What changed in this filing

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Item 1. Business

2025-02-25 compared with 2024-02-27 · 332 added, 301 removed, 290 unchanged (69% of the section changed)

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and around the world.

Through our more than 50,000-mile pipeline network, we transport the natural gas, NGLs, Refined Products and crude oil that help meet domestic and international energy demand, contribute to energy security and provide safe, reliable and responsible energy solutions needed today and into the future.

Through our now approximately 60,000-mile pipeline network, we transport the natural gas, NGLs, Refined Products and crude oil that help meet domestic and international energy demand, contribute to energy security and provide safe, reliable and responsible energy solutions needed today and into the future.

Midstream Value Chain

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After crude oil and natural gas are produced from upstream wells, we use our extensive infrastructure to process and transport these raw materials, readying them for end use.

For transportation of crude oil, natural gas, Refined Products and NGLs, pipelines are generally the most reliable, lowest cost, least carbon intensive and safest alternative for intermediate and long-haul movements between markets.

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EXECUTIVE SUMMARY

Magellan Acquisition - On September 25, 2023, we completed the Magellan Acquisition.

The acquisition strategically diversifies our complementary asset base and allows for significant expected synergies.

Pursuant to the Merger Agreement, each common unit of Magellan was exchanged for a fixed ratio of 0.667 shares of ONEOK common stock and $25.00 of cash, for a total consideration of $14.1 billion.

In addition, we assumed Magellan’s debt at the fair value of $4.0 billion.

We issued approximately 135 million shares of common stock, with a fair value of approximately $9.0 billion as of the closing date of the Magellan Acquisition.

We funded the cash portion of the acquisition with an underwritten public offering of $5.25 billion senior unsecured notes.

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

See Part 1, Item 1A “Risk Factors” for further discussion of risks related to the Magellan Acquisition.

Business Update and Market Conditions - We experienced increased volumes across our system in 2023, compared with 2022, highlighting our extensive and integrated assets located in, and connected with, some of the most productive shale basins, refining regions and demand centers in the United States.

Although the energy industry has experienced many commodity cycles, we have positioned ourselves to reduce exposure to direct commodity price volatility.

Each of our four reportable segments are primarily fee-based, and our consolidated earnings were more than 85% fee-based in 2023.

Medford Incident - 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 that occurred at our 210 MBbl/d Medford, Oklahoma, NGL fractionation facility in July 2022.

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, resulting in a one-time settlement gain of $779 million.

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.

Due to market demand and a more favorable completion schedule, in January 2023, we announced plans to construct a new 125 MBbl/d MB-6 NGL fractionator in Mont Belvieu, Texas, instead of immediately rebuilding our Medford NGL fractionator.

The MB-6 fractionator is expected to be in service in the first quarter of 2025 and will produce purity ethane instead of the ethane/propane mix previously produced at the Medford facility.

The 125 MBbl/d capacity of the MB-6 fractionator is expected to be economically comparable to the capacity lost at Medford.

In addition, our 125 MBbl/d MB-5 NGL fractionator was completed in April 2023, which has reduced the need for third-party fractionation while the new MB-6 fractionator is being constructed.

For additional information on the Medford Incident, see Part II, Item 8, Note C of the Notes to Consolidated Financial Statements in this Annual Report.

EnLink Controlling Interest Acquisition - On Aug.

28, 2024, we entered into the EnLink Purchase Agreement with GIP to acquire GIP’s interest in EnLink consisting of approximately 43% of the outstanding EnLink Units for $14.90 in cash per unit and 100% of the outstanding limited liability company interests in the managing member of EnLink for $300 million, for total cash consideration of $3.3 billion.

15, 2024, we completed the EnLink Controlling Interest Acquisition.

We used a portion of the proceeds from our September 2024 underwritten public offering of $7.0 billion senior unsecured notes to fund this acquisition.

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

We expect to achieve significant synergies by combining our complementary asset positions.

The operations of EnLink are reported across all four of our existing segments.

EnLink Acquisition - On Nov.

24, 2024, we entered into the EnLink Merger Agreement to acquire all of the publicly held EnLink Units in an all stock, tax-free transaction.

31, 2025, we completed the EnLink Acquisition.

Pursuant to the EnLink Merger Agreement, each common unit of EnLink was exchanged for a fixed ratio of 0.1412 shares of ONEOK common stock, including EnLink Units that were exchanged for all previously outstanding Series B Preferred Units immediately prior to closing.

We issued 41 million shares of common stock, with a fair value of $4.0 billion as of the closing date of the EnLink Acquisition.

EnLink is now a wholly owned subsidiary.

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

In addition, see Part 1, Item 1A “Risk Factors” for further discussion of related risks.

Medallion Acquisition - On Aug.

28, 2024, we entered into the Medallion Purchase and Sale Agreement with GIP to acquire all of the equity interests in Medallion for a purchase price of $2.6 billion, subject to customary adjustments, and inclusive of the purchase of additional interests in a Medallion joint venture owned by a separate third party.

31, 2024, we completed the Medallion Acquisition.

We used a portion of the proceeds from our September 2024 underwritten public offering of $7.0 billion senior unsecured notes to fund this acquisition.

This acquisition expands our midstream services for crude oil and condensate in West Texas, specifically in the Midland Basin.

Medallion’s operations are reported in our Refined Products and Crude segment.

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

See Part 1, Item 1A “Risk Factors” for further discussion of risks related to the Medallion Acquisition.

Joint Ventures - On Feb.

4, 2025, we entered into definitive agreements to form joint ventures with MPLX LP (MPLX) to construct a 400 MBbl/d liquified petroleum gas export terminal in Texas City, Texas, and a new 24-inch pipeline from our Mont Belvieu, Texas, storage facility to the new terminal.

Texas City Logistics LLC, the export terminal joint venture, is owned 50% by us and 50% by MPLX, with MPLX constructing and operating the facility.

MBTC Pipeline LLC, the pipeline joint venture, is owned 80% by us and 20% by MPLX, and we will construct and operate the pipeline.

We expect to invest approximately $1.0 billion in these projects.

Interstate Natural Gas Pipeline Divestiture - On Nov.

19, 2024, we entered into a definitive agreement with DT Midstream, Inc.

to sell three of our wholly owned interstate natural gas pipeline systems for total cash consideration of $1.2 billion.

31, 2024, we completed the sale and recognized a gain of $227 million.

This transaction aligns and enhances our capital allocation priorities within our integrated value chain.

Gulf Coast NGL Pipelines Acquisition - In June 2024, we completed the acquisition of a system of NGL pipelines from Easton Energy, a Houston-based midstream company, for approximately $280 million.

This acquisition in our Natural Gas Liquids segment includes approximately 450 miles of liquids products pipelines located in the strategic Gulf Coast market centers for NGLs, Refined Products and crude oil.

A portion of the Easton assets are connected to our Mont Belvieu assets.

We expect to add connections to our Houston-based assets beginning in mid-2025 through the end of 2025.

Business Update and Market Conditions - Over the past year, we experienced significant growth across our value chain due to our recent acquisitions.

Earnings increased in 2024, compared with 2023, due primarily to a full year of earnings from the new Refined Products and Crude segment, higher NGL and natural gas processing volumes in the Rocky Mountain region and the impact of the interstate pipeline divestiture in the Natural Gas Pipelines segment.

Our extensive and integrated assets are located in, and connected with, some of the most productive shale basins, as well as refineries and demand centers, in the United States.

Although the energy industry has experienced many commodity cycles, we have positioned ourselves to reduce

exposure to direct commodity price volatility.

Each of our four reportable segments are primarily fee-based, and our consolidated earnings were approximately 90% fee-based in 2024.

Capital Allocation - We continue to focus on maintaining prudent financial strength and flexibility.

In January 2024, our Board of Directors increased our quarterly dividend to 99 cents per share and announced a targeted 3% to 4% annual dividend growth rate.

Our Board of Directors also authorized a share repurchase program to buy up to $2.0 billion of our outstanding common stock and targets it to be largely utilized over the next four years.

Additionally, in the fourth quarter of 2023, we opportunistically repurchased in the open market $322 million of our senior notes at a discount to par value using operating cash flows.

At December 31, 2023, we had $338 million of cash and cash equivalents and no borrowings under our $2.5 Billion Credit Agreement.

Sustainability and Social Responsibility - Through our participation in the 2023 S&P Global Corporate Sustainability Assessment, we qualified for inclusion in the S&P Global Sustainability Yearbook for the fourth consecutive year, scoring within the top 15% of the Oil and Gas Storage and Transportation industry.

