition. Our 2024 results include the impact of the Medallion Acquisition from the period of November 1, 2024, to December 31, 2024, in our Refined Products and Crude segment.

Other and eliminations consist of corporate costs, the operating activities of our headquarters building and related parking facility, the activity of our wholly owned captive insurance company and eliminations necessary to reconcile our reportable segments to our Consolidated Financial Statements.

For the years ended December 31, 2025, and December 31, 2023, revenues from one customer impacting all our segments represented approximately 12% and 11% of our consolidated revenues, respectively. For the year ended December 31, 2024, we had no single customer from which we received 10% or more of our consolidated revenues.

The significant expense categories and amounts included in the table below align with the segment-level information that is regularly provided to the chief operating decision-maker.


111
Operating Segment Information - The following tables set forth certain selected financial information for our operating segments for the periods indicated:
Year Ended December 31, 2025Natural Gas Gathering and ProcessingNatural Gas LiquidsNatural Gas PipelinesRefined Products and CrudeTotal Segments
(Millions of dollars)
Liquids commodity sales$4,372 $15,405 $— $10,631 $30,408 
Residue natural gas sales2,137 — 1,235 — 3,372 
Exchange services and natural gas gathering and processing revenue1,137 336 — — 1,473 
Transportation and storage revenue— 258 611 2,291 3,160 
Other revenue38 11 — 117 166 
Total revenues (a)7,684 16,010 1,846 13,039 38,579 
Cost of sales and fuel (exclusive of depreciation and operating costs)(4,617)(12,533)(1,005)(10,171)(28,326)
Operating costs(988)(831)(231)(906)(2,956)
Adjusted EBITDA from unconsolidated affiliates5 101 244 166 516 
Noncash compensation expense and other54 32 7 49 142 
Segment adjusted EBITDA$2,138 $2,779 $861 $2,177 $7,955 
Depreciation and amortization$(501)$(468)$(98)$(438)$(1,505)
Equity in net earnings from investments$3 $91 $170 $122 $386 
Investments in unconsolidated affiliates$40 $652 $929 $1,263 $2,884 
Total assets$16,757 $20,415 $4,805 $25,255 $67,232 
Capital expenditures$1,314 $758 $237 $752 $3,061 
(a) - Intersegment revenues are primarily from commodity sales, which are based on the contracted selling price that is generally index-based and settled monthly. Intersegment revenues totaled $4.3 billion for the Natural Gas Gathering and Processing segment, $0.5 billion for the Natural Gas Liquids segment and were not material for the Refined Products and Crude and Natural Gas Pipelines segments.



Year Ended December 31, 2025Total SegmentsOther and EliminationsTotal
(Millions of dollars)
Reconciliations of total segments to consolidated
Liquids commodity sales$30,408 $(4,842)$25,566 
Residue natural gas sales3,372 (60)3,312 
Exchange services and natural gas gathering and processing revenue1,473 (3)1,470 
Transportation and storage revenue3,160 (23)3,137 
Other revenue166 (22)144 
Total revenues (a)$38,579 $(4,950)$33,629 
Cost of sales and fuel (exclusive of depreciation and operating costs)$(28,326)$4,953 $(23,373)
Operating costs$(2,956)$(7)$(2,963)
Depreciation and amortization$(1,505)$(9)$(1,514)
Equity in net earnings from investments$386 $— $386 
Investments in unconsolidated affiliates$2,884 $5 $2,889 
Total assets$67,232 $(591)$66,641 
Capital expenditures$3,061 $91 $3,152 
(a) - Substantially all of our revenues are related to contracts with customers.


