Oneok Inc /new,
Fiscal Year 2025.

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 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)

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;

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.

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. 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.

Diluted EPS$5.17 $5.48 $3.84 (0.31)1.64 Adjusted EBITDA$6,784 $5,243 $3,620 1,541 1,623 Capital expenditures$2,021 $1,595 $1,202 426 393 49 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. 1, 2024 and Oct. 15, 2024, respectively.

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. 51 In 2024, we connected one third-party natural gas processing plant in the Permian Basin to our system, and two third-party natural gas processing plants previously connected to our system were expanded, one in the Permian Basin and one in the Mid-Continent region.

- - 35 (35) Other3 778 88 (775)690 Adjusted EBITDA$2,543 $3,045 $2,095 (502)950 Capital expenditures$987 $818 $581 169 237 (a) - Beginning in 2023, we updated our calculation methodology of adjusted EBITDA to include adjusted EBITDA from our unconsolidated affiliates, which resulted in an additional $9 million of adjusted EBITDA in 2023, and we have not restated prior periods. 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.

For a discussion of our capital expenditure financing, see "Capital Expenditures" in the "Liquidity and Capital Resources" section. Interstate Natural Gas Pipeline Divestiture - On Nov. 19, 2024, we entered into a definitive agreement with DT Midstream, Inc. to sell three of our wholly owned interstate natural gas pipeline systems. On Dec. 31, 2024, we completed the sale and recognized a gain of $227 million. 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:

(857)(192) Adjusted EBITDA from unconsolidated affiliates 247 36 Other(9)- Adjusted EBITDA$1,892 $465 Capital expenditures$216 $52 (a) - The year ended Dec. 31, 2023, includes results subsequent to the Magellan Acquisition. 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.

Refined Products volume shipped (MBbl/d) 1,512 1,547 Crude oil volume shipped (MBbl/d) 783 808 (a) - Includes volumes for consolidated entities only and excludes Medallion and EnLink, as Medallion and EnLink operating statistics are not meaningful to full-year 2024 operating results.

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 resources 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. We believe we have sufficient liquidity due to our $3.5 Billion Credit Agreement, which expires in February 2030, and access to $1.0 billion available through our "at-the-market" equity program. As of Feb. 17, 2025, no shares have been sold through our "at-the-market" equity program. 55 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 swaps, see Note E of the Notes to Consolidated Financial Statements in this Annual Report. Cash Management - At Dec. 31, 2024, we had $733 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. In December 2024, we entered into an agreement to provide revolving unsecured loans to EnLink through a promissory note at an interest rate of 4.85% at Dec. 31, 2024. This is a floating rate agreement which bears interest at ONEOK's current short-term borrowing rate plus 0.25%. At Dec. 31, 2024, we held a promissory note receivable of $510 million, which was eliminated in consolidation. Interest earned on this agreement was not material. Following the EnLink Acquisition, completed on Jan. 31, 2025, we effectively terminated this agreement as EnLink operating subsidiaries are wholly owned and now participate in the cash management program described above. Guarantees - ONEOK, ONEOK Partners, the Intermediate Partnership and Magellan (Obligated Group) 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 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 holds interests in its subsidiaries, which are nonguarantors, and substantially all the assets and operations reside with nonguarantor operating subsidiaries. At Dec. 31, 2024, EnLink was a subsidiary of ONEOK, but did not guarantee ONEOK's or ONEOK Partners' indebtedness and was excluded from the Obligated Group. EnLink and EnLink Partners also had outstanding debt securities that were not guaranteed by ONEOK as of Dec. 31, 2024. At the completion of the EnLink Acquisition on Jan. 31, 2025, ONEOK assumed the outstanding debt of EnLink and EnLink Partners (the Assumed Debt) such that EnLink and EnLink Partners were each released from all debt obligations, and provided a guarantee for our and ONEOK Partners' indebtedness to the holders of each series of outstanding securities, including for the Assumed Debt. EnLink and EnLink Partners are now included in the Obligated Group. As of the date of this report, 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 and therefore, we have excluded the summarized financial information for each issuer and guarantor.

For additional information on our $3.5 Billion Credit Agreement, see Note H 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 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 September 2024, we completed an underwritten public offering of $7.0 billion senior unsecured notes consisting of senior notes of the following tenors: $1.25 billion, 4.25% senior notes due 2027; $600 million, 4.4% senior notes due 2029; $1.25 billion, 4.75% senior notes due 2031; $1.6 billion, 5.05% senior notes due 2034; $1.5 billion, 5.7% senior notes due 2054; and $800 million, 5.85% senior notes due 2064. 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. Debt Repayments - In December 2024, we repaid $120 million of borrowings under the Guardian Term Loan Agreement and $60 million of borrowings under the Viking Term Loan Agreement, plus accrued and unpaid interest, with cash on hand, as part of the interstate natural gas pipeline divestiture. In December 2024, we 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.

We expect total capital expenditures, excluding AFUDC and capitalized interest, of $2.8 - $3.2 billion in 2025. Credit Ratings - Our long-term debt credit ratings as of Feb. 17, 2025, are shown in the table below:

Table of Contents 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.

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.

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

Additional information regarding our financial results and operating information is provided in the following discussion for each of our segments. 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.

(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.

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

Capital Projects - Our primary capital projects are outlined in the table below: Project ScopeApproximateCost (a)Expected Completion Natural Gas Gathering and Processing(In millions)

$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. 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.

(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

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

(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. 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.

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. 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,

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.

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.

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 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.

•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 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.

•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, 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.