In 2023, we qualified for inclusion in the Dow Jones Sustainability North American Index, part of the Dow Jones Sustainability Indices, which recognizes global sustainability leaders.

In January 2025, our Board of Directors increased our quarterly dividend to $1.03 per share, an increase of 4% compared with the same quarter in the prior year.

In January 2024, our Board of Directors authorized a share repurchase program to buy up to $2.0 billion of our outstanding common stock.

31, 2024, we repurchased $172 million of our outstanding common shares under the program.

31, 2024, we also had $733 million of cash and cash equivalents on hand and $2.5 billion of available capacity under our $2.5 Billion Credit Agreement.

Sustainability and Social Responsibility - Through our participation in the 2024 S&P Global Corporate Sustainability Assessment, we qualified for inclusion in the S&P Global Sustainability Yearbook for the fifth consecutive year, scoring within the top 15% of the Oil and Gas Storage and Transportation industry.

Additionally, in 2024, we received an MSCI ESG Rating of AAA, and our ESG Risk Rating, as assessed by Morningstar Sustainalytics, was in the top 20% of the refiners and pipelines industry.

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.

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.

We have achieved reductions totaling approximatel y 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.

We continue to

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look for ways to reduce our GHG emissions and utilize more efficient technologies.

We are evaluating the development of renewable energy and low-carbon projects, including opportunities that may complement our extensive midstream assets and expertise.

For more information on our GHG emissions, see “GHG emissions” in the “Regulatory, Environmental and Safety Matters” section.

Natural Gas - In our Natural Gas Gathering and Processing segment, processed volumes increased in 2023, compared with 2022, 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.

In our Natural Gas Pipelines segment, we completed an expansion of the injection capabilities of our Oklahoma natural gas storage facilities, which allowed us to utilize and subscribe an additional 4 Bcf of existing storage capacity, which is fully subscribed through 2027 and 90% subscribed through 2029.

In addition, we completed the electrification of certain compression assets on Viking to maintain reliability of our operations while lowering our Scope 1 emissions from this equipment.

Viking is seeking to recover its investment in the project through a proposed increase in rates filed in July 2023.

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.

NGLs - In our Natural Gas Liquids segment, we benefited from increased volumes in 2023, compared with 2022, due primarily to increased production in the Permian Basin and Rocky Mountain region.

In addition to construction of our MB-6 fractionator, activities are underway to complete the looping of the West Texas NGL pipeline, which will more than double our NGL capacity out of the Permian Basin.

The full loop is expected to be in service in the first quarter of 2025.

We also have begun initial work, primarily on long-lead-time components, towards expanding the Elk Creek pipeline to 435 MBbl/d to provide capacity for growing volumes in the Rocky Mountain region, which will bring our total pipeline capacity out of the Rocky Mountain region to 575 MBbl/d.

The Elk Creek pipeline expansion is expected to be in service in the first quarter of 2025.

Refined Products and Crude - Our 2023 results include the period from September 25, 2023, to December 31, 2023.

During this time, we benefited from mid-year tariff increases and long-haul shipments of Refined Products, as well as increased shipments on our crude oil system compared to the pre-acquisition period.

Additionally, our liquids blending margins have remained strong due to favorable commodity market conditions.

Progress continues on the expansion of our Refined Products pipeline to El Paso, Texas, which is expected to be completed in early 2024.

This expansion will connect more supply to growing markets in Texas, New Mexico, Arizona and Mexico and the majority of the capital associated with this expansion is supported by volume commitments.

Natural Gas Gathering and Processing - In our Natural Gas Gathering and Processing segment, earnings increased in 2024, compared with 2023, due to higher volumes in the Rocky Mountain region, as well as the impact of the EnLink Controlling Interest Acquisition from the period of Oct.

15, 2024, to Dec.

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

NGLs - In our Natural Gas Liquids segment, earnings decreased in 2024, compared with 2023, due primarily to the insurance settlement gain in 2023 related to the Medford incident, which was offset partially by higher volumes in the Rocky Mountain region and the impact of the EnLink Controlling Interest Acquisition from the period of Oct.

15, 2024, to Dec.

In December 2024, we announced that we completed construction of our 125 MBbl/d MB-6 NGL fractionator and the looping of the West Texas NGL pipeline.

Additional pump stations, which are expected to be completed in mid-2025, will further increase system capacity to 740 MBbl/d, more than doubling our NGL capacity out of the Permian Basin.

In January 2025, we completed construction of our Elk Creek pipeline expansion project, which is partially in service.

Upon supply of full power, expected in mid-2025, we will have capacity of 435 MBbl/d to transport growing volumes in the Rocky Mountain region, which will bring our total pipeline capacity out of the Rocky Mountain region to 575 MBbl/d.

In August 2024, we announced plans to rebuild our 210 MBbl/d NGL fractionator in Medford, Oklahoma.

Rebuilding at Medford provides strategic benefits that include expansion options that will allow our integrated system to accommodate volume growth from the Permian Basin and the Rocky Mountain and Mid-Continent regions.

The Medford fractionator will also produce butane and natural gasoline for incremental Refined Products and diluent blending opportunities in the Mid-Continent region.

Natural Gas Pipelines - In our Natural Gas Pipelines segment, earnings increased in 2024, compared with 2023, due primarily to the impact of the interstate pipeline divestiture and increased transportation services, as well as the impact of the EnLink Controlling Interest Acquisition from the period of Oct.

15, 2024, to Dec.

We recently reactivated previously idled storage facilities with 3 Bcf of working gas storage capacity in Texas.

In addition, we are in the process of expanding our storage injection capabilities in Oklahoma, which we expect to be complete in the second quarter of 2025.

As a result of the EnLink Acquisitions, we have access to additional natural gas storage assets in Texas and Louisiana.

Refined Products and Crude - This reportable business segment was added in 2023 in conjunction with the Magellan Acquisition.

Our 2023 results include the impact of the Magellan Acquisition from the period of Sept.

25, 2023, to Dec.

Earnings in this segment increased in 2024 due primarily to a full year of operating results following the Magellan Acquisition and due to the recent acquisitions of EnLink and Medallion.

Our 2024 results include the impact of the EnLink Controlling Interest Acquisition from the period of Oct.

15, 2024, to Dec.

31, 2024, and the impact of the Medallion Acquisition from the period of Nov.

1, 2024, to Dec.

In 2024, we benefited from mid-year tariff increases of Refined Products.

Additionally, our optimization and marketing earnings have remained strong due to favorable commodity market conditions.

At the end of the first quarter 2024, we completed the expansion of our Refined Products pipeline to El Paso, Texas.

This expansion provides additional Refined Products supply to growing markets in Texas, New Mexico, Arizona and Mexico.

In July 2024, we announced plans to expand our Refined Products pipeline capacity, connecting Mid-Continent and Gulf Coast supply with the greater Denver area, to meet growing demand and increase connectivity with the Denver International Airport (DIA).

The project includes construction of a new 230-mile, 16-inch diameter pipeline from Scott City, Kansas, to DIA and the addition or upgrading of certain pump stations along the existing Refined Products pipeline system.

Total system capacity will increase by 35 MBbl/d and will have additional expansion capabilities.

This project is fully subscribed under long-term contracts.

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

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• 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.

Safety and environmental responsibility continue to be primary areas of focus for us.

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

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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

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regions, grow our dividend, reduce debt and fund our $2.0 billion share repurchase program.

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.

We continue to actively seek out opportunities that will complement our extensive assets and expertise.

• Maximizing total shareholder return - We plan to grow earnings through high-return capital projects that will allow us to increase our dividend and repurchase shares under our $2.0 billion share repurchase program.

We 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.

We seek 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 and the communities in which we operate.

NARRATIVE DESCRIPTION OF BUSINESS

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• Refined Products and Crude.

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Natural Gas Gathering and Processing

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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.

Our Natural Gas Gathering and Processing segment provides these midstream services to producers in the regions listed below.

Rocky Mountain region - The Williston Basin is located in portions of North Dakota and Montana and includes the oil-producing, NGL-rich Bakken Shale and Three Forks formations.

We have more than 3 million dedicated acres in the Williston Basin.

The Powder River Basin is primarily located in 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 Gathering and Processing segment includes the following assets, which are wholly owned, except where noted:

The Powder River Basin is primarily located in Eastern Wyoming, which includes the NGL-rich Niobrara, Frontier, Turner and Mowry formations.

Mid-Continent region - The Mid-Continent region includes the natural gas and oil-producing Anadarko Basin, which includes the NGL-rich SCOOP and STACK areas, Cana-Woodford Shale, Woodford Shale, Springer Shale, Meramec, Granite Wash, Cherokee and Mississippian Lime formations of Oklahoma.

We have more than 600,000 dedicated acres in the Anadarko Basin, excluding EnLink.

As a result of the EnLink Acquisitions, we have more than doubled our presence in the Mid-Continent region by expanding our existing presence in the Cana-Woodford Shale, Woodford Shale and STACK area, while also beginning to operate in the Arkoma-Woodford Shale.

Permian Basin region - The Permian Basin is a large, natural gas-rich sedimentary basin composed of the Midland Basin, located in West Texas, and the Delaware Basin, located in West Texas and Southeastern New Mexico.

As a result of the EnLink Acquisitions, we have a meaningful presence in the Permian Basin, providing gathering and processing services in the Midland and Delaware Basins.

North Texas region - The North Texas region is located in the Barnett Shale, one of the largest onshore natural gas fields in the United States.

As a result of the EnLink Acquisitions, we now provide gathering and processing services in the Barnett Shale.

Property - Our Natural Gas Gathering and Processing segment includes the following assets, which are wholly owned, except where noted, and exclude EnLink, which is shown separately below:

• 13,500 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;

• 14 MBbl/d of NGL fractionation capacity and 26 MBbl/d of de-ethanizer capacity at various natural gas processing plants.

The utilization rates for our natural gas processing plants were 77% and 70% for 2023 and 2022, respectively.

The increase was due primarily to increased producer activity in the Rocky Mountain and the Mid-Continent regions.

Our 2022 utilization rates were impacted by winter weather in the Rocky Mountain region in the second and fourth quarters of 2022.

• Natural gas processing plants with 1.9 Bcf/d of processing capacity in the Rocky Mountain region and 1.0 Bcf/d in the Mid-Continent region, which were 84% and 77% utilized in 2024 and 2023, respectively.

In addition, we have 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.

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

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The following are the Natural Gas Gathering and Processing segment assets added as a result of the EnLink Acquisitions:

• 9,000 miles of natural gas gathering pipelines (includes gross mileage of a consolidated, partially owned subsidiary);

• Natural gas processing plants with 1.4 Bcf/d of processing capacity in the Mid-Continent region, 1.7 Bcf/d of processing capacity in the Permian Basin region (includes gross operating capacity of a consolidated, partially owned subsidiary), 0.8 Bcf/d of processing capacity in the North Texas region.

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.

After performing these services, we sell the commodities and remit a portion of the commodity sales proceeds to the producers less our contractual fees.

This type of contract represented 76% and 72% of supply volumes in this segment, excluding EnLink, for 2024 and 2023, respectively.

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

This type of contract represented 19% of supply volumes in this segment, excluding EnLink, for both 2024 and 2023.

EnLink’s service contracts are primarily fee with POP contracts with producer take-in-kind rights to certain commodities.

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

Our fee-only contracts represented 9% and 7% of supply volumes in this segment for 2023 and 2022, respectively.

Our fee-only contracts represented 5% and 9% of supply volumes in this segment, excluding EnLink, for 2024 and 2023, respectively.

For commodity sales, we contract to deliver residue natural gas, condensate and/or unfractionated NGLs to downstream customers at a specified delivery point.

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

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

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

Government Regulation - The FERC traditionally has maintained that a natural gas processing plant is not a facility for the transportation or sale of natural gas in interstate commerce and, therefore, is not subject to jurisdiction under the Natural Gas Act.

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The FERC has historically distinguished between these two types of facilities, either interstate or intrastate, on a fact-specific basis.

We transport residue natural gas from certain of our natural gas processing plants to interstate pipelines in accordance with Section 311(a) of the Natural Gas Policy Act.

Oklahoma, Kansas, Wyoming, Montana and North Dakota also have statutes regulating, to varying degrees, the gathering of natural gas in those states.

We transport residue natural gas from certain of our natural gas processing plants to interstate pipelines in accordance with Section 311(a) of the Natural Gas Policy Act of 1978, as amended.

The states where we operate have statutes regulating, to varying degrees, the gathering of natural gas in those states.

In each state, regulation is applied on a case-by-case basis if a complaint is filed against the gatherer with the appropriate state regulatory agency.

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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.

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

Overview of Operations - In our Natural Gas Liquids segment, NGLs extracted at our own and third-party natural gas processing plants are gathered by our NGL gathering pipelines.

Gathered NGLs are directed to our downstream fractionators to be separated into Purity NGLs.

Purity NGLs are stored or distributed to our customers, such as petrochemical companies, propane distributors, diluent users, ethanol producers, refineries and exporters.

We provide midstream services to producers of NGLs in the Rocky Mountain region, Mid-Continent region, Permian Basin and Gulf Coast region (including Louisiana) and deliver those products to the market.

Our primary markets include the Mid-Continent in Conway, Kansas, the Gulf Coast in Mont Belvieu, Texas, Louisiana and the upper Midwest.

The majority of the pipeline-connected natural gas processing plants in the Williston Basin, Oklahoma, Kansas and the Texas Panhandle as well as a large number in the Permian Basin, Barnett Shale, East Texas and Louisiana regions are connected to our NGL gathering

Through our NGL gathering and distribution pipelines, and fractionation, terminal and storage facilities, we provide needed midstream services while connecting key supply and demand areas.

Property - Our Natural Gas Liquids segment includes the following assets, which are wholly owned, except where noted, and exclude EnLink, which is shown separately below:

• 9,300 miles of gathering pipelines;

• 4,800 miles of distribution pipelines;

• eight NGL fractionators with combined operating capacity of 835 MBbl/d (includes interests in our proportional share of operating capacity), including 310 MBbl/d in the Mid-Continent region and 525 MBbl/d in the Gulf Coast region, which are 98% utilized;

• NGL fractionators with combined operating capacity of 960 MBbl/d (includes interests in our proportional share of operating capacity), including 310 MBbl/d in the Mid-Continent region and 650 MBbl/d in the Mont Belvieu, Texas area, which were 92% and 98% utilized in 2024 and 2023, respectively;

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

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

• six NGL storage facilities with operating storage capacity of 30 MMBbl;

• NGL storage facilities with operating storage capacity of 30 MMBbl;

• 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.

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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.

We completed the construction of our 125 MBbl/d MB-6 fractionator, which is included in the assets listed above.

We are in the process of reconstructing our 210 MBbl/d fractionator in Medford, Oklahoma, which is excluded from the assets listed above.

In addition, we have access to 6 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 following are the Natural Gas Liquids segment assets added as a result of the EnLink Acquisitions:

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

• NGL fractionators with combined operating capacity of 235 MBbl/d;

• NGL storage facility with operating storage capacity of approximately 10 MMBbl.

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.

Sources of Earnings - Earnings for our Natural Gas Liquids segment are derived primarily from fee-based services and commodity sales and purchases.

We purchase NGLs and condensate from third parties, as well as from our Natural Gas Gathering and Processing segment.

We also sell NGLs to our affiliate in the Refined Products and Crude segment.

Our business activities are categorized as follows:

• Exchange services - We utilize our assets to gather, transport, treat and fractionate NGLs, thereby converting them into marketable Purity NGLs and deliver them to a market center or customer-designated location.

• Exchange services - We utilize our assets to gather, transport, treat and fractionate NGLs, converting them into marketable Purity NGLs, and deliver them to a market center or customer-designated location.

Some of these exchange volumes are under contracts with minimum volume commitments that provide a minimum level of revenues regardless of volumetric throughput.

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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.

• Transportation and storage services - We transport Purity NGLs and certain Refined Products, primarily under regulated tariffs.

Tariffs specify the maximum rates we may charge our customers and the general terms and conditions for transportation service on our pipelines.

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• Optimization and marketing - We utilize our assets, contract portfolio and market knowledge to capture location, product and seasonal price differentials through 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.

We transport Purity NGLs between the Mid-Continent region, upper Midwest and Gulf Coast regions to capture the location price differentials between market centers.

Our marketing activities also include utilizing our NGL storage facilities to capture seasonal price differentials and serving marine, truck and rail markets.

Our isomerization activities capture the price differential when normal butane is converted into the more valuable iso-butane at our isomerization unit in Conway, Kansas.

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Our other unconsolidated affiliates in this segment are not material.

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

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

Government Regulation - The operations and revenues of our NGL pipelines are regulated by various state and federal government agencies.

Our interstate NGL pipelines are regulated under the Interstate Commerce Act, which gives the FERC jurisdiction to regulate the terms and conditions of service, rates, including depreciation and amortization policies, and initiation of service.

In Oklahoma, Kansas and Texas, certain aspects of our intrastate NGL pipelines that provide common carrier service are subject to the jurisdiction of the OCC, KCC and RRC, respectively.

Certain aspects of our intrastate NGL pipelines that provide common carrier service are subject to the jurisdiction of various state agencies in the states where we operate.

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

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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-

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generation facilities and large industrial companies supported low-cost expansions that position us well to provide additional services to our customers when needed.

Growing demand from data centers and continued demand from local distribution companies, electric-generation facilities and large industrial companies support low-cost expansions that position us well to provide additional services to our customers when needed.

Intrastate Pipelines and Storage - Our intrastate natural gas pipeline and storage assets are located in Oklahoma, Texas and Kansas.

Our Oklahoma intrastate pipeline and storage assets have access to major natural gas production areas in the Mid-Continent region.

Our Texas intrastate pipeline and storage assets have access to major natural gas producing formations in the Texas Panhandle.

These assets provide shippers access to western markets, several markets to the southeast along the Gulf Coast, including the Houston Ship Channel, the Mid-Continent market to the north and exports to Mexico.

Our storage facilities provide 61 Bcf of working gas storage capacity.

Additionally, as a result of the EnLink Acquisitions, we also have intrastate pipeline and storage assets in Louisiana and North Texas.

Our intrastate pipeline and storage companies primarily include:

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ONEOK WesTex Transmission is connected to our ONEOK Texas Gas Storage facilities, which provide 8 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;

• OkTex Pipeline, which has interconnections with several pipelines in Oklahoma, Texas and New Mexico.

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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;

• 1,500 miles of FERC-regulated interstate natural gas pipelines with 3.7 Bcf/d of transportation capacity;

• 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.

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:

• Bridgeline Pipeline, acquired with the EnLink Acquisitions, which provides transportation and storage services to a variety of customers including South Louisiana industrial companies, power companies, utilities and Gulf Coast LNG facilities;

• Louisiana Intrastate Gas (LIG) Pipeline, acquired with the EnLink Acquisitions, which is a natural gas pipeline system providing a fully integrated wellhead to burner tip value chain that includes local gathering, processing, transmissions and treating services to Louisiana producers.

The LIG Pipeline has access to the Haynesville shale producing area and connects to several other natural gas pipelines, providing additional system supply, and to the Jefferson Island storage facility;

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

Interstate Natural Gas Pipeline Divestiture - On Nov.

19, 2024, we entered into a definitive agreement with DT Midstream, Inc.

to sell three of our wholly owned interstate natural gas pipeline systems, including Guardian and Viking, located in the Upper Midwest, and Midwestern Gas Transmission Company, located between Tennessee and the Chicago Hub near Joliet, Illinois.

31, 2024, we completed the sale of these assets.

Interstate Pipelines - Sabine Pipeline was acquired with the EnLink Acquisitions and is an interstate natural gas pipeline that transports natural gas between Port Arthur, Texas, and the Henry Hub located in Erath, Louisiana.

The Sabine Pipeline also owns and operates the Henry Hub, the official delivery mechanism and pricing point for Chicago Mercantile Exchange’s NYMEX natural gas futures.

Property - Our Natural Gas Pipelines segment includes the following wholly owned assets and exclude EnLink, which is shown separately below:

• 5,200 miles of natural gas pipelines, which were 97% and 96% subscribed in 2024 and 2023, respectively;

• seven underground natural gas storage facilities with 61 Bcf of total active working natural gas storage capacity which were 75% and 76% subscribed in 2024 and 2023, respectively.

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

The following are the Natural Gas Pipeline segment assets added as a result of the EnLink Acquisitions:

• 3,200 miles of natural gas pipelines;

• four underground natural gas storage facilities with approximately 13 Bcf of total active working natural gas storage capacity.

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

• Transportation services - Our regulated natural gas transportation services contracts are based upon rates stated in the respective tariffs, which have generally been established through shipper specific negotiation, discounts and negotiated settlements.

The rates are filed with FERC or the appropriate state jurisdictional agencies.

In addition, customers typically are assessed fees, such as a commodity charge, and we may retain a percentage of natural gas in-kind for our compression services.

Our transportation earnings are primarily fee-based and utilize the following types of contracts:

◦ Firm service - Customers reserve a fixed quantity of pipeline capacity for a specified period of time, which obligates the customer to pay regardless of usage.

Under this type of contract, the customer pays a monthly fixed fee and incremental fees, known as commodity charges, which are based on the actual volumes of natural gas they transport or store.

Under 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.

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◦ 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.

Our storage earnings are primarily fee-based from the following types of services:

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

◦ Firm service - Customers reserve a specific quantity of storage capacity, including injection and withdrawal rights, and generally pay fixed fees based on the quantity of capacity reserved plus an injection and withdrawal fee based on actual usage.

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Customers reserve the right to park or loan natural gas based on a specified quantity, including injection and withdrawal rights when capacity is available.

• Optimization and marketing - As a result of the EnLink Acquisitions, we also derive earnings from providing natural gas marketing and optimization for our customers.

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

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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.

The final investment decision on the Saguaro Connector pipeline is expected by mid-year 2024.

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

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

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

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

Intrastate - Our intrastate natural gas pipelines in Oklahoma, Kansas and Texas are regulated by the OCC, KCC and RRC, respectively, and by the FERC under the Natural Gas Policy Act for certain services where we deliver natural gas into FERC-regulated natural gas pipelines.

Intrastate - Our intrastate natural gas pipelines in Oklahoma, Kansas, Louisiana and Texas are subject to rate regulation by state regulators and by the FERC under the Natural Gas Policy Act of 1978, as amended, for certain services where we deliver natural gas into FERC-regulated natural gas pipelines.

While we have flexibility in establishing natural gas transportation rates with customers, there is a maximum rate that we can charge our customers in Oklahoma and Kansas and for the services regulated by the FERC.

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Overview of Operations - Our Refined Products and Crude segment is principally engaged in the transportation, storage and distribution of Refined Products and crude oil.

This new reportable business segment was added in conjunction with the Magellan Acquisition.

Our Refined Products pipeline system is one of the longest common carrier pipeline systems for Refined Products in the United States, extending approximately 9,800 miles from the Texas Gulf Coast and covering a 15-state area

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across the central and western United States.

Our crude oil pipelines transport crude oil to refineries, export facilities and demand centers.

As a result of the EnLink Acquisitions and the Medallion Acquisition, we are also engaged in the gathering of crude oil .

Crude oil pipelines gather and transport crude oil to refineries, export facilities and demand centers.

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

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Shipments originate on our Refined Products pipeline system from direct connections to refineries or through interconnections with other pipelines or terminals for transportation and ultimate distribution to retail fueling stations, convenience stores, travel centers, railroads, airports and other end users.

Our crude oil assets are strategically located to transport and store crude oil supply and are connected with multiple trading and demand centers.

Our 450-mile Longhorn pipeline has the capacity to transport approximately 275 MBbl/d of crude oil from the Permian Basin in West Texas to our East Houston terminal.

Our Houston distribution system consists of more than 100 miles of pipeline that connect our East Houston terminal through several interchanges to various points, including multiple refineries throughout the Houston area and crude oil import and export facilities.

Our East Houston terminal is a primary delivery point for the HOU futures contract traded on ICE, and certain price quotes are based on trades at our terminal.

We own approximately 400 miles of pipeline in Kansas and Oklahoma used for crude oil transportation service.

Our Cushing terminal primarily receives and distributes crude oil via the multiple common carrier pipelines that terminate in and originate from the Cushing crude oil trading hub.

Our Corpus Christi terminal receives product primarily from barges and pipelines that connect to our terminal for further distribution to end users by trucks, pipeline or waterborne vessels.

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

Our Refined Products pipeline system is one of the longest common carrier pipeline systems for Refined Products in the United States, extending from the Texas Gulf Coast and covering a 15-state area across the central and western United States.

Our crude oil assets are strategically located to transport and store crude oil and are connected to multiple trading and demand centers.

We have existing crude oil pipelines in Kansas and Oklahoma, and from the Permian Basin in West Texas to our East Houston terminal.

Our Houston distribution system connects our East Houston terminal through several interchanges to various points, including multiple refineries throughout the Houston area and crude oil import and export facilities.

Our Cushing terminal primarily receives and distributes crude oil via the multiple pipelines that terminate in and originate from the Cushing hub.

