OKE 10-K & 10-Q changes, risk factors and insider trading

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 adversely our business, results of operations, financial position and cash flows.

Our operating results may be adversely affected adversely 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 adversely 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. Also, economic conditions following the COVID-19 pandemic included increased inflation. While inflation has declined since the second half of 2022, inflationaryInflationary 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 causedcould cause the Federal Reserve System and other central banks to increase interest rates, which maycould cause the cost of capital to increase and depress economic growth, either of which, or the combination of both, could adversely affect adversely our business, results of operations, financial position and cash flows.

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

•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 recent agreements relating to production decisions;

•public health crises, including pandemics (such as COVID-19);

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

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 adversely our business, results of operations, financial position and cash flows.

Our operations are subject to operational hazards and unforeseen interruptions, which could adversely affect adversely 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 (such as COVID-19),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 adversely 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 adversely 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.

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 adversely our results of operations.

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

To manage the risk from market price fluctuations in natural gas, NGLs, Refined Products and crude oil and electricity prices, we may use derivative instruments such as swaps, futures, forwards and options. However, weWe do not hedge fully against commodity price changes, and we therefore retain some exposure to market risk. Further, 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. Finally, 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 adversely our operations, financial results or reputation.

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 adversely our business and results of operations. Our financial results could also be adversely affected adversely 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.

Terrorist attacks, including cyber sabotage, aimed at our facilities could adversely affect adversely 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. For example, in May 2021, a ransomware attack on a major U.S. Refined Products pipeline forced the operator to temporarily shut down the pipeline, resulting in disruption of fuel supplies along the East Coast. 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.

•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 materialsmaterials, 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 adversely our business, results of operations, financial position and cash flows.

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 adversely our business, results of operations, financial position and cash flows.

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 adversely our business, results of operations, financial position and cash flows.

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 adversely our business, results of operations, financial position and cash flows.

Our pipeline, processing, fractionation, terminal and storage assets compete with other similar assets for natural gas, NGL,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 adversely our business, results of operations, financial position and cash flows.

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 adversely 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, as discussed in Note ON 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 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 theseactivities morerequiring significantjoint-venture activitiesparticipant approval are large expenditures or contractual commitments, the construction or acquisition of assets, borrowing moneycash 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.

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 adversely 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 adversely our business and results of operations.

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 adversely our results of operations, financial position and cash flows. The historical EnLink NOL carryforward acquired upon the completion of the EnLink Acquisition is expected to be subject to limitations under Section 382 of the Code.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.

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 results of FERC’s last five-year review were subject to appeal at the D.C. Circuit, which vacated FERC’s orders and remanded to FERC. FERC subsequently issued a supplemental notice of proposed rulemaking proposing to reduce the index price back down to the rehearing order price and the proposal is now pending at FERC.

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 energyidentification credits,numbers, called RINs, under the Renewable Fuel Standard Program to meet this obligation. Increases in the cost or decreases in the availability of RINsRINs, as well as any volatility in such costs or availability, could have an adverse impact on our business.

GHG emissions in the midstream industry originate primarily from combustion engine exhaust,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, and the United States Supreme Court has ruled that carbon dioxide is a pollutant subject to regulation by the EPA.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. ForIn example,the past, the Inflation Reduction Act of 2022 (IRA) directshad 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. Based on text in the IRA and a related rule that the EPA finalized in November 2024 to implement the Methane Fee program, we expect to begin paying Methane Fees in 2025 (for 2024 reported emissions) for applicable facilities. In January 2025, industry associations and certain states challenged the Waste Emissions Charge rule in the D.C. Circuit, andHowever, 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, 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 adversely 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 adversely our business.

•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;

Various federal and state governmental authorities, including the EPA,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 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 PO 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 more aggressiveincreased 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 adversely our business, results of operations, financial position or cash flows.

Changes in interest rates could adversely affect adversely our business.

Any reduction in our credit ratings could adversely affect adversely 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 adversely 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.

As of Dec.December 31, 2024,2025, we had total indebtedness of $33.2$34.0 billion. Our indebtedness and guarantee obligations could have significant consequences. For example, they could:

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 adversely our ability to repay our other indebtedness.

