Oneok Inc /new,
Fiscal Year 2023.

2023 vs. 2022 - Adjusted EBITDA increased $207 million, primarily as a result of the following: •an increase of $227 million from higher volumes due primarily to increased producer activity in the Rocky Mountain and Mid-Continent regions, and the impact of winter weather in the Rocky Mountain region in the second and fourth quarters of 2022; and •an increase of $49 million due primarily to higher average fee rates and realized condensate prices, net of hedging, offset partially by lower realized NGL prices, net of hedging; offset by •an increase of $62 million in operating costs due primarily to higher employee-related costs, outside services and materials and supplies expense due primarily to the growth of our operations, and higher property insurance premiums. Capital expenditures remained relatively unchanged for 2023, as compared to 2022, due primarily to increased expenditures in 2023 on various capital projects, offset by expenditures in 2022 on our Demicks Lake III project completed in the first quarter of 2023. Years Ended December 31,

Operating Information202320222021 Raw feed throughput (MBbl/d) (a) 1,359 1,237 1,198 Average Conway-to-Mont Belvieu OPIS price differential - ethane in ethane/propane mix ($/gallon)

Natural Gas Pipelines Capital Projects - Our Natural Gas Pipelines segment invests in capital projects that provide transportation and storage services to end users. In February 2024, the FERC approved our Saguaro Connector Pipeline, L.L.C.'s Presidential Permit application to construct and operate new international border-crossing facilities at the U.S. and Mexico border. The proposed border facilities would connect upstream with a potential intrastate pipeline, the Saguaro Connector pipeline. Additionally, the proposed border facilities would connect at the international boundary with a new pipeline under development in Mexico for delivery to a liquefied natural gas export facility on the west coast of Mexico. The final investment decision on the Saguaro Connector pipeline is expected by mid-year 2024. In 2023, we completed an expansion of our injection capabilities of our Oklahoma natural gas storage facilities, which allowed us to utilize and subscribe an additional 4 Bcf of our existing storage capacity, which is fully subscribed through 2027 and 90% subscribed through 2029. We are reactivating previously idled storage facilities with 3 Bcf of working gas storage capacity in Texas, which is already fully subscribed on a firm basis. We are also further expanding our injection capabilities in Oklahoma to allow us to subscribe additional firm storage capacity.

Natural gas transportation capacity contracted (MDth/d) 7,743 7,428 7,395 Transportation capacity contracted96 %94 %95 % (a) - Includes volumes for consolidated entities only. In April 2022, the FERC initiated a review of Guardian's rates pursuant to Section 5 of the Natural Gas Act. In August 2022, Guardian reached a settlement in principle with the participants in the Section 5 rate case. The FERC approved the settlement in February 2023, which resulted in a reduction of rates starting in April 2023. The reduced rates did not have a material impact on our results of operations. In July 2023, Viking filed a proposed increase in rates pursuant to Section 4 of the Natural Gas Act with the FERC. The FERC is currently reviewing the filing. While the ultimate outcome of the filing cannot be predicted, we do not expect it to materially impact our results of operations.

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. Following the Magellan Acquisition, we performed a review of our calculation methodology of adjusted EBITDA, and beginning in 2023, we updated our calculation to include the adjusted EBITDA related to our unconsolidated affiliates using the same recognition and measurement methods used to record equity in net earnings from investments. In prior periods, our calculation included equity in net earnings from investments. This change resulted in an additional $62 million of adjusted EBITDA in 2023, and we have not restated prior periods. Adjusted EBITDA from our unconsolidated affiliates is calculated consistently with the definition above and excludes items such as interest, depreciation, 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.

Financing Cash Flows 2023 vs. 2022 - Cash from financing activities for the year ended December 31, 2023, increased $3.8 billion compared with the same period in 2022, due primarily to the issuance of $5.25 billion senior unsecured notes associated with the Magellan Acquisition. Cash Flow Analysis for the Year Ended December 31, 2022 vs. 2021 - The cash flow analysis for the year ended December 31, 2022, compared with the year ended December 31, 2021, is included in Part II, Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations of our 2022 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.

See reconciliation of net income to adjusted EBITDA in the "Non-GAAP Financial Measures" section. 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, except where noted. Operating income for the year ended December 31, 2022, includes $96.1 million of business interruption insurance recoveries, which are included in the other operating (income) expense, net line item above, and an approximately $30 million unfavorable impact from the 45-day business interruption coverage waiting period related to the Medford incident in our Natural Gas Liquids segment. 39

$0.04 $(0.01)$0.01 (a) - Represents physical raw feed volumes for which we provide transportation and/or fractionation services. 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 extract or reject ethane. 2022 vs. 2021 - Volumes increased due primarily to increased NGL production in the Rocky Mountain region and Permian Basin, and higher ethane volumes from incentivized ethane recovery in the Rocky Mountain region, offset partially by decreased ethane recovery in the Mid-Continent region due to ethane economics. Volumes also benefited from the unfavorable impact of Winter Storm Uri in the first quarter 2021, offset partially by the impact of winter weather in the Rocky Mountain region in the second and fourth quarters of 2022.

these assets, we use two generally accepted valuation approaches, an income approach and a market approach. Under the income approach, our discounted cash flow analysis includes the following inputs that are not readily available: a discount rate reflective of industry cost of capital, our estimated contract rates, volumes, operating margins, operating and maintenance costs and capital expenditures. Under the market approach, our inputs include EBITDA multiples, which are estimated from recent peer acquisition transactions, and forecasted EBITDA, which incorporates inputs similar to those used under the income approach. If actual results are not consistent with our assumptions and estimates or our assumptions and estimates change due to new information, we may be exposed to future impairment charges. See Notes A, E and F of the Notes to Consolidated Financial Statements in this Annual Report for additional discussion of goodwill, long-lived assets and investments in unconsolidated affiliates. Depreciation Methods and Estimated Useful Lives of Property, Plant and Equipment - Our property, plant and equipment are depreciated using the straight-line method that incorporates management assumptions regarding useful economic lives and residual values. As we place additional assets in service, our estimates related to depreciation expense have become more significant and changes in estimated useful lives of our assets could have a material effect on our results of operations. At the time we place our assets in service, we believe such assumptions are reasonable; however, circumstances may develop that would cause us to change these assumptions, which would change our depreciation expense prospectively. Examples of such circumstances include changes in (i) competition, (ii) laws and regulations that limit the estimated economic life of an asset, (iii) technology that render an asset obsolete, (iv) expected salvage values, (v) results of rate cases or rate settlements on regulated assets and (vi) forecasts of the remaining economic life for the resource basins where our assets are located, if any. For the fiscal years presented in this Form 10-K, no changes were made to the determinations of useful lives that would have a material effect on the timing of depreciation expense in future periods.

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.

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 around connecting diversified supply basins from the Rocky Mountain region through the Mid-Continent region and the Permian Basin with demand for Purity NGLs from the petrochemical and refining industries and NGL exports in the Gulf Coast. 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. See "Capital Projects" in the "Recent Developments" section for more information on our capital projects. In 2023, we connected two third-party natural gas processing plants in the Permian Basin and one affiliate natural gas processing plant in the Rocky Mountain region.