Our Corpus Christi terminal provides terminalling services and includes our splitter.

As a result of the EnLink Acquisitions and the Medallion Acquisition, we acquired crude oil gathering pipelines and crude oil storage facilities in the Permian Basin and the Mid-Continent region.

Property - Our Refined Products and Crude segment includes the following wholly owned assets, which exclude EnLink and Medallion, which are shown separately below:

• 9,800 miles of Refined Products pipelines;

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• 97 MMBbl of operating storage capacity.

The operating capacity of our pipelines varies depending on pipeline diameter, product composition and segment of the system.

As a result, we consider volumes shipped 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.

The following are the Refined Products and Crude segment assets added as a result of the EnLink Acquisitions and the Medallion Acquisition:

• 2,100 miles of crude oil gathering pipelines;

• 2 MMBbl of operating storage capacity.

We are in the process of constructing our greater Denver area pipeline expansion project.

The project includes construction of a new 230-mile, 16-inch diameter pipeline from Scott City, Kansas, to Denver International Airport and the addition or upgrading of certain pump stations and will increase total system capacity by 35 MBbl/d and have additional expansion capabilities.

This project is excluded from the assets listed above.

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

• Transportation services - We generate revenue from transportation tariffs on volumes shipped on our Refined Products and crude oil pipeline systems.

These transportation tariffs vary depending upon where the product originates, where ultimate delivery occurs and any applicable discounts.

Transportation fees and discounts are in published tariffs filed with the FERC or the appropriate state agency or established by negotiated rates.

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

• Optimization and marketing - At times, we obtain Refined Products and crude oil and utilize our assets, contract portfolio and market knowledge to capture location, product and seasonal price differentials through purchases and sales of product and liquids blending.

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

• Transportation services - We generate revenue from tariffs on volumes gathered and transported on our Refined Products and crude oil pipeline systems.

These transportation tariffs vary depending upon where the product originates and where ultimate delivery occurs.

Transportation fees are in published tariffs filed with the FERC or the appropriate state agency or established by negotiated rates.

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

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

• a 30% ownership interest in BridgeTex, which owns an approximately 400-mile crude oil pipeline with transport capacity of up to 440 MBbl/d that connects Permian Basin crude oil to our East Houston terminal;

• a 30% ownership interest in Saddlehorn, which owns an undivided joint interest in an approximately 600-mile pipeline, with transport capacity of up to 290 MBbl/d of crude oil from the DJ Basin and Rocky Mountain region to storage facilities in Cushing, including our Cushing terminal;

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

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

Our other unconsolidated affiliates in this segment are not material.

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

Government Regulation - Our interstate common carrier pipeline operations are subject to rate regulation by the FERC under the Interstate Commerce Act, the Energy Policy Act of 1992 and related rules and orders.

Most of the tariffs on our long-haul crude oil pipelines are established by negotiated rates that generally provide for annual adjustments in line with changes in the FERC index applicable to liquids pipelines, subject to certain modifications.

Some shipments on our pipeline systems that move within a single state are considered to be in intrastate commerce.

The rates, terms and conditions of intrastate service are subject to certain regulations with respect to such intrastate transportation by state regulatory authorities in the states of Colorado, Kansas, Minnesota, Oklahoma, Texas and Wyoming.

The FERC or state regulatory authorities could limit our ability to increase our rates or to set rates based on our costs or could order us to reduce our rates and require the payment of refunds to shippers if our rates are found to have been unjust.

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

Government Regulation - Our interstate common carrier pipelines are subject to rate regulation by the FERC under the Interstate Commerce Act, the Energy Policy Act of 1992 and related rules and orders.

Most of the tariff rates on our long-haul pipelines are established under market-based rate authority or via negotiated rates that generally allow for annual inflation-based adjustments.

Some shipments on our pipeline systems are considered to be in intrastate commerce and are subject to certain regulations with respect to such intrastate transportation by state regulatory authorities in Colorado, Kansas, Minnesota, Oklahoma, Texas or Wyoming.

In future rate or rulemaking proceedings, the FERC or state regulatory authorities could reduce rates prospectively, limit our ability to increase future rates or modify the way rates are currently established.

In certain circumstances, a change could also require the payment of refunds to shippers.

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

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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;

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

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existing production;

changes in gas-to-oil ratios and the decline rate of existing production;

refinery maintenance cycles;

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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 gathering and processing services is dependent on natural gas and crude oil production by producers in the regions in which we operate.

Demand for NGLs and the ability of natural gas processors to sustain their operations successfully and economically affect the volume of unfractionated NGLs produced by natural gas processing plants, thereby affecting the demand for NGL gathering, transportation and fractionation services.

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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 shipments on our crude oil pipelines is driven primarily by crude oil production and takeaway demand in the regions in which we operate.

Demand for natural gas, NGLs, Refined Products and crude oil is also impacted by global macroeconomic factors.

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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.

Our Natural Gas Gathering and Processing segment is exposed to commodity price risk as a result of retaining a portion of the commodity sales proceeds associated with our fee with POP contracts and our POP contracts with take-in-kind rights.

Our Natural Gas Gathering and Processing segment follows a programmatic approach to hedging commodity price risk and expects to hedge approximately 75% of its monthly equity volumes over time.

Under certain fee with POP contracts, our contractual fees and POP percentage may increase or decrease if production volumes, delivery pressures or commodity prices change relative to specified thresholds.

In our Natural Gas Liquids segment, we are exposed to commodity price risk associated with changes in the price of NGLs;

the location differential between the Mid-Continent, Chicago, Illinois, and Gulf Coast regions;

the location differential between the Conway, Kansas, upper Midwest region, Mont Belvieu, Texas, and Louisiana;

and the relative price differential between natural gas, NGLs and individual Purity NGLs, which affect our NGL purchases and sales, our exchange services, transportation and storage services, and optimization and marketing financial results.

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.

We are also exposed to changes in the price of power, which can impact our fractionation and transportation costs.

In our Natural Gas Pipelines segment, we are exposed to 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.

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 customer demand for our natural gas storage services.

In our Refined Products and Crude segment, we are exposed to some commodity price risk, including product price and location differentials primarily from our optimization and marketing activities, as well as product retained during the operations of our pipelines and terminals.

See additional discussion regarding our commodity price risk and related hedging activities under “Commodity Price Risk” in Part II, Item 7A, Quantitative and Qualitative Disclosures about Market Risk, in this Annual Report.

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Power interruptions and inaccessible well sites as a result of severe storms or freeze-offs, a phenomenon where water vapor from the well bore freezes at the wellhead or within the natural gas gathering system, may cause a temporary interruption in the flow of natural gas, NGLs, Refined Products and crude oil.

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

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The factors that typically affect our ability to compete for natural gas, NGL, Refined Products and crude oil volumes are:

• quality of services provided;

• quality and quantity of services provided;

• producer drilling activity;

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• cost of and access to capital.

We have remained competitive by making capital investments to access and connect new supplies with end-user demand;

We have remained competitive by executing strategic acquisitions;

making capital investments to access and connect new supplies with end-user demand;

increasing gathering, processing, fractionation and pipeline capacity;

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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.

Customers - Our Natural Gas Gathering and Processing, Natural Gas Liquids and Refined Products and Crude segments derive fees for services from major and independent crude oil and natural gas producers.

Our Natural Gas Liquids segment’s customers also include other NGL and natural gas gathering and processing companies.

Our downstream commodity sales customers are primarily petrochemical, refining and marketing companies, utilities, large industrial companies, natural gasoline distributors, propane distributors 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 Natural Gas Pipeline segment’s assets primarily serve local distribution companies, electric-generation facilities, large industrial companies, municipalities, producers, processors and marketing companies.

Our utility customers generally require our services regardless of commodity prices.

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ONEOK Leasing Company, L.L.C.

leases excess office space, if any, to others and operates our headquarters office building.

primarily operates our headquarters office building.

ONEOK Parking Company, L.L.C.

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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.

We are subject to a variety of historical preservation and environmental and safety laws and/or regulations that affect many aspects of our present and future operations.

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

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similar federal and state laws could require unexpected capital expenditures at our facilities.

Failure to comply with these laws, regulations, licenses and permits may expose us to fines, penalties, reputational harm, claims or lawsuits from third parties, and/or interruptions in our operations that could be material to our results of operations or financial condition.

also incur material costs for cleanup of spills or releases of hazardous substances.

In addition, emissions controls and/or other regulatory or permitting mandates under the Federal Clean Air Act, as amended (Clean Air Act), and other similar federal and state laws could require unexpected capital expenditures at our facilities.