112
Year Ended December 31, 2024Natural Gas Gathering and ProcessingNatural Gas LiquidsNatural Gas PipelinesRefined Products and CrudeTotal Segments
(Millions of dollars)
Liquids commodity sales$3,033 $14,446 $— $2,258 $19,737 
Residue natural gas sales1,203 — 137 — 1,340 
Exchange services and natural gas gathering and processing revenue260 500 — — 760 
Transportation and storage revenue70 207 684 2,082 3,043 
Other revenue23 14 1 120 158 
Total revenues (a)4,589 15,167 822 4,460 25,038 
Cost of sales and fuel (exclusive of depreciation and operating costs)(2,600)(11,994)(112)(1,949)(16,655)
Operating costs(603)(762)(233)(888)(2,486)
Adjusted EBITDA from unconsolidated affiliates3 95 187 247 532 
Noncash compensation expense20 34 8 31 93 
Other (b)75 3 228 (9)297 
Segment adjusted EBITDA$1,484 $2,543 $900 $1,892 $6,819 
Depreciation and amortization$(325)$(361)$(88)$(354)$(1,128)
Equity in net earnings from investments$— $85 $143 $211 $439 
Investments in unconsolidated affiliates$33 $484 $764 $1,031 $2,312 
Total assets$15,856 $19,797 $5,041 $23,181 $63,875 
Capital expenditures$492 $987 $258 $216 $1,953 
(a) - Intersegment revenues are primarily from commodity sales, which are based on the contracted selling price that is generally index-based and settled monthly. Intersegment revenues totaled $3.0 billion for the Natural Gas Gathering and Processing segment, $0.3 billion for the Natural Gas Liquids segment and were not material for the Refined Products and Crude and Natural Gas Pipelines segments.
(b) - Included a gain of $227 million for the Natural Gas Pipelines segment related to the sale of three of our wholly owned interstate natural gas pipeline systems to DT Midstream, Inc.
Year Ended December 31, 2024Total SegmentsOther and EliminationsTotal
(Millions of dollars)
Reconciliations of total segments to consolidated
Liquids commodity sales$19,737 $(3,287)$16,450 
Residue natural gas sales1,340 (10)1,330 
Exchange services and natural gas gathering and processing revenue760 — 760 
Transportation and storage revenue3,043 (23)3,020 
Other revenue158 (20)138 
Total revenues (a)$25,038 $(3,340)$21,698 
Cost of sales and fuel (exclusive of depreciation and operating costs)$(16,655)$3,344 $(13,311)
Operating costs$(2,486)$(10)$(2,496)
Depreciation and amortization$(1,128)$(6)$(1,134)
Equity in net earnings from investments$439 $— $439 
Investments in unconsolidated affiliates$2,312 $4 $2,316 
Total assets$63,875 $194 $64,069 
Capital expenditures$1,953 $68 $2,021 
(a) - Substantially all of our revenues are related to contracts with customers.
113
Year Ended December 31, 2023Natural Gas Gathering and ProcessingNatural Gas LiquidsNatural Gas PipelinesRefined Products and CrudeTotal Segments
(Millions of dollars)
Liquids commodity sales$2,479 $13,666 $— $502 $16,647 
Residue natural gas sales1,398 — 39 — 1,437 
Gathering, processing and exchange services revenue147 549 — — 696 
Transportation and storage revenue— 204 582 535 1,321 
Other revenue32 10 2 34 78 
Total revenues (a)4,056 14,429 623 1,071 20,179 
Cost of sales and fuel (exclusive of depreciation and operating costs)(2,364)(11,592)(28)(450)(14,434)
Operating costs(467)(666)(202)(198)(1,533)
Adjusted EBITDA from unconsolidated affiliates 1 67 160 36 264 
Noncash compensation expense19 29 8 6 62 
Other (b)(1)778 (2)— 775 
Segment adjusted EBITDA$1,244 $3,045 $559 $465 $5,313 
Depreciation and amortization$(272)$(334)$(67)$(92)$(765)
Equity in net earnings from investments$(2)$58 $118 $28 $202 
Investments in unconsolidated affiliates$24 $419 $526 $903 $1,872 
Total assets$7,078 $14,974 $2,624 $19,531 $44,207 
Capital expenditures$448 $818 $228 $52 $1,546 
(a) - Intersegment revenues are primarily from commodity sales, which are based on the contracted selling price that is generally index-based and settled monthly. Intersegment revenues for the Natural Gas Gathering and Processing segment totaled $2.4 billion and were not material for the Natural Gas Liquids, Refined Products and Crude and Natural Gas Pipelines segments.
(b) - Included a settlement gain of $779 million for the Natural Gas Liquids segment related to the Medford incident.