See "Capital Projects" in the "Recent Developments" section for a discussion of our capital projects. For a discussion of our capital expenditure financing, see "Capital Expenditures" in the "Liquidity and Capital Resources" section. Selected Financial Results and Operating Information - The following tables set forth certain selected financial results and operating information for our Natural Gas Pipelines segment for the periods indicated:

Capital expenditures increased in 2023 due primarily to capital projects, including the Viking compression project. Years Ended December 31, Operating Information (a)202320222021

177 Cost of sales and fuel (exclusive of depreciation and operating costs) (450) Operating costs, excluding noncash compensation adjustments (192)

LIQUIDITY AND CAPITAL RESOURCES General - Our primary sources of cash inflows are operating cash flows, proceeds from our commercial paper program and our $2.5 Billion Credit Agreement, debt issuances and the issuance of common stock for our liquidity and capital resources requirements. In January 2023, we reached an agreement with our insurers to settle all claims for physical damage and business interruption related to the Medford incident. Under the terms of the settlement agreement, we agreed to resolve the claims for total insurance payments of $930 million, $100 million of which was received in 2022. The remaining $830 million was received in the first quarter of 2023. The proceeds serve as settlement for property damage, business interruption claims to the date of settlement and as payment in lieu of future business interruption insurance claims. We expect our cash from operations in 2024 to be impacted by incurred costs resulting from the Medford incident for which we no longer receive business interruption proceeds. 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 $2.5 Billion Credit Agreement, which expires in June 2027, and access to $1.0 billion available through our "at-the-market" equity program. As of the date of this report, no shares have been sold through our "at-the-market" equity program. We may manage interest-rate risk through the use of fixed-rate debt, floating-rate debt, Treasury locks and interest-rate swaps. For additional information on our interest-rate swaps, see Note E of the Notes to Consolidated Financial Statements in this Annual Report. Cash Management - At December 31, 2023, we had $338 million of cash and cash equivalents. We use a centralized cash management program that concentrates the cash assets of our 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. Guarantees - In December 2023, ONEOK assumed the debt obligations of Magellan under its previous debt indentures and Magellan provided a guarantee of the outstanding notes. As of December 31, 2023, Magellan no longer had debt obligations outstanding. We guarantee certain debt securities of ONEOK Partners, and ONEOK Partners, the Intermediate Partnership and Magellan guarantee certain of our debt securities. The 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. Therefore, as allowed under Rule 13-01, we have excluded the summarized financial information for each issuer and guarantor as the combined financial information of the subsidiary issuers and parent guarantor, excluding our ownership of all the interests in ONEOK Partners and Magellan, reflect no material assets, liabilities or results of operations, apart from the guaranteed indebtedness. For additional information on our and ONEOK Partners' indebtedness, please see Note H 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 equity-method investments, proceeds from our commercial paper program and our $2.5 Billion Credit Agreement. As of December 31, 2023, we had no borrowings under our $2.5 Billion Credit Agreement and we are in compliance with all covenants. We had working capital (defined as current assets less current liabilities) deficits of $344 million and $503 million as of December 31, 2023, and December 31, 2022, respectively due primarily to current maturities of long-term debt. 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 repayments, 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.

The following table sets forth our capital expenditures, excluding AFUDC, for the periods indicated: Capital Expenditures202320222021 (Millions of dollars)

Rating AgencyLong-Term RatingShort-Term RatingOutlook Moody'sBaa2Prime-2Stable S&PBBBA-2Stable Fitch BBBF2Stable Our credit ratings, which are investment grade, may be affected by our leverage, liquidity, credit profile or potential transactions. In April 2023, Moody's upgraded the rating on our long-term debt to Baa2 from Baa3, the rating on our short-term debt to Prime-2 from Prime-3 and changed the outlook to stable from positive. 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 $2.5 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 $2.5 Billion Credit Agreement, which expires in 2027. An adverse credit rating change alone is not a default under our $2.5 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, subject to the rights of the holders of outstanding preferred stock. In 2023, we paid common stock dividends totaling $3.82 per share, an increase of 2% compared to the 2022 dividend of $3.74 per share. In February 2024, we paid a quarterly common stock dividend of $0.99 per share ($3.96 per share on an annualized basis), an increase of 3.7% compared with the same quarter in the prior year. Our Series E Preferred Stock pays quarterly dividends on each share of Series E Preferred Stock, when, as and if declared by our Board of Directors, at a rate of 5.5% per year. In 2023, we paid dividends for the Series E Preferred Stock of $1 million for the series E preferred stock. In February 2024, we paid quarterly dividends totaling $0.3 million for the Series E Preferred Stock. For the year ended December 31, 2023, our cash flows from operations exceeded dividends paid by $2.6 billion, due in part to the insurance proceeds received from the Medford settlement in 2023. 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 assets, net undistributed earnings from equity-method investments, share-based compensation expense, other amounts and changes in our assets and liabilities not classified as investing or financing activities.

Cash and cash equivalents at end of period$338 $220 $146 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. 2023 vs. 2022 - Cash flows from operating activities, before changes in operating assets and liabilities increased $1.1 billion for the year ended December 31, 2023, compared with the same period in 2022, due primarily to higher operating income resulting from higher volumes from increased production and higher average fee rates in our Natural Gas Gathering and Processing segment, higher exchange services in our Natural Gas Liquids segment, higher transportation and storage services in our Natural Gas Pipelines segment and an increase due to the impact of the Magellan Acquisition in our Refined Products and Crude segment; and insurance proceeds received from the Medford settlement. Please see "Financial Results and Operating Information" for a discussion of operating results. The changes in operating assets and liabilities increased operating cash flows $358 million for the year ended December 31, 2023, compared with a decrease of $58 million for the same period in 2022. This change is due primarily to changes in accounts receivable resulting from the timing of receipt of cash from counterparties and from inventory, both of which vary from period to period, and with changes in commodity prices; offset partially by changes in risk management assets and liabilities.

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

Financial Results202320222021$ Increase (Decrease) (Millions of dollars, except per share amounts) Revenues Commodity sales$15,614 $20,976 $15,180 (5,362)5,796

Increasing attention to ESG issues, including climate change, may impact our business. There are increasing expectations that companies across all industries address ESG issues, including climate change. Changes in regulatory policies, public sentiment or widespread adoption of technologies that aim to address climate change through reducing GHG emissions may result in a reduction in the demand for hydrocarbon products, restrictions on their use or increased use of alternative energy sources. These changes could reduce the demand for our services, impacting our business, results of operations, financial position and cash flows. In addition, increasing attention to climate change has resulted in an increased likelihood of governmental investigations, regulation, shareholder activism and private litigation, which could increase our costs or otherwise affect adversely our business. For example, the SEC has announced its plans to propose new climate change disclosure requirements. While the form those requirements may take are not final, we may face increased costs associated with complying with any new climate disclosure rules. Certain investors are increasingly focused on ESG issues, including climate change. Further, organizations that provide information to investors on corporate governance and related matters have also increased their focus on ESG issues and have developed ratings processes for evaluating companies on various ESG initiatives. Unfavorable ESG ratings may lead to increased negative investor sentiment toward us or midstream companies in general. Due to climate change concerns, some investors may choose not to invest, or to reduce investment, in companies that explore for, produce, process, transport or sell products derived from hydrocarbons. If this negative investor sentiment increases, we may see reduced demand for our securities, which could impact our liquidity or the value of our securities. Additionally, certain large institutional lenders have announced their own policies to meet publicly announced climate commitments, which often involve commitments to shift lending activities in the energy sector to meet GHG emissions goals. As a result, certain institutional lenders may impose additional requirements on us, or decide not to lend to us, based on ESG concerns, which could adversely affect our access to capital on reasonable terms or at all and, as a result, our financial condition. To the extent financial markets view climate change and emissions of GHGs as a financial risk, this could also negatively affect our ability to access capital or cause us to receive less favorable terms and conditions in future financings. In 2021, we announced a companywide absolute GHG emissions reduction target of 2.2 million metric tons of carbon dioxide equivalents from our combined Scope 1 and Scope 2 emissions by 2030 for our legacy ONEOK assets. The target represents a 30% reduction in combined operational Scope 1 and location-based Scope 2 GHG emissions attributable to ONEOK assets as of December 31, 2019. To the extent that the potential pathways we have identified to achieve this emissions reduction target are not available to us, or to the extent we otherwise are unable to make progress toward other ESG-related targets we may establish, we may face additional costs to meet these targets, or we may fail to meet them, which could negatively impact our business and reputation.