We cannot ensure that existing environmental statutes and regulations will not be revised or that new regulations will not be adopted or become applicable to us.

We also cannot ensure that existing permits will not be revised or cancelled, potentially impacting facility construction activities or ongoing operations.

Air and Water Emissions - The Clean Air Act, the 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.

Air and Water Emissions - The Clean Air Act, the Federal Water Pollution Control Act Amendments of 1972, as amended (Clean Water Act), the Oil Pollution Act of 1990 and analogous state laws and/or regulations impose restrictions and controls regarding the release of pollutants into the air and water in the United States.

Under the Clean Air Act, a federal operating permit is required for sources of significant air emissions.

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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.

GHG Emissions - In 2023, GHG emissions were approximately 3.7 million metric tons of carbon dioxide equivalents of Scope 1 emissions and 3.1 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.

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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 met ric tons of the targeted 2.2 million metric tons of carbon dioxide equivale nts, 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.

The target represents a 30% reduction in combined operational Scope 1 and location-based Scope 2 GHG emissions attributable to ONEOK assets as of Dec.

31, 2024, we have achieved reductions totaling approximately 1.7 million met ric tons of the targeted 2.2 million metric tons of carbon dioxide equivale nts, primarily as a result of methane emissions mitigation, system utilization and optimizations, electrification of certain natural gas compression equipment and lower carbon-based electricity in states in which we operate.

GHG emission reductions as reported may be modified, updated, changed or supplemented based on available information.

F or 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.

For the years ended Dec.

31, 2024, 2023 and 2022, 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.

In 2025, we intend to work towards further reductions in our emissions toward our target through improved methane management practices and system optimization that will not require material capital expenditures.

We do not anticipate purchasing or selling carbon credits or offsets in 2025.

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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.

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.

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

United States Department of Transportation Pipeline and Hazardous Materials Safety Administration ( PHMSA) - On Jan.

17, 2025, the PHMSA issued a final rule, which has been submitted to the Federal Register underscoring to pipeline and pipeline facility operator’s requirements to minimize methane emissions in the Protecting our Infrastructure of Pipelines and Enhancing Safety (PIPES) Act of 2020.

The PIPES Act directs pipeline operators to update their inspection and maintenance plans to address the elimination of hazardous leaks and to minimize natural gas releases from pipeline facilities.

The updated plans must also address the replacement or remediation at facilities that historically have been known to experience leaks.

The updated plans must also address the replacement or remediation of pipeline facilities that historically have been known to experience leaks.

We have completed and continue to update our pipeline maintenance procedures to identify and reduce methane leaks.

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.

United States Environmental Protection Agency (EPA) - The EPA’s Mandatory Greenhouse Gas Reporting Rule requires annual GHG emissions reporting from our affected facilities and the carbon dioxide emission equivalents for all hydrocarbon liquids produced by us as if all products were combusted, even if they are used otherwise.

The additional cost to gather and report this emission data did not have, and we do not expect it to have, a material impact on our results of operations, financial position or cash flows.

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

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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 p resent 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.

In 2024, the EPA finalized its rule targeting oil and gas section emissions of greenhouse gases (primarily methane) and volatile organic compounds (VOCs).

The rule includes (i) new source performance standards codified in 40 C.F.R.

Part 60 Subpart OOOOb for new sources (i.e., facilities that commence construction, reconstruction, or modification after Dec.

6, 2022), (ii) emission guidelines codified in 40 C.F.R.

Part 60 Subpart OOOOc that states must use to develop performance standards for existing sources (i.e., facilities that existed on or before Dec.

This final rule was challenged in court by states and industry stakeholders, which litigation is ongoing.

In addition, in January 2025, the new administration issued an executive order directing the heads of all federal agencies to identify and begin the processes to suspend, revise or rescind all agency actions that are unduly burdensome on the identification, development or use of domestic energy resources.

Consequently, future implementation and enforcement of the final rule remain uncertain.

At this time, we do not anticipate a material impact to our planned capital, operations and maintenance costs resulting from compliance with the current or pending regulations and proposed EPA actions.

However, the EPA and/or state regulators may issue additional regulations, responses, amendments and/or policy guidance, which could alter our present expectations.

Renewable Fuel Standard - We are an obligated party under the Renewable Fuel Standard (RFS) promulgated by the EPA and are required to satisfy our Renewable Volume Obligation (RVO) on an annual basis.

To meet our RVO, we must either ensure that the transportation fuel we produce in our optimization and marketing activities contains the mandated renewable fuel components or purchase credits to cover any shortfall.

We generally satisfy our RVO requirements through the purchase of RINs.

RINs are generated when a gallon of renewable fuel is produced and may be separated when the renewable fuel is blended into gasoline or diesel fuel, at which point the RIN is available for use in compliance or available for sale on the open market.

As the RFS program is currently structured, the RVO of all obligated parties may increase over time unless adjusted by the EPA.

The ability to incorporate increasing volumes of renewable fuel components into fuel products and the availability of RINs may be limited, which could increase our 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 i mpact to our planned capital, operations and maintenance costs resulting from compliance with the current or pending regulations and proposed EPA actions.

The ability to incorporate increasing volumes of renewable fuel components into fuel products and the availability of RINs may be limited, which could increase our RFS compliance costs or limit our ability to blend.

In 2024, the EPA finalized changes to the federal gasoline distribution reg ulations.

We do not anticipate a material im pact to our planned capital, operations and maintenance costs resulting from compliance with the current regulations.

Additionally, we are subject to the EPA’s fuels compliance regulations.

These regulations include standards for fuel parameters and require rigorous product sampling and testing, recordkeeping and reporting.

These regulations include standards for fuel parameters and require rigorous product sampling and testing, recordkeeping and reportin g.

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.

Federal Regulation - In August 2022, the Inflation Reduction Act of 2022 (IRA) was signed into law.

The IRA includes tax credits and other incentives intended to combat climate change by advancing decarbonization and promoting increased investment in renewable and low carbon intensity energy.

In addition, the IRA directed the EPA to impose and collect “Waste Emissions Charges,” or “Methane Fees,” for specific facilities that report more than 25,000 metric tons of carbon dioxide equivalent of GHG emissions per year and have a methane emissions intensity in excess of the relevant statutory threshold.

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.

In addition, the IRA directed the EPA to impose and collect “Waste Emissions Charges,” or “Methane Fees,” for specific facilities th at report more than 25,000 metric tons of carbon dioxide equivalent of GHG emissions per year and have a methane emissions intensity in excess of the relevant statutory threshold.

In January 2025, industry associations and certain states challenged the Waste Emissions Charge rule in the D.C.

Circuit, and the new administration issued an executive order directing the heads of all federal agencies to identify and begin the processes to suspend, revise or rescind all agency actions that are unduly burdensome on the identification, development or use of domestic energy resources.

Consequently, future implementation and enforcement of these rules remain uncertain at this time.

Based on text in the IRA and a related rule that the EPA finalized in November 2024 that will require payment of Methane Fees to the EPA beginning in 2025 (for 2024 reported emissions), the 2024 Methane Fees, if implemented, will not 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.

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 requirements in any future federal legislation and/or regulation.

We monitor all relevant legislation and regulatory initiatives to assess the potential impact on our operations and otherwise take steps to limit GHG emissions from our facilities, including methane.

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

Waste - Our operations generate waste, including hazardous waste, that is subject to the requirements of the RCRA and comparable state statutes.

We are not currently required to comply with a substantial portion of the RCRA requirements as our operations routinely generate only small quantities of hazardous waste, and we are not a hazardous waste treatment, storage or disposal facility operator that is required to obtain a RCRA permit.

While the RCRA currently exempts a number of waste from being subject to hazardous waste requirements, including many oil and gas exploration and production waste, the EPA could consider the adoption of stricter disposal standards for non-hazardous waste.

Waste - Our operations generate waste, including hazardous waste, that is subject to the requirements of the Resource Conservation and Recovery Act, as amended (RCRA), and comparable state statutes.

While the RCRA currently exempts a number of types of waste from being subject to hazardous waste requirements, including many oil and gas exploration and production wastes, the EPA could consider the adoption of stricter disposal standards for non-hazardous waste.

Moreover, it is possible that additional waste, which could include non-hazardous waste currently generated during operations, may be designated as hazardous waste.

Hazardous waste is subject to more rigorous and costly storage and disposal requirements than non-hazardous waste.

Changes in the regulations could materially increase our expenses.

Changes in the regulations could materially increase our operating expenses.