•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 affect adversely our business and results of operations. Our financial results could also be 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. 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. 33 Terrorist attacks, including cyber sabotage, aimed at our facilities could 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. 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;

Table of Contents 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.

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.

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, 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;

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.

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.

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;

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 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. 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;

•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.

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

•Natural Gas Pipelines; and •Refined Products and Crude. 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.

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. This type of contract represented 76% and 72% of supply volumes in this segment, excluding EnLink, for 2024 and 2023, respectively. •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. This type of contract represented 19% of supply volumes in this segment, excluding EnLink, for both 2024 and 2023. EnLink's service contracts are primarily fee with POP contracts with producer take-in-kind rights to certain commodities. •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. Our fee-only contracts represented 5% and 9% of supply volumes in this segment, excluding EnLink, for 2024 and 2023, respectively. 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.

See further discussion in the "Regulatory, Environmental and Safety Matters" section. 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 (including Louisiana) 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 13 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. Property - Our Natural Gas Liquids segment includes the following assets, which are wholly owned, except where noted, and exclude EnLink, which is shown separately below: •9,300 miles of gathering pipelines; •4,800 miles of distribution pipelines; •NGL fractionators with combined operating capacity of 960 MBbl/d (includes interests in our proportional share of operating capacity), including 310 MBbl/d in the Mid-Continent region and 650 MBbl/d in the Mont Belvieu, Texas area, which were 92% and 98% utilized in 2024 and 2023, respectively; •one isomerization unit with operating capacity of 10 MBbl/d; •one ethane/propane splitter with operating capacity of 40 MBbl/d;

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 and Northern Border, 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 low-cost expansions that position us well to provide additional services to our customers when needed. 15 Intrastate Pipelines and Storage - Our intrastate natural gas pipeline and storage assets are located in Oklahoma, Texas 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. 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 61 Bcf of working gas storage capacity. Additionally, as a result of the EnLink Acquisitions, we also have intrastate pipeline and storage assets in Louisiana and North Texas. 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 to the southeast 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, acquired with the EnLink Acquisitions, which provides transportation and storage services to a variety of customers including South Louisiana industrial companies, power companies, utilities and Gulf Coast LNG facilities; •Louisiana Intrastate Gas (LIG) Pipeline, acquired with the EnLink Acquisitions, which is a natural gas pipeline system providing a fully integrated wellhead to burner tip value chain that includes local gathering, processing, transmissions and treating services to Louisiana producers. The LIG Pipeline has access to the Haynesville shale producing area and connects to several other natural gas pipelines, providing additional system supply, and to the Jefferson Island storage facility; and •Acacia Pipeline, acquired with the EnLink Acquisitions, which provides transportation services to connect production from the Barnett Shale to markets in North Texas. Interstate Natural Gas Pipeline Divestiture - On Nov. 19, 2024, we entered into a definitive agreement with DT Midstream, Inc. to sell three of our wholly owned interstate natural gas pipeline systems, including Guardian and Viking, located in the Upper Midwest, and Midwestern Gas Transmission Company, located between Tennessee and the Chicago Hub near Joliet, Illinois. On Dec. 31, 2024, we completed the sale of these assets. Interstate Pipelines - Sabine Pipeline was acquired with the EnLink Acquisitions and 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. 16

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. •As a result of the EnLink Acquisitions, 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.

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. As a result of the EnLink Acquisitions and the Medallion Acquisition, we are also engaged in the gathering of crude oil. Crude oil pipelines gather and transport crude oil to refineries, export facilities 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. 18 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 transport and store crude oil and are connected to multiple trading and demand centers. We have existing crude oil pipelines in Kansas and Oklahoma, and from the Permian Basin in West Texas to our East Houston terminal. 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. As a result of the EnLink Acquisitions and the Medallion Acquisition, we acquired crude oil gathering pipelines and crude oil storage facilities in the Permian Basin and the Mid-Continent region. Property - Our Refined Products and Crude segment includes the following wholly owned assets, which exclude EnLink and Medallion, which are shown separately below: •9,800 miles of Refined Products pipelines; •1,100 miles of crude oil pipelines; •53 Refined Products terminals;

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. I&D continues to be a priority in recruiting, and we deploy sourcing strategies designed to access talent from groups that are historically underrepresented in our industry and workplace. Retirement - We maintain a 401(k) Plan for our employees and match 100% of employee contributions up to 6% of eligible compensation each payroll period, subject to applicable tax limits. We have a legacy defined benefit pension plan covering certain employees and former employees, which closed to new participants in 2005. In addition, as a result of the Magellan Acquisition, we assumed the pension and postretirement benefit obligations for Magellan employees and former employees. These obligations are composed of two defined benefit pension plans, including one for non-union employees and one for union employees, as well as a postretirement welfare benefit plan for certain employees. The pension plan for non-union employees closed to new participants upon the closing of the Magellan Acquisition. The pension plan for union employees closed to new participants in January 2024. Employees who do not participate in our defined benefit pension plan are eligible to receive quarterly and annual profit-sharing contributions under our 401(k) Plan. Effective Jan. 1, 2025, the profit-sharing quarterly contributions increased to 6% from 1% of quarterly eligible compensation. We will continue to make annual discretionary contributions of up to 2% of eligible compensation. As of Dec. 31, 2024, 96% of eligible employees were contributing to our 401(k) Plan. For additional information about our retirement benefits, see Note M of the Notes to Consolidated Financial Statements in this Annual Report.

•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.

•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. •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.

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. 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.

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 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.

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 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.

•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. 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.

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

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