Acquisitions and Divestitures

EnLink Acquisition - On Nov. 24, 2024, we entered into the EnLink Merger Agreement to acquire all of the publicly held EnLink Units in an all stock, tax-free transaction. On Jan.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,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 and divestiture,acquisitions, see Part II, Item 8, Note B of the Notes to Consolidated Financial Statements in this Annual Report. See Part 1,I, Item 1A “Risk Factors” for further discussion of risks related to these transactions.

JointTexas VenturesCity Logistics and MBTC Pipeline - OnIn Feb. 4,February 2025, we entered intoannounced definitive agreements to form joint ventures with MPLX LP (MPLX) 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 LLC,Logistics, the export terminal joint venture, is owned 50% by us and 50% by MPLX,MPLX LP, with MPLX LP constructing and operating the facility. MBTC Pipeline LLC,Pipeline, the pipeline joint venture, is owned 80% by us and 20% by MPLX,MPLX LP, and we will construct and operate the pipeline. We expect to invest a total of approximately $1.0 billion ininto these projects.projects, which are expected to be completed in early 2028.

Market ConditionConditions - Earnings increased in 2024,2025, compared with 2023,2024, due primarily to a full year of earnings from our new Refined ProductsEnLink and CrudeMedallion segment,across our segments and higher NGL and natural gas processing volumes in the Rocky Mountain region and the impact of the interstate pipeline divestiture in the Natural Gas Pipelines segment.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.

(cb) - 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.

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

Debt Repayments(a) - In December 2024, weAmounts redeemed our $500 million, 4.9% senior notes due March 2025 at 100% of the principal amount, plus accrued and unpaid interest, with cash on hand.interest.

Share Repurchase Program - In January 2024, ourOur 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. We expect any purchases to be funded by cash on hand, cash flow from operations and short-term borrowings. The program will terminate upon completion of the repurchase of the $2.0 billion of common stock or on Jan.January 1, 2029, whichever occurs first. AsFor ofthe Feb.year 17,ended December 31, 2025, we repurchased 1.675$62 million sharesof forour $172outstanding millioncommon understock thewith program.cash on hand.

Dividends - During 2024,2025, we paid common stock dividends totaling $3.96$4.12 per share, an increase of 3.7%4% compared to the 20232024 dividend of $3.82$3.96 per share. In February 2025,2026, we paid a quarterly common stock dividend of $1.03$1.07 per share ($4.12$4.28 per share on an annualized basis), an increase of 4% compared with the same quarter in the prior year.. 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 Feb.February 14,13, 2025,2026, to shareholders of record at the close of business on Feb.February 3,2, 2025.2026.

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. Following the Magellan Acquisition, we performed a review of ourOur calculation methodology of adjusted EBITDA and, beginning in 2023, we updated our calculation to include theincludes adjusted EBITDA related to our unconsolidated affiliates using the same recognition and measurement methods used to record equity in net earnings from investments. In prior periods, our calculation included equity in net earnings from investments. This change resulted in an additional $62 million of adjusted EBITDA in 2023, and we have not restated prior periods. 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.

Changes in commodity prices and sales volumes affect both revenues and cost of sales and fuel in our Consolidated Statements of Income 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 Nov.November 1, 20242024, and Oct.October 15, 2024, respectively.

•Natural Gas Gathering and Processing - an increase of $181$469 million due primarily to the operating income of EnLink,EnLink and higher volumes in the Mid-Continent and Rocky Mountain region and the sale of certain non-strategic assets,regions, offset partially by lower realized NGL prices, net of hedging, and higherthe operatingimpact costsfrom the divestiture of certain nonstrategic assets in 2024; offset byand

•Natural Gas Pipelines - ana increasedecrease of $291$104 million due primarily to the impact of the interstate natural gas pipeline divestiture in 2024, higheroffset transportationpartially services andby the operating income of EnLink and higher optimization and marketing; offset by

•Refined Products and Crude - an increase of $934$276 million due primarily to a full year of operating income following the Magellan Acquisition in 2023 and the operating income of Medallion and EnLink inand 2024;lower andoperating costs.