We own or lease properties where hydrocarbons have been handled for many years, during which operating and disposal standards have evolved.

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In addition, many of these properties were previously operated by third parties whose treatment and disposal or release of hydrocarbons or other waste was not under our control.

These properties and waste disposal facilities may be subject to CERCLA, RCRA and analogous state laws.

Under these laws, we could be required to

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remove or remediate previously disposed waste, including waste disposed of or released by prior owners or operators, to remediate contaminated property, including groundwater contaminated by prior owners or operators, or to make capital improvements to prevent future contamination.

These properties and waste disposal facilities may be subject to Comprehensive Environmental Response Compensation and Liability Act, as amended, RCRA and analogous state laws.

Under these laws, we could be required to remove or remediate previously disposed waste, including waste disposed of or released by prior owners or operators, to remediate contaminated property, including groundwater contaminated by prior owners or operators, or to make capital improvements to prevent future contamination.

Pipeline and Facility Safety - We are subject to PHMSA safety regulations, including pipeline asset integrity-management regulations.

The Pipeline Safety Improvement Act of 2002 requires pipeline companies operating high-pressure pipelines to perform integrity assessments on pipeline segments that pass through densely populated areas or near specifically designated high-consequence areas (HCAs).

The Pipeline Safety, Regulatory Certainty and Job Creation Act of 2011 (the 2011 Pipeline Safety Act) increased maximum penalties for violating federal pipeline safety regulations, directs the DOT and Secretary of Transportation to conduct further review or studies on issues that may or may not be material to us and may result in the imposition of more stringent regulations.

In 2015, PHMSA issued notices of proposed rulemaking for hazardous liquid pipeline safety regulations, natural gas transmission and gathering lines and underground natural gas storage facilities.

For natural gas and natural gas gathering pipelines, the new proposed regulations became known as “the Mega Rule.” Due to the large number of rules being considered, PHMSA partitioned the new rulemaking into three sections.

The first section of rules was finalized and published in 2019 in the Federal Register and became effective in July 2020.

These final rules mostly address congressional mandates due to former pipeline safety reauthorizations and established criteria for verifying current operating pressures.

The second section of the Mega Rule, which was published in August 2022 and became effective in May 2023, focuses on natural gas transmission pipelines and includes enhancements to management requirements for risk and integrity assessments, guidance for corrosion and mitigation timelines, pipeline inspections following extreme weather events and repair requirements for HCAs and non-HCAs.

The thir d section of the Mega Rule establishes new regulations for certain gas gathering lines, which were formerly unregulated, and was published in November 2021 and became effective in May 2022.

Coupled together, these new sections of the Mega Rule provide incr eased requirements for operating and maintenance, integrity management, public awareness and civil/criminal penalties;

however, we do not anticipate a material im pact to our planned capital or operations and maintenance costs resulting from compliance with the newly published regulations.

The Pipeline Safety, Regulatory Certainty and Job Creation Act of 2011 (the 2011 Pipeline Safety Act) increased maximum penalties for violating federal pipeline safety regulations, directs the United States Department of Transportation (DOT) and Secretary of Transportation to conduct further review or studies on issues that may or may not be material to us and may result in the imposition of more stringent regulations.

Penalty amounts have since been regularly adjusted for inflation with the most recent adjustment taking effect on Dec.

In 2015 through 2022, PHMSA issued notices of proposed rulemaking for hazardous liquid pipeline safety regulations, natural gas transmission and gathering lines and underground natural gas storage facilities.

For natural gas and natural gas gathering pipelines, the new proposed regulations became known as “the Mega Rule.” The Mega Rule increased requirements for operating and maintenance, integrity management, public awareness and civil/criminal penalties with full compliance deadlines extending into 2035;

however, we do not anticipate a material impact to our planned capital or operations and maintenance costs resulting from compliance with these requirements.

Our NGL, Refined Products and crude oil pipeline systems are subject to regulation by the DOT and PHMSA under the Hazardous Liquid Pipeline Safety Act of 1979, as amended (HLPSA).

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In addition to the amended HLPSA covered in Title 49 of the Code of Federal Regulations, subsequent statutes provide the framework for the pipeline hazardous liquid safety program and include provisions related to PHMSA’s authorities, administration and regulatory activities.

During 2022, PHMSA published expanded regulations for the installation of rupture mitigation valves and the establishment of a minimum rupture detection standard.

We believe that compliance with such regulatory changes will not have a material adverse effect on our business.

Our marine terminals along coastal waterways are subject to U.S.

Coast Guard regulations and comparable state and municipal statutes relating to the design, installation, construction, testing, operation, replacement and management of these assets.

In 2020, legislation was passed to reauthorize PHMSA through 2024.

Legislation is currently pending to extend this authorization.

Certain requirements for operations and maintenance, integrity management, leak detection and public awareness will be subject to future rulemaking as a result.

The potential capital and operating expenditures related to the new regulations are not fully known, but we do not anticipate a material impact to our planned capital or operations and maintenance costs resulting from compliance with the new regulations.

In July 2022, a fire occurred at our 210 MBbl/d Medford, Oklahoma, natural gas liquids fractionation facility.

Our marine terminals along coastal waterways are subject to U.S.

Coast Guard regulations and comparable state and municipal statutes relating to the design, installation, construction, testing, operation, replacement and management of these assets.

Certain of our field injection and withdrawal wells and water disposal wells are subject to the jurisdiction of the Railroad Commission of Texas (RRC).

The RRC regulations require that we report the volumes of natural gas and water disposal associated with the operations of such wells on a monthly and annual basis, respectively.

Results of periodic mechanical integrity tests must also be reported to the RRC.

In addition, our underground natural gas storage caverns in Louisiana are subject to the jurisdiction of the Louisiana Department of Natural Resources (LDNR).

In recent years, LDNR has put in place more comprehensive regulations governing underground hydrocarbon storage in salt caverns, and we believe we are in substantial compliance with these newer regulations.

PHMSA regulates safety issues related to downhole facilities located at both intrastate and interstate underground natural gas storage facilities.

PHMSA mandates certain reporting requirements for operators of underground natural gas storage facilities and sets minimum federal safety standards.

In addition, all intrastate transportation-related underground natural gas storage facilities are subject to minimum federal safety standards and are inspected by PHMSA or by a state entity that has chosen to expand its authority to regulate these facilities under a certification filed with PHMSA.

State entities that exercise jurisdiction over our underground natural gas storage facilities include the RRC (for our underground natural gas storage facilities in Texas) and LDNR (for our underground natural gas storage facilities in Louisiana).

We do not believe continued compliance with safety standards and other requirements applicable to our underground natural gas storage facilities will have a material impact on results of operations, financial position or cash flows.

In July 2022, a fire occurred at our 210 MBbl/d Medford, Oklahoma, NGL fractionation facility.

All personnel were safe and accounted for with temporary evacuations of local residents taken as a precautionary measure.

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This inquiry is still active with the CSB.

Pipeline Security - Homeland Security’s Transportation Security Administration (TSA) released new pipeline security guidelines that included broader definitions for the determination of pipeline “critical facilities.” We have reviewed our pipeline facilities according to the new guidelines and met the timelines associated with TSA reporting.

Pipeline Security - In April 2021, the United States Department of Homeland Security’s Transportation Security Administration (TSA) released revised pipeline security guidelines that included broader definitions for the determination of pipeline “critical facilities.” In September 2024, we completed our annual review of our pipeline facilities according to the guidelines.

The cost of compliance did not have a material impact on our operations, financial position or cash flows.

In 2021, the TSA began issuing pipeline security directives to owners and/or operators of critical pipeline systems or facilities.

The most recent version of the security directive included a requirement to provide on an annual basis an assessment plan for

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the Cybersecurity Implementation Plan.

In July 2021, the TSA began issuing pipeline security directives to owners and/or operators of critical pipeline systems or facilities.

Pursuant to those directives, our Cybersecurity Implementation Plan was last approved in August 2024, and our Cybersecurity Assessment Plan was last approved in September 2024.

While compliance with the security directives requires significant internal and external resources, we do not expect it to have a material impact on our results of operations, financial position or cash flows.

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To accomplish this, our business strategy includes attracting, selecting and retaining talent, advancing an inclusive, diverse and engaged culture and developing individuals and leaders.

Leaders continued to execute on employee engagement action plans in 2023 to build on the strong 2022 employee engagement survey results.

We did not complete a survey in 2023 as we began the process to stabilize and integrate our employee base following the Magellan Acquisition.

We expect to conduct a survey of the combined company in 2024.

As of December 31, 2023, we had 4,775 employees.