Year Ended December 31, 2023Total SegmentsOther and EliminationsTotal
(Millions of dollars)
Reconciliations of total segments to consolidated
Liquids commodity sales$16,647 $(2,480)$14,167 
Residue natural gas sales1,437 — 1,437 
Gathering, processing and exchange services revenue696 — 696 
Transportation and storage revenue1,321 (15)1,306 
Other revenue78 (7)71 
Total revenues (a)$20,179 $(2,502)$17,677 
Cost of sales and fuel (exclusive of depreciation and operating costs)$(14,434)$2,505 $(11,929)
Operating costs$(1,533)$(2)$(1,535)
Depreciation and amortization$(765)$(4)$(769)
Equity in net earnings from investments$202 $— $202 
Investments in unconsolidated affiliates$1,872 $2 $1,874 
Total assets$44,207 $59 $44,266 
Capital expenditures$1,546 $49 $1,595 
(a) - Substantially all of our revenues are related to contracts with customers.
114
Years Ended December 31,
202520242023
Reconciliation of income before income taxes to total segment adjusted EBITDA(Millions of dollars)
Income before income taxes$4,490 $4,110 $3,497 
Interest expense, net of capitalized interest1,783 1,371 866 
Depreciation and amortization1,514 1,134 769 
Adjusted EBITDA from unconsolidated affiliates
516 532 264 
Equity in net earnings from investments(386)(439)(202)
Noncash compensation expense and other (a)103 76 49 
Corporate other (b)(65)35 70 
Total segment adjusted EBITDA (c)(d)$7,955 $6,819 $5,313 
(a) - The year ended December 31, 2025, included noncash transaction costs related primarily to the EnLink Acquisition of $16 million included within noncash compensation expense and other.
(b) - The year ended December 31, 2025, included corporate net gains on extinguishment of debt of $106 million in connection with open market repurchases and interest income of $33 million, offset partially by transaction costs related primarily to the EnLink Acquisition of $65 million. The year ended December 31, 2024, included transaction costs related primarily to the EnLink Acquisitions and Medallion Acquisition of $73 million, offset partially by interest income of $39 million. The year ended December 31, 2023, included transaction costs related to the Magellan Acquisition of $158 million, offset partially by interest income of $49 million and corporate net gains on extinguishment of debt of $41 million in connection with open market repurchases.
(c) - The year ended December 31, 2024, included a gain of $227 million from the interstate natural gas pipeline divestiture.
(d) - The year ended December 31, 2023, included $633 million related to the Medford incident, including a settlement gain of $779 million, offset partially by $146 million of third-party fractionation costs.

ITEM 9.    CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE

None.

ITEM 9A.    CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

Our Chief Executive Officer (Principal Executive Officer) and Chief Financial Officer (Principal Financial Officer) have concluded that our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) of the Exchange Act) were effective as of the end of the period covered by this report.

Management’s Report on Internal Control over Financial Reporting

Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Rule 13a-15(f) and 15d-15(f) of the Exchange Act. Under the supervision and with the participation of our management, including our Principal Executive Officer and Principal Financial Officer, we evaluated the effectiveness of our internal control over financial reporting based on the framework in Internal Control-Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Because of inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. Based on our evaluation under that framework, our management concluded that our internal control over financial reporting was effective as of December 31, 2025.

The effectiveness of our internal control over financial reporting as of December 31, 2025, has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report which is included herein (Item 8).

Changes in Internal Control over Financial Reporting

There have been no changes in our internal control over financial reporting during the quarter ended December 31, 2025, that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

115
ITEM 9B.    OTHER INFORMATION

During the three months ended December 31, 2025, no director or officer of the Company adopted or terminated a “Rule 10b5-1 trading arrangement” or “non-Rule 10b5-1 trading arrangements,” as each term is defined in item 408(a) Regulation S-K.

ITEM 9C.    DISCLOSURE REGARDING FOREIGN JURISDICTIONS THAT PREVENT INSPECTIONS

Not applicable.

PART III

ITEM 10.    DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

Directors of the Registrant

Information concerning our directors is set forth in our 2026 definitive Proxy Statement and is incorporated herein by this reference.

Executive Officers of the Registrant

Information concerning our executive officers is included in Part I, Item 1, Business, of this Annual Report.

Compliance with Section 16(a) of the Exchange Act

Information on compliance with Section 16(a) of the Exchange Act is set forth in our 2026 definitive Proxy Statement and is incorporated herein by this reference.

Code of Ethics

Information concerning the code of ethics, or code of business conduct, is set forth in our 2026 definitive Proxy Statement and is incorporated herein by this reference.

Corporate Governance

Information concerning our corporate governance is set forth in our 2026 definitive Proxy Statement and is incorporated herein by this reference.

Insider Trading Policy

We have adopted insider trading policies and procedures that govern the purchase, sale and other disposition of our securities by our directors, officers and employees that we believe are reasonably designed to promote compliance with insider trading laws, rules and regulations and the listing standards of the NYSE. A copy of our Insider Trading Policy is filed with this Annual Report as Exhibit 19.

ITEM 11.    EXECUTIVE COMPENSATION

Information on executive compensation is set forth in our 2026 definitive Proxy Statement and is incorporated herein by this reference.

ITEM 12.    SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

Security Ownership of Certain Beneficial Owners

Information concerning the ownership of certain beneficial owners is set forth in our 2026 definitive Proxy Statement and is incorporated herein by this reference.

116
Security Ownership of Management

Information on security ownership of directors and officers is set forth in our 2026 definitive Proxy Statement and is incorporated herein by this reference.

Equity Compensation Plan Information

The following table sets forth certain information concerning our equity compensation plans as of December 31, 2025:
Plan Category
Number of Securities
to be Issued
Upon Exercise of
Outstanding Options,
Warrants and Rights (3)
Weighted-Average
Exercise Price of
Outstanding Options,
Warrants and Rights (4)
Number of Securities
Remaining Available For
Future Issuance Under
Equity Compensation
Plans (5)
Equity compensation plans
approved by security holders (1)
3,529,356 — 20,166,969 
Equity compensation plans
not approved by security holders (2)
132,261 — — 
Total3,661,617 — 20,166,969 
(1) - Included our Employee Stock Purchase Plan, 2025 Employee Stock Award Program, Equity Compensation Plan, 2018 Equity Incentive Plan and 2025 Equity Incentive Plan. For a brief description of the material features of these plans, see Note K of the Notes to Consolidated Financial Statements in this Annual Report.
(2) - Included the assumed EnLink Midstream, LLC, Long-Term Incentive Plan. For a brief description of the material features of this plan, see Note K of the Notes to Consolidated Financial Statements in this Annual Report.
(3) - Included grants of restricted stock unit awards, performance awards and director stock awards deferred as phantom stock units under our Deferred Compensation Plan for Non-Employee Directors.
(4) - There is no exercise price associated with restrictive stock unit awards, performance unit awards or director stock awards as phantom stock units under our Deferred Compensation Plan for Non-Employee Directors.
(5) - Included 969,316, 633,084 and 18,564,569 shares available for future issuance under our Employee Stock Purchase Plan, 2025 Employee Stock Award Program and 2025 Equity Incentive Plan, respectively.

ITEM 13.    CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

Information on certain relationships and related transactions and director independence is set forth in our 2026 definitive Proxy Statement and is incorporated herein by this reference.

ITEM 14.    PRINCIPAL ACCOUNTING FEES AND SERVICES

Information concerning the principal accountant’s fees and services is set forth in our 2026 definitive Proxy Statement and is incorporated herein by this reference.

117
PART IV

ITEM 15.    EXHIBITS, FINANCIAL STATEMENT SCHEDULES
(1) Financial StatementsPage No.
(a)
Report of Independent Registered Public Accounting Firm (PCAOB ID: 238)
(b)Consolidated Statements of Income for the years ended
December 31, 2025, 2024 and 2023
(c)Consolidated Statements of Comprehensive Income for the years ended
December 31, 2025, 2024 and 2023
(d)Consolidated Balance Sheets as of December 31, 2025 and 2024
(e)Consolidated Statements of Cash Flows for the years ended
December 31, 2025, 2024 and 2023
(f)Consolidated Statements of Changes in Equity for the years ended
December 31, 2025, 2024 and 2023
(g)Notes to Consolidated Financial Statements
(2) Financial Statements Schedules
All schedules have been omitted because of the absence of conditions under which they are required.
(3) Exhibits
2
2.1
2.2
2.3
3
3.1
118
Table of Contents
3.2
3.3
3.4
4
4.1
4.2
4.3
4.4
4.5
4.6
4.7
4.8
119
Table of Contents
4.9
4.10
4.11
4.12
4.13
4.14
4.15
4.16
4.17
4.18
4.19
120
Table of Contents
4.20
4.21
4.22
4.23
4.24
4.25
4.26
4.27
4.28
4.29
4.30
121
Table of Contents
4.31
4.32
4.33
4.34
4.35
4.36
4.37
4.38
4.39
4.40
122
Table of Contents
4.41
4.42
4.43
4.44
4.45
4.46
4.47
4.48
4.49
4.50
123
Table of Contents
4.51
4.52
4.53
4.54
4.55
4.56
4.57
4.58
4.59
4.60
4.61
124
Table of Contents
4.62
4.63
4.64
4.65
4.66
4.67
4.68
4.69
4.70
4.71
4.72
125
Table of Contents
4.73
4.74
4.75
4.76
4.77
4.78
4.79
4.80
4.81
4.82
126
Table of Contents
4.83
4.84
4.85
4.86
4.87
4.88
10
10.1
10.2
10.3
10.4
10.5
10.6
127
Table of Contents
10.7
10.8
10.9
10.10
10.11
10.12
10.13
10.14
10.15
10.16
10.17
10.18
10.19
10.20
10.21
128
Table of Contents
10.22
10.23
10.24*
10.25
10.26
10.27
10.28
19
21
22.1
23
31.1
31.2
32.1
32.2
97
101.INSInline XBRL Instance Document - the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document.
101.SCHInline XBRL Taxonomy Extension Schema Document.
101.CALInline XBRL Taxonomy Calculation Linkbase Document.
129
Table of Contents
101.DEFInline XBRL Taxonomy Extension Definitions Document.
101.LABInline XBRL Taxonomy Label Linkbase Document.
101.PREInline XBRL Taxonomy Presentation Linkbase Document.
104Cover Page Interactive Data File (formatted in Inline XBRL and contained in Exhibit 101).
*Certain annexes, schedules and exhibits have been omitted pursuant to Item 601(a)(5) of Regulation S-K. ONEOK undertakes to furnish supplemental copies of any of the omitted annexes, schedules and exhibits to the SEC upon its request.

Attached as Exhibit 101 to this Annual Report are the following Inline XBRL-related documents: (i) Document and Entity Information; (ii) Consolidated Statements of Income for the years ended December 31, 2025, 2024 and 2023; (iii) Consolidated Statements of Comprehensive Income for the years ended December 31, 2025, 2024 and 2023; (iv) Consolidated Balance Sheets at December 31, 2025 and 2024; (v) Consolidated Statements of Cash Flows for the years ended December 31, 2025, 2024 and 2023; (vi) Consolidated Statements of Changes in Equity for the years ended December 31, 2025, 2024 and 2023 and (vii) Notes to Consolidated Financial Statements.

ITEM 16.    FORM 10-K SUMMARY

None.

130
SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Exchange Act, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

 ONEOK, Inc.
 Registrant
  
Date: February 24, 2026By:/s/ Walter S. Hulse III
 Walter S. Hulse III
 Chief Financial Officer, Treasurer and
 Executive Vice President, Investor Relations
and Corporate Development
 (Principal Financial Officer)

Pursuant to the requirements of the Exchange Act, this report has been signed below by the following persons on behalf of the registrant and in the capacities indicated on this 24th day of February 2026.

/s/ Julie H. Edwards /s/ Pierce H. Norton II
Julie H. Edwards Pierce H. Norton II
Board Chair President, Chief Executive Officer and
Director
/s/ Walter S. Hulse III /s/ Mary M. Spears
Walter S. Hulse III Mary M. Spears
Chief Financial Officer, Treasurer and  Senior Vice President and Chief
Executive Vice President, Investor Accounting Officer, Finance and Tax
Relations and Corporate Development
/s/ Brian L. Derksen 
/s/ Pattye L. Moore
Brian L. Derksen 
Pattye L. Moore
Director Director
/s/ Lori A. Gobillot
/s/ Precious W. Owodunni
Lori A. Gobillot
Precious W. Owodunni
Director
Director
/s/ Mark W. Helderman /s/ Eduardo A. Rodriguez
Mark W. Helderman Eduardo A. Rodriguez
Director Director
/s/ Randall J. Larson/s/ Gerald B. Smith
Randall J. LarsonGerald B. Smith
DirectorDirector
/s/ Mark A. McCollum
/s/ Wayne T. Smith
Mark A. McCollum
Wayne T. Smith
Director
Director
131

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