Net income and diluted EPS increased due primarily to the items discussed above and higher equity in net earnings from investments,above, offset partially by higher interest expense due to higher debt balances resulting from the August 2023 $5.25 billion notes offering, the September 2024 $7.0 billion notes offeringoffering, andthe August 2025 $3.0 billion notes offering, the acquired debt balances from both the Magellan Acquisition in 2023 and 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.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.

Selected Financial Results and Operating Information for the Year Ended Dec.December 31, 20232024 vs. 20222023 - The consolidated and segment financial results and operating information for the year ended Dec.December 31, 2023,2024, compared with the year ended Dec.December 31, 2022,2023, are included in Part II, Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations of our 20232024 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.

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.

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

20242025 vs. 20232024 - Adjusted EBITDA increased $240$654 million,million primarily as a result of the following:

•an increase of $200$740 million due to adjusted EBITDA from EnLink; and

•an increase of $77$99 million from higher volumes due primarily to increased production in the Mid-Continent and Rocky Mountain regionregions; andoffset by

•a decrease of $54$122 million due primarily to lower realized NGL prices, netprimarily of hedging, offset partially by higher average fee rates and realized condensate and natural gasNGL prices, net of hedging; and

(a) - IncludesIncluded volumes for consolidated entities only,only and excludes EnLink, asexcluded EnLink operating statistics arefor 2024 as they were not meaningful to full-year 2024 operating results.

(b) - IncludesIncluded volumes we processed at company-owned and third-party facilities.

20242025 vs. 20232024 - Our natural gas processed volumes increased in 2025 due primarilyto toincremental volumes from EnLink and increased production in the Mid-Continent and Rocky Mountain region. Our average fee rate increased due primarily to inflation-based escalators in our contracts.regions.

Business Update and Market Conditions - Earnings increased in the firstsecond quarter of 2026, compared with the firstsecond quarter of 2025, due primarily to higher optimization and marketing activity and higher NGL, Refined Products and natural gas processingvolumes volumes.and higher optimization and marketing activity.

Geopolitical conditions in the Middle East continue to impact our industry and contributed to a volatile commodity price environment infor the firstsix quartermonths ofended June 30, 2026. These conditions have highlightedhighlight the importance of a reliable energy supply and infrastructure that support the United States economy and national security. We operate an integrated, reliable, resilient and regionally diversified network of gathering, processing, fractionation, transportation, storage and marine export assets connecting supply in the Rocky Mountain, Mid-Continent, Permian and Gulf Coast regions with key market centers. We believe ourOur assets are well positioned to provide midstream services to producers and end-use markets to help meet domestic and international energy demand.

Each of our four reportable segments areis primarily fee-based, and we expect our consolidated earnings to be approximately 90% fee-based in 2026. Our fee-based earnings are primarily supported by long-term contracts,contracts with investment-grade counterparties, including minimum volume commitments and take-or-pay agreements, with investment-grade counterparties.agreements. While we remain well positioned to reduce downside exposure to commodity price volatility, we may use our integrated midstream network to capture differentialsproduct, between productslocation and locationsseasonal price differentials in our optimization and marketing businesses as we deliver volumes to where they are needed most.

(c) - Our investments in Texas City Logistics and Eiger are accounted for using the equity method. Spending on these projects will beis recorded as contributions to unconsolidated affiliates.

SubsequentDebt EventsExtinguishments - In April 2026, we redeemed the remaining $491 million of our $500 million, 4.85% senior notes due July 2026 at 100% of the outstanding principal amount, plus accrued and unpaid interest, with short-term borrowings.

$1.2 Billion Term Loan Agreement - In April 2026, we entered into a $1.2 Billion Term Loan Agreement, which iswas available to be drawn in up to two borrowings within 90 days of the closing date. Borrowings under the $1.2 Billion Term Loan Agreement bear interest at Term SOFR plus an applicable margin of 95 basis points. The $1.2 Billion Term Loan Agreement matures 364 days after June 23, 2026, the date of the initial borrowingborrowing, and may be used for working capital, capital expenditures, acquisitions, mergers and for other general corporate purposes. The $1.2 Billion Term Loan Agreement allows prepayment of all or any portion outstanding, without penalty or premium, and contains substantially the same covenants as those contained in our $3.5 Billion Credit Agreement. WeAs of June 30, 2026, we had no$600 million of borrowings outstanding at an interest rate of 4.59% under the $1.2 Billion Term Loan Agreement. In July 2026, the remaining borrowings available under the $1.2 Billion Term Loan Agreement aswere offully thedrawn dateand ofno issuanceadditional ofamounts themay Consolidatedbe Financial Statements in this Quarterly Report.borrowed.