We conduct employee engagement surveys, typically on an annual basis.

In 2024, the annual employee engagement participation rate increased to 93% compared with 90% in 2022, the last year a survey was conducted.

We did not complete a survey in 2023 as we focused on stabilizing and integrating our employee base following the Magellan Acquisition.

The overall engagement mean increased to the 80th percentile and the ratio of engaged employees to actively disengaged also increased.

All leaders have been asked to discuss the 2024 survey results with their teams and create an engagement plan for 2025.

Training and support resources are available through our learning management system, the Gallup engagement portal and dedicated individuals, engagement champions, within the business.

31, 2024, we had 5,177 employees, which excludes EnLink employees.

Listed below is a summary of our human capital resources, measures and objectives that are collectively important to our success as an organization.

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

• Diversity & Inclusion:

we respect the uniqueness and worth of each employee, and believe that a diverse, inclusive workforce is essential for a sense of belonging, engagement and performance.

• Inclusion & Diversity:

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

• Excellence:

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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.

Inclusion and Diversity - Our inclusion and diversity (I&D) strategy is a cross-functional effort that draws upon contributions from employees at all levels of the organization and is focused on enhancing the workplace to attract and retain talent.

The strategy is guided by a council composed of a diverse group of employees who represent different demographics, work locations, points of view, roles and levels of seniority.

We also have a team within our human resources department that is wholly dedicated to supporting our I&D efforts.

We provide support for four employee-led business resource groups (BRGs) that include a Racial/Ethnic Inclusion Resource Group, Veterans Resource Group, Women’s Resource Group and LGBTQ+ Resource Group.

The purpose of these groups is to promote the attraction, development, engagement and retention of 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.

All employees are invited to become supporters of our BRGs.

We embed I&D concepts into our core leadership development curriculum and sponsor a number of internal programs intended to promote I&D.

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.

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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

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management systems and process safety programs, such as key risk/key control identification and knowledge sharing.

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.

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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 expect that beginning on May 1, 2025, legacy EnLink employees will have access to these ONEOK health and welfare benefits.

We also provide the opportunity for our employees to help fellow employees through the ONE Trust Fund by contributing donated vacation hours or monetary donations.

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Further, we provide volunteer opportunities and volunteer grants, as well as $10,000 of charitable giving matching, annually, through the ONEOK Foundation.

Subsequent to the EnLink Acquisition completed on Jan.

31, 2025, we expect legacy EnLink employees to have access to the ONE Trust Fund benefits and can begin making contributions to the fund beginning on May 1, 2025.

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.

For employees just entering the workforce who desire to advance their career and continue to learn or for the employees who are interested in developing their skills, we 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 I&D 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.

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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.

I&D continues to be a priority in recruiting, and we deploy sourcing strategies designed to access talent from groups that are historically underrepresented in our industry and workplace.

Retirement - We maintain a 401(k) Plan for our employees and match 100% of employee contributions up to 6% of eligible compensation each payroll period, subject to applicable tax limits.

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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.

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Effective Jan.

1, 2025, the profit-sharing quarterly contributions increased to 6% from 1% of quarterly eligible compensation.

We will continue to make annual discretionary contributions of up to 2% of eligible compensation.

31, 2024, 96% of eligible employees were contributing to our 401(k) Plan.

For additional information about our retirement benefits, see Note M of the Notes to Consolidated Financial Statements in this Annual Report.

INFORMATION ABOUT OUR EXECUTIVE OFFICERS

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Chief Financial Officer, Treasurer and Executive Vice President, Investor Relations and Corporate Development 2019 to 2021 Chief Financial Officer, Treasurer and Executive Vice President, Strategy and Corporate Affairs, ONEOK

2017 to 2019 Chief Financial Officer and Executive Vice President, Strategic Planning and Corporate Affairs, ONEOK

Burdick 60 2023 to present Executive Vice President and Chief Enterprise Services Officer, ONEOK

Executive Vice President and Chief Enterprise Services Officer

2022 to 2023 Executive Vice President and Chief Commercial Officer, ONEOK

Executive Vice President and Chief Enterprise Services Officer 2022 to 2023 Executive Vice President and Chief Commercial Officer, ONEOK

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

Swords 54 2023 to present Executive Vice President, Commercial Liquids and Gathering and Processing, ONEOK

Executive Vice President, Commercial Liquids and Gathering and Processing 2022 to 2023 Senior Vice President, Natural Gas Liquids and Natural Gas Gathering and Processing, ONEOK

Swords 55 2025 to present Executive Vice President and Chief Commercial Officer, ONEOK

Executive Vice President and Chief Commercial Officer 2023 to 2025 Executive Vice President, Commercial Liquids and Gathering and Processing, ONEOK

2022 to 2023 Senior Vice President, Natural Gas Liquids and Natural Gas Gathering and Processing, ONEOK

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

2023 to present Executive Vice President, Chief Legal Officer and Assistant Secretary, ONEOK

Executive Vice President, Chief Legal Officer and Assistant Secretary

Executive Vice President and Chief Legal and Administrative Officer, Devon Energy Corporation

Kelley 65 2022 to present Senior Vice President, Natural Gas Pipelines, ONEOK

Taylor 66 2023 to present Executive Vice President, Chief Legal Officer and Assistant Secretary, ONEOK

Executive Vice President, Chief Legal Officer and Assistant Secretary 2005 to 2021 Executive Vice President and Chief Legal and Administrative Officer, Devon Energy Corporation

Lentz 60 2025 to present Executive Vice President and Chief Operating Officer, ONEOK

Executive Vice President and Chief Operating Officer 2010 to 2024 President and Chief Executive Officer, Medallion Midstream, LLC

66 2022 to present Senior Vice President, Natural Gas Pipelines, ONEOK

Senior Vice President, Natural Gas Pipelines 2018 to 2022 Senior Vice President, Natural Gas, ONEOK

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Senior Vice President and Chief Accounting Officer, Finance and Tax 2019 to 2021 Vice President and Chief Accounting Officer, ONEOK

2015 to 2019 Director, SEC Reporting, ONEOK

Schingen 50 2023 to present Senior Vice President, Natural Gas Liquids and Natural Gas Operations, ONEOK

Senior Vice President, Natural Gas Liquids and Natural Gas Operations

2021 to 2023 Senior Vice President, Operations, ONEOK

2017 to 2021 Vice President, Natural Gas Liquids Operations, ONEOK

52 2023 to present Senior Vice President, Refined Products and Crude Operations, ONEOK

Senior Vice President, Refined Products and Crude Operations 2023 to 2023 Senior Vice President Operations, Magellan Midstream Partners

2021 to 2023 Vice President of Operations, Magellan Midstream Partners

2019 to 2021 Director of Operations, Magellan Midstream Partners

(a) - Charles M.

Kelley has announced his retirement, effective March 2025.

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

INFORMATION AVAILABLE ON OUR WEBSITE

We make available, free of charge, on our website (www.oneok.com) copies of our Annual Reports, Quarterly Reports, Current Reports on Form 8-K, amendments to those reports filed or furnished to the SEC pursuant to Section 13(a) or 15(d) of the Exchange Act and reports of holdings of our securities filed by our officers and directors under Section 16 of the Exchange Act as soon as reasonably practicable after filing such material electronically or otherwise furnishing it to the SEC.

Copies of our Code of Business Conduct and Ethics, Corporate Governance Guidelines, Director Independence Guidelines, Corporate Sustainability Report and the written charters of our Board Committees also are available on our website, and we provide copies of these documents upon request.

We make available, free of charge, on our website (www.oneok.com) copies of our Annual Reports, Quarterly Reports, Current Reports on Form 8-K, Proxy Statements, amendments to those reports filed or furnished to the SEC pursuant to Section 13(a) or 15(d) of the Exchange Act and reports of holdings of our securities filed by our officers and directors under Section 16 of the Exchange Act as soon as reasonably practicable after filing such material electronically or otherwise furnishing it to the SEC.

In addition to our filings with the SEC and materials posted on our website, we also use social media platforms as additional channels of distribution to reach public investors.

Information contained on our website, posted on our social media accounts, and any corresponding applications, are not incorporated by reference into this report.

T able of Contents

Information contained on our website, or posted on our social media accounts, including any corresponding applications, are not incorporated by reference into this report.

Compared sentence by sentence after normalising whitespace, quotation marks, case and digits, so re-formatting and restated figures do not read as changed language. Wording changes appear as one removal and one addition. The current filing and the prior one are authoritative.

What changed 10-K

Item 1. Business