Measurement adjustments on our pipeline system may be impacted materially by changes in estimation, type of commodity and other factors. Natural gas and NGL measurement adjustments occur as part of the normal operating conditions associated with our assets. The quantification and resolution of measurement adjustments are complicated by several factors including: (i) the significant quantities (i.e., thousands) of measurement equipment that we use across our natural gas and NGL systems, primarily around our gathering and processing assets; (ii) varying qualities of natural gas in the streams gathered and processed through our systems and the mixed nature of NGLs gathered and fractionated; and (iii) variances in measurement that are inherent in metering technologies and standards. Each of these factors may contribute to measurement adjustments that may occur on our systems, which could affect adversely our business, results of operations, financial position and cash flows. In the competition for supply, we may have significant levels of excess capacity on our natural gas and NGL pipelines, processing, fractionation and storage assets. Our natural gas and NGL pipelines, processing, fractionation and storage assets compete with other pipelines, processing, fractionation and storage assets for natural gas and NGL supply delivered to the markets we serve. As a result of competition, we may have significant levels of uncontracted or discounted capacity on our assets, which could affect adversely our business, results of operations, financial position and cash flows.

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

Continued development of supply sources outside of our operating regions could impact demand for our services. Production areas outside of our operating regions may compete with natural gas and NGL supply originating in production areas connected to our systems, which may cause natural gas and NGLs in supply areas connected to our systems to be diverted to markets other than our traditional market areas and may affect capacity utilization adversely on our pipeline systems and our ability to renew or replace existing contracts. In our Natural Gas Gathering and Processing segment, the development of reserves could move drilling rigs from our current service areas to other areas, which may reduce demand for our services. In our Natural Gas Pipelines segment, the displacement of natural gas originating in supply areas connected to our pipeline systems by supply sources that are closer to the end-use markets could reduce demand for our services. Either of these possibilities could result in lower revenues, which could affect adversely our business, results of operations, financial position and cash flows. We do not hedge fully against commodity price risk or interest rate risk, including commodity price changes, seasonal price differentials, product price differentials or location price differentials. This could result in decreased revenues, increased costs and lower margins, affecting adversely our results of operations. Certain of our businesses are exposed to market risk and the impact of market fluctuations in natural gas, NGLs and crude oil prices. Market risk refers to the risk of loss of future cash flows and earnings arising from adverse changes in commodity prices. Our primary commodity price exposures arise from: •the value of the commodities sold under fee with POP contracts of which we retain a portion of the sales proceeds; •the price differentials between the individual purity NGLs with respect to our NGL transportation and fractionation agreements; •the location price differentials in the price of natural gas and NGLs; •the seasonal price differentials in natural gas and NGLs related to our storage operations;

RISK FACTORS RELATED TO OUR BUSINESS AND INDUSTRY If the level of drilling in the regions in which we operate declines substantially near our assets, our volumes and revenues could decline. Our gathering and transportation pipeline systems are dependent upon production from natural gas and crude oil wells, which naturally decline over time. As a result, our cash flows associated with these wells may also decline over time. In order to maintain or increase throughput levels on our gathering and transportation pipeline systems and the asset utilization rates at our processing and fractionation facilities, we must continually obtain new supplies. Our ability to maintain or expand our businesses depends largely on the level of drilling and production by third parties in the regions in which we operate. Our natural gas and NGL supply volumes may be impacted if producers curtail or redirect drilling and production activities. Drilling and production are impacted by factors beyond our control, including: •demand and prices for natural gas, NGLs, Refined Products and crude oil; •producers' access to capital; •producers' finding and development costs of reserves; •producers' ability to secure drilling and completion crews and equipment; •producers' desire and ability to obtain necessary permits, drilling rights and surface access in a timely manner and on reasonable terms; •crude oil and associated natural gas field characteristics and production performance; •regulatory compliance;

•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 and 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. Growing our business by constructing new pipelines and facilities or making modifications to our existing facilities subjects us to construction risk and supply risks, should adequate natural gas, NGL, Refined Products and crude oil supply be unavailable upon completion of the facilities. To expand our business, we regularly construct new and modify or expand existing pipelines and gathering, processing, storage and fractionation facilities. The construction and modification of these facilities may involve the following risks: •projects may require significant capital expenditures, which may exceed our estimates, and involve numerous regulatory, environmental, political, legal and weather-related uncertainties; •projects may increase demand for labor, materials and rights of way, which may, in turn, affect our costs and schedule; •we may be unable to obtain new rights of way or permits to connect our systems to supply or downstream markets; •if we undertake these projects, we may not be able to complete them on schedule or at the budgeted cost; •our revenues may not increase immediately upon the expenditure of funds on a particular project. For instance, if we build a new pipeline, the construction will occur over an extended period of time, and we will not receive any material increases in revenues until after completion of the project; •we may construct facilities to capture anticipated future growth in production or downstream demand in which anticipated growth does not materialize; •opposition from environmental and social groups, landowners, tribal groups, local groups and other advocates could result in organized protests, attempts to block or sabotage our construction activities or operations, intervention in regulatory or administrative proceedings involving our assets, or lawsuits or other actions designed to prevent, disrupt or delay the construction or operation of our assets; •we may be required to rely on third parties downstream of our facilities to have available capacity for our delivered natural gas, NGLs, Refined Products and crude oil, which may not be operational; and

•inflationary pressure could increase our costs for construction materials or labor. As a result, new facilities may not be able to attract enough natural gas, NGLs, Refined Products and crude oil to achieve our expected investment return, which could affect adversely our business, results of operations, financial position and cash flows.

RISK FACTORS RELATED TO REGULATION 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 are relying increasingly 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, 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, affect adversely 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.

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

•maintenance of accounts and records; and •relationships with affiliate companies involved in all aspects of our business. Compliance with these requirements can be costly and burdensome. Future changes to laws, regulations and policies in these areas may impair our ability to compete for business or to recover costs and may increase the cost and burden of our operations. We cannot guarantee that state or federal regulators will not challenge our safety practices or will authorize any projects or acquisitions that we may propose in the future. Moreover, there can be no guarantee that, if granted, any such authorizations will be made in a timely manner or will be free from potentially burdensome conditions. Under the Natural Gas Act, which is applicable to our interstate natural gas pipelines, and the Interstate Commerce Act, which is applicable to our interstate Refined Products, crude oil and NGL pipelines, our interstate transportation rates are regulated by the FERC and many changes to our pipeline tariffs must be approved in a regulatory proceeding. Additionally, shippers, the FERC and/or state regulatory agencies may investigate our tariff rates which could result in, among other things, our being ordered to reduce rates or make refunds to shippers.

We may face significant costs to comply with the regulation of GHG emissions. GHG emissions in the midstream industry originate primarily from combustion engine exhaust, heater exhaust and fugitive methane gas emissions. International, federal, regional and/or state legislative and/or regulatory initiatives may attempt to control or limit GHG emissions, including initiatives directed at issues associated with climate change. Various federal and state legislative proposals have been introduced to regulate the emission of GHGs, particularly carbon dioxide and methane, and the United States Supreme Court has ruled that carbon dioxide is a pollutant subject to regulation by the EPA. 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. For example, the IRA directs 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 methane emissions intensity in excess of the relevant statutory threshold. Based on text in the IRA and a related rule that the EPA proposed in January 2024 to implement the Methane Fee program, we expect to begin paying Methane Fees in 2025 (for 2024 reported emissions) for applicable facilities. Methane Fees and other legislative and/or regulatory initiatives 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 affected adversely if such costs are not recovered or otherwise passed on to our customers. Our operations are subject to federal and state laws and regulations relating to the protection of public health and 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 impact adversely 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: •Clean Air Act and analogous state laws that impose obligations related to air emissions; •Clean Water Act 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; •CERCLA 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;

•limit our flexibility in planning for, or reacting to, changes in our business and the industry in which we operate; and •place us at a competitive disadvantage compared with our competitors that have proportionately less debt and fewer guarantee obligations. We are not prohibited under the indentures governing the senior notes from incurring additional indebtedness, but our debt agreements do subject us to certain operational limitations that could restrict our ability to finance future operations or expand or pursue business activities, as summarized in the next paragraph. If we incur significant additional indebtedness, it could worsen the negative consequences mentioned above and could affect adversely our ability to repay our other indebtedness. Our $2.5 Billion Credit Agreement contains provisions that, among other things, limit our ability to make material changes to the nature of our business, merge, consolidate or dispose of all or substantially all of our assets, grant liens and security interests on our assets, engage in transactions with affiliates or make restricted payments, including dividends. It also requires us to maintain certain financial ratios, which limit the amount of additional indebtedness we can incur, as described in the "Liquidity and Capital Resources" section of Part II, Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations, in this Annual Report. These restrictions could result in higher costs of borrowing and impair our ability to generate additional cash. Future financing agreements we may enter into may contain similar or more restrictive covenants. If we are unable to meet our debt-service obligations or comply with financial covenants, we could be forced to restructure or refinance our indebtedness, seek additional equity capital or sell assets. We may be unable to obtain financing or sell assets on satisfactory terms, or at all. An event of default may require us to offer to repurchase certain of our and ONEOK Partners' senior notes or may impair our ability to access capital. The indentures governing certain of our and ONEOK Partners' senior notes include an event of default upon the acceleration of other indebtedness of $15 million or more for certain of our senior notes or $100 million or more for certain of our and ONEOK Partners' senior notes. Such events of default would entitle the trustee or the holders of 25% in aggregate principal amount of our and ONEOK Partners' outstanding senior notes to declare those senior notes immediately due and payable in full. We may not have sufficient cash on hand to repurchase and repay any accelerated senior notes, which may cause us to borrow funds under our credit facility or seek alternative financing sources to finance the repurchases and repayment. We could also face difficulties accessing capital or our borrowing costs could increase, impacting our ability to obtain financing for acquisitions or capital expenditures, to refinance indebtedness and to fulfill our debt obligations. The right to receive payments on our outstanding debt securities and subsidiary guarantees is unsecured and will be effectively subordinated to any future secured indebtedness as well as to any existing and future indebtedness of our subsidiaries that do not guarantee the senior notes. Although ONEOK Partners, the Intermediate Partnership and Magellan have guaranteed our debt securities, the guarantees are subject to release under certain circumstances, and we have subsidiaries that are not guarantors. In those cases, the debt securities effectively are subordinated to the claims of all creditors, including trade creditors and tort claimants, of our subsidiaries that are not guarantors. In the event of the insolvency, bankruptcy, liquidation, reorganization, dissolution or winding up of the business of a subsidiary that is not a guarantor, creditors of that subsidiary would generally have the right to be paid in full before any distribution is made to us or the holders of the debt securities.

A court may use fraudulent conveyance considerations to avoid or subordinate the cross guarantees of our and ONEOK Partners' indebtedness. ONEOK, ONEOK Partners, the Intermediate Partnership and Magellan have cross guarantees in place for our and ONEOK Partners' indebtedness. A court may use fraudulent conveyance laws to subordinate or avoid the cross guarantees of certain of this indebtedness. It is also possible that under certain circumstances, a court could avoid or subordinate the guarantor's guarantee of this indebtedness in favor of the guarantor's other debts or liabilities to the extent that the court determined either of the following were true at the time the guarantor issued the guarantee: •the guarantor incurred the guarantee with the intent to hinder, delay or defraud any of its present or future creditors or the guarantor contemplated insolvency with a design to favor one or more creditors to the total or partial exclusion of others; or •the guarantor did not receive fair consideration or reasonable equivalent value for issuing the guarantee and, at the time it issued the guarantee, the guarantor: - was insolvent or rendered insolvent by reason of the issuance of the guarantee;

Our operating results may be affected adversely by unfavorable economic and market conditions. Uncertainty or adverse changes in economic conditions worldwide, in the United States, or in the economic regions in which we operate, could negatively affect the crude oil and natural gas markets, resulting in reduced demand and increased price competition for our services and products, or otherwise affect adversely our business, results of operations, financial position and cash flows. Volatility in commodity prices may have an impact on many of our suppliers and customers, which, in turn, could have a negative impact on their ability to meet their obligations to us. Periods of severe volatility in equity and credit markets may disrupt our access to such markets, make it difficult to obtain financing necessary to expand facilities or acquire assets, increase financing costs and result in the imposition of restrictive financial covenants. Also, economic conditions in the wake of the pandemic have included increasing inflation. 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. Sustained levels of high inflation have caused the Federal Reserve System and other central banks to increase interest rates, which may cause the cost of capital to increase and depress economic growth, either of which, or the combination of both, could affect adversely our business, results of operations, financial position and cash flows.

•it could not pay its debts as they become due. Among other things, a legal challenge of the cross guarantees of our and ONEOK Partners' indebtedness on fraudulent conveyance grounds may focus on the benefits, if any, realized by the guarantor as a result of the issuance of such debt. To the extent the guarantor's guarantee of any such indebtedness is avoided as a result of fraudulent conveyance or held unenforceable for any other reason, the holders of such debt would cease to have any claim in respect of the guarantee.

•increased regulatory burdens; and •customer or key employee losses at an acquired business. If we consummate any future mergers or acquisitions, our capitalization and results of operations may change significantly, and investors will not have the opportunity to evaluate the economic, financial and other relevant information that we will consider in determining the application of our resources to future acquisitions.

We are exposed to the credit risk of our customers or counterparties, and our credit-risk management may not be adequate to protect against such risk. We are subject to the risk of loss resulting from nonpayment and/or nonperformance by our customers and counterparties. Our customers or counterparties may experience rapid deterioration of their financial condition as a result of changing market conditions, commodity prices or financial difficulties that could impact their creditworthiness or ability to pay us for our services. We assess the creditworthiness of our customers and counterparties and obtain collateral or contractual terms as we deem appropriate. We cannot, however, predict to what extent our business may be impacted by deteriorating market or financial conditions, including possible declines in our customers' and counterparties' creditworthiness. Our customers and counterparties may not perform or adhere to our existing or future contractual arrangements. To the extent our customers and counterparties are in financial distress or commence bankruptcy proceedings, contracts with them may be subject to renegotiation or rejection under applicable provisions of the United States Bankruptcy Code. If our risk-management policies and procedures fail to assess adequately the creditworthiness of existing or future customers and counterparties, any material nonpayment or nonperformance by our customers and counterparties due to inability or unwillingness to perform or adhere to contractual arrangements could affect adversely our business, results of operations, financial position and cash flows. Our counterparties are primarily major integrated and independent exploration and production, pipeline, marketing and petrochemical companies and natural gas and electric utilities. Therefore, our counterparties may be similarly affected by changes in economic, regulatory or other factors that may affect our overall credit risk.

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

An impairment of goodwill, long-lived assets, including intangible assets, and equity-method investments could reduce our earnings. Goodwill is recorded when the purchase price of a business exceeds the fair market value of the tangible and separately measurable intangible net assets. GAAP requires us to test goodwill for impairment on an annual basis or when events or circumstances occur indicating that goodwill might be impaired. Long-lived assets, including intangible assets with finite useful lives, are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. For the investments we account for under the equity method, the impairment test considers whether the fair value of the equity investment as a whole, not the underlying net assets, has declined and whether that decline is other than temporary. For example, if a low commodity price environment persisted for a prolonged period, it could result in lower volumes delivered to our systems and impairments of our assets or equity-method investments. If we determine that an impairment is indicated, we would be required to take an immediate noncash charge to earnings with a correlative effect on equity and balance sheet leverage as measured by consolidated debt to total capitalization. For further discussion of impairments of long-lived assets, goodwill and equity-method investments, see Notes A, F, G, and N, respectively, of the Notes to Consolidated Financial Statements in this Annual Report. The cost of providing pension and postretirement health care benefits to eligible employees and qualified retirees is subject to changes in pension fund values and changing demographics and may increase. We have defined benefit pension plans for certain employees and former employees, which are closed to new participants, and postretirement welfare plans that provide postretirement medical and life insurance benefits to certain employees. The cost of providing these benefits to eligible current and former employees is subject to changes in the market value of our pension and postretirement benefit plan assets, changing demographics, including longer life expectancy of plan participants and their beneficiaries and changes in health care costs. For further discussion of our defined benefit pension plan and postretirement welfare plans, see Note L of the Notes to Consolidated Financial Statements in this Annual Report. Any sustained declines in equity markets and reductions in bond yields may affect adversely the value of our pension and postretirement benefit plan assets. In these circumstances, additional cash contributions to our pension plans may be required, which could affect adversely our business, financial condition and cash flows. If we fail to maintain an effective system of internal controls, we may not be able to report accurately our financial results or prevent fraud. As a result, current and potential holders of our equity and debt securities could lose confidence in our financial reporting. Effective internal controls are necessary for us to provide reliable financial reports, prevent fraud and operate successfully as a public company. We cannot be certain that our efforts to maintain our internal controls will be successful, that we will be able to maintain adequate controls over our financial processes and reporting in the future or that we will be able to continue to comply with our obligations under Section 404 of the Sarbanes-Oxley Act of 2002. Any failure to maintain effective internal controls, or difficulties encountered in implementing or improving our internal controls, could harm our operating results or cause us to fail to meet our reporting obligations. Ineffective internal controls could also cause investors to lose confidence in our reported financial information, which would likely have a negative effect on the trading price of our equity, our access to capital markets and the cost of capital.

The volatility of natural gas, NGL, Refined Products and crude oil prices could affect adversely 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 significant 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) impacting supply and demand for natural gas, NGLs, Refined Products and crude oil; •production decisions by other countries, and the failure of countries to abide by recent agreements relating to production decisions; •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 (such as COVID-19); •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 liquefied natural gas; •the effect of worldwide energy-conservation measures;

We may be subject to risks associated with the physical impacts of climate change. The threat of global climate change may create physical and financial risks to our business. Some of our customers' energy needs vary with weather conditions, primarily temperature. To the extent weather conditions may be affected by climate change, customers' energy use could increase or decrease depending on the duration and magnitude of any changes. Increased energy use due to weather changes may require us to invest in more pipelines and other infrastructure to serve increased demand. A decrease in energy use due to weather changes may affect our financial condition, through decreased revenues. Extreme weather conditions in general require more system backup, adding to costs, and can contribute to increased system stresses, including damage to our assets or service interruptions. Weather conditions outside of our operating territory could also have an impact on our revenues. Severe weather impacts our operating territories primarily through hurricanes, thunderstorms, tornados, floods, freezing temperatures and snow or ice storms. To the extent the severity or frequency of extreme weather events increases, this could increase our cost of providing services, including the cost of insurance, and the availability of certain insurance coverages could decrease. We may not be able to pass on the higher costs to our customers or recover all costs related to mitigating these physical risks. Our operations are subject to operational hazards and unforeseen interruptions, which could affect adversely our business and for which we may not be adequately insured. Our operations are subject to all the risks and hazards typically associated with the operation of gathering, transportation and distribution pipelines, storage facilities and processing and fractionation facilities, which include, but are not limited to, leaks, pipeline ruptures, damage by third parties, the breakdown or failure of equipment or processes and the performance of facilities below expected levels of capacity and efficiency. Other operational hazards and unforeseen interruptions include adverse weather conditions (including extreme cold weather), infectious disease including a pandemic (such as COVID-19), cybersecurity attacks, geopolitical reactions, 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. Further, the United States government warned that energy assets, specifically the nation's pipeline infrastructure, may be targets of terrorist attacks. An act of terrorism could target our facilities, those of our suppliers or customers or those of other pipelines. 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 affect adversely our business results of operations, financial position and cash flows. Premiums and deductibles for certain insurance policies can increase substantially, and, in some instances, certain insurance may become unavailable or available only for reduced amounts of coverage. Consequently, we may not be able to renew existing insurance policies or purchase other desirable insurance on commercially reasonable terms, if at all. Insurance proceeds may not be adequate to cover all liabilities or incurred costs and losses or lost earnings. Further, we are not fully insured against all risks inherent to our business. If we were to incur a significant liability for which we were not fully insured, it could affect adversely our business, results of operations, financial position and cash flows. Further, the proceeds of any such insurance may not be paid in a timely manner.

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 producer's natural gas. After performing these services, we sell the commodities and remit a portion of the commodity sales proceeds to the producer less our contractual fees. This type of contract represented 72% and 73% of supply volumes in this segment for 2023 and 2022, 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 primarily the residue natural gas 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% and 20% of supply volumes in this segment for 2023 and 2022, respectively. •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 9% and 7% of supply volumes in this segment for 2023 and 2022, 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 that are extracted at natural gas processing plants, both third-party and our own, are gathered by our NGL gathering pipelines. Gathered NGLs are directed to our downstream fractionators in the Mid-Continent and Gulf Coast regions to be separated into Purity NGLs. Purity NGLs are stored or distributed to our customers, such as petrochemical companies, propane distributors, heating fuel users, ethanol producers, refineries and exporters. We own and operate facilities primarily in Oklahoma, Kansas, Texas, New Mexico and the Rocky Mountain region, which includes the Williston, Powder River and DJ Basins. We provide midstream services to producers of NGLs and deliver those products to the two primary market centers: one in the Mid-Continent in Conway, Kansas, and the other in the Gulf Coast in Mont Belvieu, Texas. We own or have an ownership interest in FERC-regulated NGL gathering and distribution pipelines in Oklahoma, Kansas, Texas, New Mexico, Montana, North Dakota, Wyoming and Colorado, and terminal and storage facilities in Kansas, Nebraska, Iowa and Illinois. We have a 50% ownership interest in Overland Pass, which operates an interstate NGL pipeline originating in Wyoming and Colorado and terminating in Kansas. The majority of the pipeline-connected natural gas processing plants in the Williston Basin, Oklahoma, Kansas and the Texas Panhandle are connected to our NGL gathering systems. We lease rail cars and own and operate truck- and rail-loading and -unloading facilities connected to our NGL fractionation, storage and pipeline assets. We also own FERC-regulated NGL distribution pipelines in Kansas, Nebraska, Iowa, Illinois and Indiana that connect our Mid-Continent assets with Midwest markets, including Chicago, Illinois. A portion of our ONEOK North System transports Refined Products, including unleaded gasoline and diesel.

•1,500 miles of FERC-regulated interstate natural gas pipelines with 3.7 Bcf/d of transportation capacity; and •six underground natural gas storage facilities with 57.4 Bcf of total active working natural gas storage capacity. Our storage includes two underground natural gas storage facilities in Oklahoma, two underground natural gas storage facilities in Kansas and two underground natural gas storage facilities in Texas. In 2023, we completed an expansion of our injection capabilities of our Oklahoma natural gas storage facilities which allowed us to utilize and subscribe an additional 4 Bcf of our existing storage capacity. We are reactivating previously idled storage facilities with 3 Bcf of working gas storage capacity in Texas, which is not included in the capacity above. We are also further expanding our injection capabilities in Oklahoma to allow us to subscribe additional firm storage capacity. Our natural gas pipelines were 96% and 94% subscribed in 2023 and 2022, respectively, and our natural gas storage facilities were 76% and 77% subscribed in 2023 and 2022, respectively.

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. In February 2024, the FERC approved our Saguaro Connector Pipeline, L.L.C.'s Presidential Permit application to construct and operate new international border-crossing facilities at the U.S. and Mexico border. The proposed border facilities would connect upstream with a potential intrastate pipeline, the Saguaro Connector pipeline. Additionally, the proposed border facilities would connect at the international boundary with a new pipeline under development in Mexico for delivery to a liquefied natural gas export facility on the west coast of Mexico. The final investment decision on the Saguaro Connector pipeline is expected by mid-year 2024.

•current and forward natural gas, NGLs, Refined Products and crude oil prices; and •cost of and access to capital. We have remained competitive by making capital investments to access and connect new supplies with end-user demand; increasing gathering, processing, fractionation and pipeline capacity; increasing storage, withdrawal and injection capabilities; and improving operating efficiency. Our and our competitors' infrastructure projects may affect commodity prices and could displace supply volumes from the Mid-Continent and Rocky Mountain regions and the Permian Basin where our assets are located. We believe our assets are located strategically, connecting diverse supply areas to market and demand centers. Customers - Our Natural Gas Gathering and Processing, Natural Gas Liquids and Refined Products and Crude segments derive services revenue from major and independent crude oil and natural gas producers. Our Natural Gas Liquids segment's customers also include other NGL and natural gas gathering and processing companies. Our downstream commodity sales customers are primarily petrochemical, refining and marketing companies, utilities, large industrial companies, natural gasoline distributors, propane distributors and municipalities. Our Refined Products and Crude segment's customers also include crude oil producers, refiners, wholesalers, retailers, traders, railroads, airlines and regional farm cooperatives. End markets for Refined Products deliveries are primarily retail gasoline stations, truck stops, farm cooperatives, railroad fueling depots, military bases and commercial airports. Our Natural Gas Pipeline segment's assets primarily serve LDCs, electric-generation facilities, large industrial companies, municipalities, producers, processors and marketing companies. Our utility customers generally require our services regardless of commodity prices. See discussion regarding our customer credit risk under "Counterparty Credit Risk" in Part II, Item 7A, Quantitative and Qualitative Disclosures about Market Risk, in this Annual Report.

Regulation PHMSA - The PHMSA has submitted to the Federal Register an advisory bulletin underscoring to pipeline and pipeline facility operators 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 at 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. 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 of these 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. Recently, the EPA has released the pre-publication of the New Source Performance Standards Subpart OOOOb regulations to further reduce methane emissions, which includes increased monitoring frequency and more stringent repair requirements for new and modified oil and gas facilities. In addition, the EPA is proposing new nationwide emission guidelines, OOOOc, for states to limit methane emissions from existing oil and gas facilities. 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. 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, the transportation fuel we produce in our liquids blending activities must either contain the mandated renewable fuel components, or credits must be purchased to cover any shortfall. We generally satisfy our RVO requirements through the purchase of renewable energy credits, known as 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 costs to comply with the RFS standards or limit our ability to blend. The EPA has proposed changes to the 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 or pending regulations and proposed EPA actions. Additionally, we are subject to the EPA's fuels compliance regulations. These regulations include standards for fuel parameters and require rigorous product sampling and testing, recordkeeping and reporting. Our ongoing compliance with these regulations is not expected to have a material adverse effect on our business. Federal Regulation - In August 2022, the IRA was signed into law. The IRA includes tax credits and other incentives intended to combat climate change by advancing decarbonization and promoting increased investment in renewable and low carbon intensity energy. In addition, the IRA directed the EPA to impose and collect "Waste Emissions Charges," or "Methane Fees," for specific facilities that report more than 25,000 metric tons of carbon dioxide equivalent of GHG emissions per year and have a methane emissions intensity in excess of the relevant statutory threshold. Based on text in the IRA and a related rule that the EPA proposed in January 2024 that will require payment of Methane Fees to the EPA beginning in 2025 (for 2024 reported emissions), we do not believe the Methane Fees will have a material impact on our results of operations, financial position or cash flows. We believe it is likely that continued future governmental legislation and/or regulation may require us to limit GHG emissions associated with our operations, pay additional fees associated with our GHG emissions or purchase allowances for such emissions. However, we cannot predict precisely what form these future regulations will take, the stringency of the regulations, when they will become effective or the impact on our capital expenditures, competitive position and results of operations. In addition to activities on the federal level, state and regional initiatives could also lead to the regulation of GHG emissions sooner than or independent of federal regulation. These regulations could be more stringent than any federal legislation that may be adopted. We monitor all relevant legislation and regulatory initiatives to assess the potential impact on our operations and otherwise take steps to limit GHG emissions from our facilities, including methane.

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. D&I 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. As of December 31, 2023, 96% of eligible employees were contributing to our 401(k) Plan. For additional information about our retirement benefits, see Note L of the Notes to Consolidated Financial Statements in this Annual Report.

•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 North Dakota, Montana, Wyoming, Kansas and Oklahoma. 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 Wyoming, which includes the NGL-rich Niobrara, Frontier, Turner and Mowry formations where we provide gathering and processing services to customers in the eastern portion of the state. Mid-Continent region - The Mid-Continent region includes the gas and oil-producing Anadarko Basin, which includes the NGL-rich SCOOP and STACK areas, including the Cana-Woodford Shale, Woodford Shale, Springer Shale, Meramec, Granite Wash and Mississippian Lime formations of Oklahoma and the Hugoton Basin in Kansas. We have more than 600,000 dedicated acres in the Anadarko Basin.

Property - Our Natural Gas Liquids segment includes the following assets: •9,140 miles of gathering pipelines with operating capacity of 1,790 MBbl/d, including 6,350 miles of FERC-regulated pipelines with operating capacity of 1,490 MBbl/d; •4,350 miles of distribution pipelines with operating capacity of 1,150 MBbl/d, including 4,180 miles of FERC-regulated pipelines with operating capacity of 1,080 MBbl/d; •seven NGL fractionators with combined operating capacity of 710 MBbl/d (includes interests in our proportional share of operating capacity), including 310 MBbl/d in the Mid-Continent region and 400 MBbl/d in the Gulf Coast region; •one isomerization unit with operating capacity of 10 MBbl/d; •one ethane/propane splitter with operating capacity of 40 MBbl/d;

Our storage earnings are primarily fee-based from the following types of services: •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. 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. Utilization - Our natural gas pipelines were 94% and 95% subscribed in 2022 and 2021, respectively, and our natural gas storage facilities were 77% and 70% subscribed in 2022 and 2021, respectively.

HUMAN CAPITAL The long-term sustainability of our business is dependent on our continued ability to maintain a highly engaged workforce. To accomplish this, our business strategy includes attracting, selecting and retaining talent, advancing an inclusive, diverse and engaged culture and developing individuals and leaders. In 2021, we conducted our first annual employee engagement survey using Gallup Inc.'s Q12 methodology. All leaders were asked to review their results with their teams and create an action plan specific to enhancing their employees' engagement in 2022. In 2022, the annual employee engagement participation rate increased to 90% compared with 80% in 2021. The overall engagement mean went from under the 40th percentile to above the 50th percentile. We showed improvement on all survey questions. The ratio of engaged employees to actively disengaged more than doubled. All leaders have been asked to discuss the 2022 survey results with their teams and create an engagement action plan for 2023. Training and support resources are also available through our learning management system, the Gallup Engagement Portal and dedicated individuals within our human resources department. As of December 31, 2022, we had 2,966 employees. Listed below is a summary of our human capital resources, measures and objectives that are collectively important to our success as an organization. Values - Our success relies on the skills, experience and dedication of our employees. We are committed to cultivating an inclusive and dynamic work environment where talented people can find opportunities to succeed, grow and contribute to the success of the company. Our employees work each day to provide safe and reliable services to a wide range of customers in the states where we operate. Our core values, listed below, guide the way in which our employees conduct our business and operations. •Safety & Environmental: we commit to a zero-incident culture for the well-being of our employees, contractors and communities and to operate in an environmentally responsible manner.

2015 to 2019Director, SEC Reporting, ONEOK Scott D. Schingen492021 to presentSenior Vice President, Operations, ONEOK Senior Vice President, Operations2017 to 2021Vice President, Natural Gas Liquids Operations, ONEOK

•six NGL storage facilities with operating storage capacity of 30 MMBbl; and •eight Purity NGLs terminals. In addition, we have access to 5 MMBbl of combined NGL storage capacity at facilities in Kansas and Texas and 60 MBbl/d of NGL fractionation capacity in the Gulf Coast through service agreements. The operating capacity of our pipelines varies depending on pipeline diameter, product composition and segment of the system. As a result, we consider throughput a more useful measure of utilization, which is provided within "Selected Financial Results and Operating Information" in Part II, Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations, in this Annual Report. We are in the process of constructing our 125 MBbl/d MB-6 NGL fractionator in Mont Belvieu, Texas, the full looping of our West Texas NGL pipeline and expansion of our Elk Creek pipeline. These projects are excluded from the assets listed above. As a result of the Medford incident, our 210 MBbl/d NGL fractionator in Medford, Oklahoma, is not currently operational and is excluded from the assets listed above. See "Recent Developments" in Part II, Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations, in this Annual Report for more information on our capital projects. Sources of Earnings - Earnings for our Natural Gas Liquids segment are derived primarily from commodity sales and purchases and fee-based services. We purchase NGLs and condensate from third parties, as well as from our Natural Gas Gathering and Processing segment. Our business activities are categorized as follows: •Exchange services - We utilize our assets to gather, transport, treat and fractionate NGLs, thereby 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 FERC-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 primarily transport Purity NGLs between Conway, Kansas, and Mont Belvieu, Texas, to capture the location price differentials between the two market centers. Our marketing activities also include utilizing our NGL storage facilities to capture seasonal price differentials and serving 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. Our other unconsolidated affiliates in this segment are not material.

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. Continued demand from LDCs, electric- generation facilities and large industrial companies supported low-cost expansions that position us well to provide additional services to our customers when needed. Intrastate Pipelines and Storage - Our intrastate natural gas pipeline and storage assets are located in Oklahoma, Texas and Kansas. 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; and •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 5 Bcf of working gas storage capacity. Interstate Pipelines - Our interstate pipelines are regulated by the FERC and are located in North Dakota, Minnesota, Wisconsin, Illinois, Indiana, Kentucky, Tennessee, Oklahoma, Texas and New Mexico. Our interstate pipeline companies include: •Guardian, which interconnects with several pipelines at the Chicago Hub near Joliet, Illinois, and with local natural gas distribution and electric generation companies in Wisconsin; •Midwestern Gas Transmission, which is a bidirectional system that interconnects with Tennessee Gas Transmission Company's pipeline near Portland, Tennessee, and with multiple interstate pipelines that have access to both the Utica Shale and the Marcellus Shale, and multiple interstate pipelines at the Chicago Hub near Joliet, Illinois; •Viking, which is a bidirectional system that interconnects with TC Energy Corporation's Canadian Mainline System at the United States border near Emerson, Canada, and ANR Pipeline Company near Marshfield, Wisconsin; and

•OkTex Pipeline, which has interconnections with several pipelines in Oklahoma, Texas and New Mexico. Property - Our Natural Gas Pipelines segment includes the following wholly owned assets: •5,100 miles of state-regulated intrastate transmission pipelines with transportation capacity of 4.5 Bcf/d;

Sources of Earnings - Earnings in this segment are derived primarily from transportation and storage services. Our transportation earnings are primarily fee-based from the following types of services: •Firm service - Customers reserve a fixed quantity of pipeline capacity for a specified period of time, which obligates the customer to pay regardless of usage. Under this type of contract, the customer pays a monthly fixed fee and incremental fees, known as commodity charges, which are based on the actual volumes of natural gas they transport or store. Under the firm service contract, the customer generally is guaranteed access to the capacity they reserve. •Interruptible service - Under interruptible service transportation agreements, the customer may utilize available capacity after firm service requests are satisfied. The customer is not guaranteed use of our pipelines unless excess capacity is available. Our regulated natural gas transportation services contracts are based upon rates stated in the respective tariffs, which have generally been established through shipper specific negotiation, discounts and negotiated settlements. The rates are filed with FERC or the appropriate state jurisdictional agencies. In addition, customers typically are assessed fees, such as a commodity charge, and we may retain a percentage of natural gas in-kind for our compression services.

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 and the decline rate of existing production; 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 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 in the regions in which we operate, as well as by takeaway demand in the Houston and Cushing areas. Demand for natural gas, NGLs, Refined Products and crude oil is also impacted by global macroeconomic factors. Commodity Prices - 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. We have hedged approximately 60% of our forecasted equity volumes for our Natural Gas Gathering and Processing segment in 2024. 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 Mid-Continent, Chicago, Illinois, and Gulf Coast regions; 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. NGL storage revenue may be affected by price volatility and forward pricing of NGL physical contracts versus the current price of NGLs on the spot market. In our Natural Gas Pipelines segment, we are exposed to minimal commodity price risk associated with (i) changes in the price of natural gas, which impact our fuel costs and retained fuel in-kind received for our compression services; and (ii) the differential between forward pricing of natural gas physical contracts and the price of natural gas on the spot market, which may affect our customer demand for our natural gas storage services. In our Refined Products and Crude segment, we are exposed to commodity price risk, including product price and location differentials from our liquids blending and marketing activities, as well as product retained during the operations of our pipelines and terminals. See additional discussion regarding our commodity price risk and related hedging activities under "Commodity Price Risk" in Part II, Item 7A, Quantitative and Qualitative Disclosures about Market Risk, in this Annual Report. Seasonality - Cold temperatures usually increase demand for natural gas and certain Purity NGLs, such as propane, a heating fuel for homes and businesses. Warm temperatures usually increase demand for natural gas used in gas-fired electric generation for residential and commercial cooling, as well as agriculture-related equipment like irrigation pumps and crop dryers. Demand for butanes and natural gasoline, which are used by the refining industry as blending stocks for motor fuel, denaturant for ethanol and diluents for crude oil, are also subject to some variability during seasonal periods when certain government restrictions on motor fuel blending products change. Additionally, our liquids blending activities are limited by seasonal changes in gasoline vapor pressure specifications and by the varying quantity of the gasoline delivered to us. During periods of peak demand for a certain commodity, prices for that product typically increase.

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

REGULATORY, ENVIRONMENTAL AND SAFETY MATTERS We are subject to a variety of historical preservation and environmental laws and/or regulations that affect many aspects of our present and future operations. Regulated activities include, but are not limited to, those involving air emissions, storm water and wastewater discharges, handling and disposal of solid and hazardous waste, wetland and waterway preservation, wildlife conservation, cultural resource protection, hazardous materials transportation and pipeline and facility construction. These laws and regulations require us to obtain and/or comply with a wide variety of environmental clearances, registrations, licenses, permits and other approvals. Failure to comply with these laws, regulations, licenses and permits may expose us to fines, penalties, reputational harm and/or interruptions in our operations that could be material to our results of operations or financial condition. In addition, emissions controls and/or other regulatory or permitting mandates under the Clean Air Act and other similar federal and state laws could require unexpected capital expenditures at our facilities. We cannot ensure that existing environmental statutes and regulations will not be revised or that new regulations will not be adopted or become applicable to us. We also cannot ensure that existing permits will not be revised or cancelled, potentially impacting facility construction activities or ongoing operations. Air and Water Emissions - The Clean Air Act, the Clean Water Act, the Oil Pollution Act of 1990 and analogous state laws and/or regulations impose restrictions and controls regarding the discharge of pollutants into the air and water in the United States. Under the Clean Air Act, a federal operating permit is required for sources of significant air emissions. We may be required to incur certain capital expenditures for air pollution-control equipment in connection with obtaining or maintaining permits and approvals for sources of air emissions. The Clean Water Act imposes substantial potential liability for pollutants discharged into waters of the United States and requires remediation of waters affected by such discharge. The Oil Pollution Act aims at preventing and responding to oil spills in U.S. waters and shorelines. GHG Emissions - 2022 GHG emissions were approximately 3.7 million metric tons of carbon dioxide equivalents of Scope 1 emissions and 2.9 million metric tons of carbon dioxide equivalents of Scope 2 emissions. Scope 1 emissions originate from the combustion of fuel in our equipment, such as compressor engines and heaters, as well as fugitive methane emissions. Scope 2 emissions are generated from purchased power sources. In 2021, we announced a companywide absolute GHG emissions reduction target of 2.2 million metric tons of carbon dioxide equivalents from our combined Scope 1 and Scope 2 GHG emissions by 2030 for our legacy ONEOK assets. The target represents a 30% reduction in combined operational Scope 1 and location-based Scope 2 GHG emissions attributable to ONEOK assets as of December 31, 2019. As of December, 31, 2023, we have achieved reductions totaling approximately 1.1 million metric tons of the targeted 2.2 million metric tons of carbon dioxide equivalents, primarily as a result of methane emissions mitigation, system optimizations, electrification of certain natural gas compression equipment and lower carbon-based electricity in states in which we operate. GHG emission reductions as reported may be modified, updated, changed or supplemented based on available information. For the years ended December 31, 2023, 2022 and 2021, we did not have any material dedicated capital expenditures specifically for climate-related projects, nor did we purchase or sell carbon credits or offsets. Progress to date on our goal has been accomplished through routine capital projects and asset optimizations that were primarily performed for operational improvements that inherently improved our emissions profile. We continue to anticipate several potential pathways toward achieving our emissions reduction target. In 2024, we anticipate reduction in our emissions toward our target to be primarily a result of improved methane management practices and system optimization that will not require material capital expenditures. We do not anticipate purchasing or selling carbon credits or offsets in 2024. We currently participate in Our Nation's Energy (ONE) Future Coalition to voluntarily report methane emission reductions and to calculate our methane intensity for our natural gas transmission and storage assets. We continue to focus on maintaining low methane gas release rates through expanded implementation of improved practices to limit the release of natural gas during pipeline and facility maintenance and operations. In 2023, we became a participant in American Petroleum Institute's The Environmental Partnership and enrolled in environmental performance programs that are designed to further reduce emissions using proven, cost-effective controls.

•Innovation: we seek to develop creative solutions by leveraging collaboration through ingenuity and technology. Diversity and Inclusion - Our diversity and inclusion (D&I) 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 D&I 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 D&I efforts. In early 2023, we introduced a Racial Inclusion Collective Resource Group that combines our legacy race- and ethnicity-focused business resource groups (BRGs), along with new resources and support for our Asian-American and Pacific Islander employees and allies, into a single organization to facilitate collaboration on topics relevant to all groups while reserving opportunities for more identity-focused programming where appropriate. We provide funding and support for this group as well as our other employee-led BRGs: a Veterans Resource Group, a Women's Resource Group and a LGBTQ+ Resource Group (Lesbian, Gay, Bisexual, Transgender, Queer and others). The purpose of these groups is to promote the attraction, development, motivation and retention of 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 a supporter of our BRGs. We embed D&I concepts into our core leadership development curriculum and sponsor a number of internal programs intended to promote D&I. 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. 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 240 hours 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. 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 a 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 professional who is interested in developing their skills, we provide education and training in a variety of areas, including leadership, functional and industry-specific topics, professional development and skill-building opportunities. Our organizational development and D&I teams provide live in-person and virtual classroom training, computer-based self-study and one-on-one coaching that is available to all employees. 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.

Name and PositionAgeBusiness Experience in Past Five Years Julie H. Edwards652022 to presentBoard Chair, ONEOK Board Chair2007 to 2022Board Director, ONEOK

Pierce H. Norton II642021 to presentPresident and Chief Executive Officer, ONEOK President and Chief Executive Officer2021 to presentMember of the Board of Directors, ONEOK

2017 to 2019Chief Financial Officer and Executive Vice President, Strategic Planning and Corporate Affairs, ONEOK Kevin L. Burdick592023 to presentExecutive Vice President and Chief Enterprise Services Officer, ONEOK

Mary M. Spears442022 to presentSenior Vice President and Chief Accounting Officer, Finance and Tax, ONEOK Senior Vice President and Chief Accounting Officer, Finance and Tax2019 to 2021Vice President and Chief Accounting Officer, ONEOK

BUSINESS STRATEGY Our mission is to deliver energy products and services vital to an advancing world. Our vision is to create exceptional value for our stakeholders by providing solutions for a transforming energy future. Our business strategy is focused on: •Zero incidents - We commit to developing processes to drive a zero-incident culture for the well-being of our employees, contractors and communities. Safety and environmental responsibility continue to be primary areas of focus for us, and our emphasis on safety has produced improving trends in the key indicators we track. •Highly engaged workforce - We strive to be an employer of choice and continue to focus on attracting, selecting and retaining talent, advancing an inclusive, diverse and engaged culture and developing individuals and leaders. •Sustainable business model - We aim to maintain prudent financial strength and flexibility while operating a safe, reliable and resilient asset base. We seek to maintain investment-grade credit ratings and a strong balance sheet. We expect our internally generated cash flows will allow us to fund high-return capital projects in our existing operating regions, grow our dividend, reduce debt and fund our $2.0 billion share repurchase program. We aim to focus on capital projects that provide value-added products and services that contribute to long-term growth, profitability and business diversification. We continue to actively research opportunities that will complement our extensive assets and expertise, strengthening the role we expect to play in the transformation to a lower-carbon economy. •Maximizing total shareholder return - We plan to grow earnings through high-return capital projects that will allow us to increase our dividend and repurchase shares under our $2.0 billion share repurchase program. We expect consistent and strong returns on invested capital will allow us to reward our shareholders and provide the means and opportunity to serve our additional stakeholders, including employees, communities and the environment.

NARRATIVE DESCRIPTION OF BUSINESS We report operations in the following four business segments: •Natural Gas Gathering and Processing; •Natural Gas Liquids;

Property - Our Natural Gas Gathering and Processing segment includes the following assets, which are wholly owned, except where noted: •17,400 miles of natural gas gathering pipelines; •14 natural gas processing plants with 1.9 Bcf/d of processing capacity in the Rocky Mountain region, and nine natural gas processing plants with 0.9 Bcf/d of processing capacity in the Mid-Continent region, and up to 150 MMcf/d of processing capacity in the Mid-Continent region through a long-term processing services agreement with an unaffiliated third party; and