Operating income increased $208$162 million for the three months ended MarchJune 31,30, 2026, compared with the same period in 2025, primarily as a result of the following:

•Natural Gas Gathering and Processing - aan decreaseincrease of $39$2 million due primarily to lowerhigher volumes across all regions and higher realized NGL and natural gascondensate prices, net of hedging, offset partially by higher volumes across all regions and lower operating costs.

•Natural Gas Liquids - ana increasedecrease of $74$16 million due primarily to higher operating costs and lower transportation and storage volumes, offset partially by higher optimization and marketing and higher exchange services.

•Refined Products and Crude - an increase of $26$77 million due primarily to higher Refined Products volumes and rates, and higher crude marketing earnings.earnings, offset partially by higher operating costs.

NetOperating income andincreased diluted$370 EPS increasedmillion for the threesix months ended MarchJune 31,30, 2026, compared with the same period in 2025, due primarily toas a result of the items discussed above, offset partially by a noncash impairment charge related to our 50% investment in Powder Springs in our Refined Products and Crude segment.following:

CapitalNet expendituresincome and diluted EPS increased for the three months ended MarchJune 31,30, 2026, compared with the same period in 2025, due primarily to the timingitems ofdiscussed our large capital projects. Please refer to the “Recent Developments” section of Management’s Discussionabove and Analysishigher of Financial Condition and Results of Operationsequity in thisnet Quarterlyearnings Reportfrom forinvestments, additionaloffset informationpartially onby ourhigher capitalincome projects.taxes.

Adjusted EBITDA decreasedincreased $24$6 million for the three months ended MarchJune 31,30, 2026, compared with the same period in 2025, primarily as a result of the following:

•aan decreaseincrease of $14$22 million in operating costs due primarily to a $13 million methane feesfee noaccrual longer incurredreversed in 20262025 due to regulatory changes.changes and $11 million of higher outside services related to the timing of projects.

OurAdjusted naturalEBITDA gasdecreased processed$18 volumes increasedmillion for the threesix months ended MarchJune 31,30, 2026, compared with the same period in 2025, dueprimarily toas increaseda productionresult inof allthe regions.following:

Adjusted EBITDA increaseddecreased $71$14 million for the three months ended MarchJune 31,30, 2026, compared with the same period in 2025, primarily as a result of the following:

•ana increasedecrease of $24$6 million in exchangetransportation servicesand storage due primarily to: lower volumes; offset by

CapitalAdjusted expendituresEBITDA increased $57 million for the threesix months ended MarchJune 31,30, 2026, compared with the same period in 2025, due primarily toas a result of the Medford fractionator rebuild project and the MBTC Pipeline.following:

Volumes increased for the three and six months ended MarchJune 31,30, 2026, compared with the same periodperiods in 2025, due primarily to higher volumesproduction in all regions across our system. The three months ended June 30, 2026, also benefited from higher ethane recovery in the Gulf Coast/Permian and Rocky Mountain and Mid-Continent regions.

Adjusted EBITDA increased $127$109 million for the three months ended MarchJune 31,30, 2026, compared with the same period in 2025, primarily as a result of the following:

•an increase of $92$77 million in optimization and marketing activity due primarily to $70 million of favorable price differentials between the Waha Hub and Katy, Texas, markets and $19 million due to the impact of Winter Storm Fern;

•an increase of $17 million in adjusted EBITDA from unconsolidated affiliates due primarily to higher earnings on Northern Border.Border and Matterhorn.

CapitalAdjusted expendituresEBITDA decreasedincreased $236 million for the threesix months ended MarchJune 31,30, 2026, compared with the same period in 2025, due primarily toas decreaseda growthresult projects.of the following: