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Item 7. Management’s Discussion and Analysis

2024-02-27 compared with 2023-02-28 · 274 added, 285 removed, 243 unchanged (70% of the section changed)

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

Market Conditions - We experienced earnings growth in 2022, compared with 2021, due primarily to increased producer activity across our operations, higher realized commodity prices, net of hedging and higher average fee rates.

In 2023, we expect to benefit from higher volumes, our completed Demicks Lake III natural gas processing plant and the expected completion of our MB-5 NGL fractionator, highlighting our extensive and integrated assets that are located in some of the most productive shale basins in the United States.

Medford Incident - On July 9, 2022, a fire occurred at our 210 MBbl/d Medford, Oklahoma, natural gas liquids fractionation facility.

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

Net income for the year ended December 31, 2022, includes the unfavorable impact of our $5 million property deductible and approximately $30 million of losses incurred associated with the 45-day waiting period for business interruption coverage.

Beginning in August 2022, we developed claims related to the Medford incident and recorded accruals for expected insurance recoveries.

The table below sets forth our 2022 insurance accruals associated with the Medford incident:

2022 Insurance Accruals

(Millions of dollars)

Business interruption $ 96.1

Noncash property losses 45.6

Medford response expenses 9.0

Total insurance recoveries accrued (a) $ 150.7

(a) - We received a $100 million payment in the fourth quarter 2022, leaving a receivable balance at December 31, 2022, of $50.7 million.

Our business interruption insurance includes coverage for (i) incurred costs and losses that are either unavoidable or incurred to mitigate or reduce losses and (ii) lost earnings.

Our business interruption insurance accruals in the table above primarily represent third-party fractionation costs and fully offset the actual losses incurred in 2022, subsequent to the 45-day waiting period.

We assessed the property damage to our facility and wrote off assets totaling $45.6 million, which represents the carrying value associated with certain damaged Medford facility property.

These noncash property losses are fully offset by insurance recoveries noted in the table above.

We expect to continue to operate NGL pipeline assets in Medford along with existing offices for regional operations.

In addition, we are preserving certain Medford assets for future potential NGL facilities that could be constructed in Medford to enhance our NGL business as the market evolves.

For additional information on the Medford incident, see Note B of the Notes to Consolidated Financial Statements in this Annual Report.

Subsequent Event - On January 9, 2023, we reached an agreement with our insurers to settle all claims for physical damage and business interruption related to the Medford incident.

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.

Additional information regarding the financial results and operating information of our Refined Products and Crude segment subsequent to the closing of the Magellan Acquisition is provided in “Financial Results and Operating Information.”

Market Condition - 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.

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 MMbl/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 2023.

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.

In the first quarter 2023, we applied the $830 million received to our outstanding insurance receivable at December 31, 2022, of $50.7 million, and recorded a gain in operating income for the remaining $779.3 million.

We expect our cash from operations in the remainder of 2023 and in 2024 to be impacted by incurred costs and losses resulting from the Medford incident for which we will no longer receive business interruption proceeds.

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

The MB-6 fractionator will have the capability to 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 equivalent to the capacity lost at Medford.

In addition, our 125 MBbl/d MB-5 NGL fractionator remains on schedule to be completed early in the second quarter of 2023, which is expected to reduce the need for third-party fractionation while the new MB-6 fractionator is being constructed.

Until these projects are completed, we expect to continue to provide midstream services through existing arrangements with industry peers, along with our integrated NGL pipeline system between the Mid-Continent and Gulf Coast regions and our fractionation and storage assets.

Ethane Production - Price differentials between ethane and natural gas can cause natural gas processors to extract ethane or leave it in the natural gas stream, known as ethane rejection.

The Medford incident resulted in an increase in operating income and adjusted EBITDA of $663 million, from the settlement gain of $779 million, offset partially by $146 million of third-party fractionation costs compared with an approximately $30

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million unfavorable impact of the 45-day waiting period in the year ended December 31, 2022.

We expect our cash from operations in 2024 to be impacted by incurred costs resulting from the Medford incident for which we no longer receive business interruption proceeds.

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.

Ethane Economics - Price differentials between ethane and natural gas can cause natural gas processors to recover ethane or leave it in the natural gas stream, known as ethane rejection.

As a result of these ethane economics, ethane volumes on our system can fluctuate.

In the second half of 2022, ethane prices decreased relative to natural gas prices, as overall demand decreased, and were further impacted by lower petrochemical plant utilization, both planned and unplanned.

This resulted in higher ethane rejection across most basins where we operate, with the largest impact in the Mid-Continent region, compared with the first half of 2022.

As utilization increases and demand for feedstock returns, we expect improvement in ethane economics;

however, price fluctuations are expected to continue.

Ethane volumes under long-term contracts delivered to our NGL system increased approximately 20 MBbl/d to an average of 450 MBbl/d in 2022, compared with 430 MBbl/d in 2021, due primarily to changes in ethane extraction economics.

We estimate that there are more than 225 MBbl/d of discretionary ethane, consisting of more than 125 MBbl/d in the Rocky Mountain region and approximately 100 MBbl/d in the Mid-Continent region, that can be recovered and transported on our system.

Growth Projects - We operate an integrated, reliable and diversified network of NGL and natural gas gathering, processing, fractionation, transportation and storage assets connecting supply in the Rocky Mountain, Mid-Continent and Permian regions with key market centers.

Our primary capital-growth projects are outlined in the table below:

Ethane volumes under long-term contracts delivered to our NGL system increased 25 MBbl/d to an average of 475 MBbl/d during 2023, compared with an average of 450 MBbl/d in 2022, due primarily to changes in ethane extraction economics.

We estimate that there are approximately 250 MBbl/d of discretionary ethane, consisting of approximately 150 MBbl/d in the Rocky Mountain region and approximately 100 MBbl/d in the Mid-Continent region, that could be recovered and transported on our system.

Capital Projects - Our primary capital projects are outlined in the table below:

Project Scope Approximate

Natural Gas Gathering and Processing ( In millions )

Demicks Lake III plant 200 MMcf/d processing plant in the core of the Williston Basin $188 Completed

Supported by acreage dedications with primarily fee-based contracts

Natural Gas Liquids

MB-5 fractionator 125 MBbl/d NGL fractionator in Mont Belvieu, Texas $750 Second Quarter 2023

Natural Gas Liquids (In millions)

MB-5 fractionator 125 MBbl/d NGL fractionator in Mont Belvieu, Texas $750 Completed

MB-6 fractionator 125 MBbl/d NGL fractionator in Mont Belvieu, Texas $550 First Quarter 2025

West Texas NGL pipeline expansion Increase capacity to 740 MBbl/d in the Permian Basin

$520 First Quarter 2025

Elk Creek pipeline expansion

Increase capacity to 435 MBbl/d out of the Rocky Mountain region

$355 First Quarter 2025

Natural Gas Pipelines

Viking compressor stations Electrification and replacement of certain compressor assets $95 Third Quarter 2023

Viking compressor stations Electrification and replacement of certain compressor assets $110 Completed

(a) - Excludes capitalized interest/AFUDC.

Debt Issuances and Repayments - In November 2022, we completed an underwritten public offering of $750 million, 6.1% senior unsecured notes due 2032.

The net proceeds, after deducting underwriting discounts, commissions and offering expenses, were $742 million.

The proceeds were used primarily to repay all outstanding amounts under our commercial paper program.

The remainder was used for general corporate purposes.

In July 2022, we redeemed the remaining $895.8 million of our 3.375% senior notes due October 2022 at 100% of the principal amount, plus accrued and unpaid interest, with cash on hand and short-term borrowings.

Subsequent event - We elected to redeem our $425 million, 5.0% senior notes due September 2023, with a redemption effective date in late February 2023.

We expect the redemption price to equal 100% of the principal amount of the notes, plus accrued and unpaid interest, which we will pay with cash on hand.

Dividends - During 2022, we paid common stock dividends totaling $3.74 per share, which is consistent with the prior year.

Debt Issuances - In August 2023, we completed an underwritten public offering of $5.25 billion senior unsecured notes consisting of $750 million, 5.55% senior notes due 2026;

$750 million, 5.65% senior notes due 2028;

$500 million, 5.80% senior notes due 2030;

$1.5 billion, 6.05% senior notes due 2033;

and $1.75 billion, 6.625% senior notes due 2053.

The net proceeds, after deducting underwriting discounts, commissions and offering expenses, were $5.2 billion.

The net proceeds were used to fund the cash consideration and other costs related to the Magellan Acquisition.

Debt Repayments - In 2023, we repurchased in the open market outstanding principal of certain of our senior notes in the amount of $322 million for an aggregate repurchase price of $280 million, including accrued and unpaid interest, with cash on hand.

In connection with these open market repurchases, we recognized $41 million of net gains on extinguishment of debt.

In June 2023, we redeemed our $500 million, 7.5% senior notes due September 2023 at 100% of the principal amount, plus accrued and unpaid interest, with cash on hand.

In February 2023, we redeemed our $425 million, 5.0% senior notes due September 2023 at 100% of the principal amount, plus accrued and unpaid interest, with cash on hand.

Share Repurchase Program - In January 2024, our Board of Directors authorized a share repurchase program to buy up to $2.0 billion of our outstanding common stock and targets the program to be largely utilized over the next four years.

We expect shares to be acquired from time to time in open-market transactions or through privately negotiated transactions at our discretion, subject to market conditions and other factors.

We expect any purchases to be funded by cash on hand, cash flow from operations and short-term borrowings.

The program will terminate upon completion of the repurchase of $2.0 billion of common stock or on January 1, 2029, whichever occurs first.

As of February 20, 2024, no shares have been repurchased under the program.

Dividends - During 2023, we paid common stock dividends totaling $3.82 per share, an increase of 2% compared to the 2022 dividend of $3.74 per share.

In February 2024, we paid a quarterly common stock dividend of $0.99 per share ($3.96 per share on an annualized basis), an increase of 3.7% compared with the same quarter in the prior year.

Our dividend growth is primarily due to the increase in cash flows resulting from the growth of our operations.

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FINANCIAL RESULTS AND OPERATING INFORMATION

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Non-GAAP Financial Measures - Adjusted EBITDA is a non-GAAP measure of our financial performance.

Adjusted EBITDA is defined as net income adjusted for interest expense, depreciation and amortization, noncash impairment charges, income taxes, allowance for equity funds used during construction, noncash compensation expense and certain other noncash items.

Adjusted EBITDA is defined as net income adjusted for interest expense, depreciation and amortization, noncash impairment charges, income taxes, noncash compensation expense and certain other noncash items.

Following the Magellan Acquisition, we performed a review of our calculation methodology of adjusted EBITDA, and beginning in 2023, we updated our calculation to include the adjusted EBITDA related to our unconsolidated affiliates using the same recognition and measurement methods used to record equity in net earnings from investments.

In prior periods, our calculation included equity in net earnings from investments.

This change resulted in an additional $62 million of adjusted EBITDA in 2023, and we have not restated prior periods.

Adjusted EBITDA from our unconsolidated affiliates is calculated consistently with the definition above and excludes items such as interest, depreciation, income taxes and other noncash items.

Although the amounts related to our unconsolidated affiliates are included in the calculation of adjusted EBITDA, such inclusion should not be understood to imply that we have control over the operations and resulting revenues, expenses or cash flows of such unconsolidated affiliates.

We believe this non-GAAP financial measure is useful to investors because it and similar measures are used by many companies in our industry as a measurement of financial performance and is commonly employed by financial analysts and others to evaluate our financial performance and to compare financial performance among companies in our industry.

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Depreciation and amortization 769 626 622 143 4

Impairment charges — — 607.2 — (607.2)

Other operating (income) expense, net (106.2) (1.4) (1.3) 104.8 0.1

Transaction costs 158 — — 158 —

Other operating income, net

(786) (105) (2) 681 103

Operating income $ 4,072 $ 2,807 $ 2,596 1,265 211

Equity in net earnings from investments $ 202 $ 148 $ 122 54 26

Impairment of equity investments $ — $ — $ (37.7) — (37.7)

Interest expense, net of capitalized interest $ (866) $ (676) $ (733) 190 (57)

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See reconciliation of net income to adjusted EBITDA in the “Non-GAAP Financial Measures” section.

Changes in commodity prices and sales volumes affect both revenues and cost of sales and fuel in our Consolidated Statements of Income and, therefore, the impact is largely offset between these line items, except where noted.

Operating income for the year ended December 31, 2022, includes $96.1 million of business interruption insurance recoveries, which are included in the other operating (income) expense, net line item above, and an approximately $30 million unfavorable impact from the 45-day business interruption coverage waiting period related to the Medford incident in our Natural Gas Liquids segment.

2021 - Operating income increased $211.1 million primarily as a result of the following:

• Natural Gas Gathering and Processing - an increase of $127.7 million due primarily to higher realized commodity prices, net of hedging, and higher average fee rates and $53.8 million from higher volumes in the Rocky Mountain and Mid-Continent regions;

• Natural Gas Liquids - an increase of $102.8 million in exchange services related primarily to higher average fee rates and higher volumes in the Rocky Mountain region and Permian Basin, offset partially by higher fuel and power costs and third-party fractionation costs;

an increase of $46.2 million due to the unfavorable impact of Winter Storm Uri in the first quarter 2021 and $18.2 million in higher optimization and marketing earnings;

• Natural Gas Pipelines - a decrease of $134.7 million due to the favorable impact of Winter Storm Uri in the first quarter 2021, offset partially by increases of $92.1 million due primarily to higher storage and transportation services, higher average earnings on natural gas sales and higher pricing on compression services;

• Consolidated Operating Costs - an increase of $82.7 million due primarily to higher outside services, materials and supplies expense and property taxes, related primarily to the growth of our operations.

Net income and diluted EPS increased due primarily to the items discussed above, lower interest expense related to increased capitalized interest and lower debt balances and higher equity in net earnings from investments.

These increases were offset partially by higher income taxes and losses related to the mark-to-market of investments associated with certain benefit plan investments.

Capital expenditures increased due primarily to our capital-growth projects, including the construction of our Demicks Lake III natural gas processing plant, our MB-5 fractionator and the Viking compression project.

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

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2022 - Operating income increased $1.3 billion primarily as a result of the following:

• Natural Gas Gathering and Processing - an increase of $227 million from higher volumes in the Rocky Mountain and Mid-Continent regions and an increase of $49 million due primarily to higher average fee rates;

• Natural Gas Liquids - an increase of $663 million related to the Medford incident and an increase of $303 million in exchange services;

• Natural Gas Pipelines - an increase of $43 million in transportation and storage services;

• Refined Products and Crude - transportation and storage revenues of $535 million for the period of September 25, 2023, through December 31, 2023 due to the impact of the Magellan Acquisition;

• Consolidated Operating, Depreciation and Transaction Costs - an increase of $290 million in operating costs and depreciation expense from our Refined Products and Crude segment, an increase of $158 million from transaction costs related to the Magellan Acquisition and an increase of $239 million due primarily to higher operating costs and depreciation expense in our Natural Gas Gathering and Processing, Natural Gas Liquids and Natural Gas Pipelines segments.

Net income and diluted EPS increased due primarily to the items discussed above, higher equity in net earnings from investments, higher interest income due to both higher cash balances and higher interest rates and net gains on extinguishment of debt related to open market repurchases.

These increases were offset partially by higher income taxes and higher interest expense due to interest costs resulting from the Magellan Acquisition, which include acquired debt balances, our August 2023 $5.25 billion notes offering and commitment fees associated with our undrawn and terminated 364-day bridge loan facility.

Capital expenditures increased due primarily to our capital projects, including our MB-6 fractionator, NGL pipeline expansion projects and the Viking compression project.

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

In connection with the Magellan Acquisition, we reviewed our business segments in light of certain changes in the financial information regularly reviewed by our chief operating decision maker and other factors.

Based on this review, we added the Refined Products and Crude segment.

This change, which was effective as of September 25, 2023, had no impact on our consolidated financial statements for any periods.

Selected Financial Results and Operating Information for the Year Ended December 31, 2022 vs.

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Natural Gas Gathering and Processing

Growth Projects - Our Natural Gas Gathering and Processing segment has invested in growth projects in NGL-rich areas in the Williston Basin.

See “Growth Projects” in the “Recent Developments” section for discussion of our capital-growth projects.

Capital Projects - Our Natural Gas Gathering and Processing segment invests in capital projects in NGL-rich areas where we operate.

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

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

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(448) (386) (351) 62 35

Equity in net earnings (loss) from investments 4.9 3.8 (1.1) 1.1 4.9

Adjusted EBITDA from unconsolidated affiliates (a)

Equity in net earnings from investments (a)

Other (1) 2 1 (3) 1

Adjusted EBITDA $ 1,244 $ 1,037 $ 889 207 148

Impairment charges $ — $ — $ 566.1 — (566.1)

Capital expenditures $ 448 $ 445 $ 275 3 170

(a) - Beginning in 2023, we updated our calculation methodology of adjusted EBITDA to include adjusted EBITDA from our unconsolidated affiliates, which resulted in an additional $3 million of adjusted EBITDA in 2023, and we have not restated prior periods.

See reconciliation of net income to adjusted EBITDA in the “Non-GAAP Financial Measures” section.

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

2021 - Adjusted EBITD A increased $147.5 million, p rimarily as a result of the following:

• an increase of $127.7 million due primarily to higher realized commodity prices, net of hedging, and average fee rates;

• an increase of $53.8 million from higher volumes due primarily to increased producer activity in the Rocky Mountain and Mid-Continent regions, offset partially by the impact of winter weather in the Rocky Mountain region in the second and fourth quarters of 2022;

• an increase of $35.2 million in operating costs due primarily to higher materials and supplies expense due primarily to the growth of our operations and higher outside services.

Capital expenditures increase d due primarily to growth projects, including our Demicks Lake III project.

2022 - Adjusted EBITDA increased $207 million, primarily as a result of the following:

• an increase of $227 million from higher volumes due primarily to increased producer activity in the Rocky Mountain and Mid-Continent regions, and the impact of winter weather in the Rocky Mountain region in the second and fourth quarters of 2022;

• an increase of $49 million due primarily to higher average fee rates and realized condensate prices, net of hedging, offset partially by lower realized NGL prices, net of hedging;

• an increase of $62 million in operating costs due primarily to higher employee-related costs, outside services and materials and supplies expense due primarily to the growth of our operations, and higher property insurance premiums.

Capital expenditures remained relatively unchanged for 2023, as compared to 2022, due primarily to increased expenditures in 2023 on various capital projects, offset by expenditures in 2022 on our Demicks Lake III project completed in the first quarter of 2023.

Years Ended December 31,

Operating Information (a) 2023 2022 2021

Natural gas gathered ( BBtu/d )

2,852 2,736 2,553

Natural gas processed ( BBtu/d ) (b)

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

2021 - Our natural gas gathered and natural gas processed volumes increased due primarily to increased producer activity in the Rocky Mountain and Mid-Continent regions, offset partially by the unfavorable impact of winter weather in the Rocky Mountain region in the second and fourth quarters of 2022.

2022 - Our natural gas processed volumes increased 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.

Our average fee rate increased due primarily to increased contribution of volumes on higher fee contracts in the Williston Basin and inflation-based escalators in our contracts.

Also, for certain fee with POP contracts, our contractual fees increased due to production volumes, delivery pressures or commodity prices relative to specified contractual thresholds.

Commodity Price Risk - See discussion regarding our commodity price risk under “Commodity Price Risk” in Item 7A, Quantitative and Qualitative Disclosures about Market Risk.

Natural Gas Liquids

Growth Projects - Our Natural Gas Liquids segment invests in projects to transport, fractionate, store and deliver to market centers NGL supply from shale and other resource development areas.

Our growth strategy is focused around connecting

diversified supply basins from the Rocky Mountain region through the Mid-Continent region and the Permian Basin with purity NGLs demand from the petrochemical and refining industries and NGL export demand in the Gulf Coast.

See “Growth Projects” in the “Recent Developments” section for discussion of our capital-growth projects.

In 2022, we connected one third-party natural gas processing plant in the Permian Basin and one raw feed truck terminal in the Mid-Continent region to our NGL system.

In addition, one third-party natural gas processing plant in the Permian Basin connected to our system was expanded.

Capital Projects - Our Natural Gas Liquids segment invests in capital projects to transport, fractionate, store, deliver to market centers and receive NGL supply from shale and other resource development areas.

Our growth strategy is focused around

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connecting diversified supply basins from the Rocky Mountain region through the Mid-Continent region and the Permian Basin with demand for Purity NGLs from the petrochemical and refining industries and NGL exports in the Gulf Coast.

We proactively monitor lead times on materials and equipment used in constructing capital projects, and we enter into procurement agreements for long-lead items for potential projects to plan for future growth.

See “Capital Projects” in the “Recent Developments” section for more information on our capital projects.

In 2023, we connected two third-party natural gas processing plants in the Permian Basin and one affiliate natural gas processing plant in the Rocky Mountain region.

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

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Operating costs, excluding noncash compensation adjustments (637) (549) (499) 88 50

Equity in net earnings from investments 34.6 21.0 39.9 13.6 (18.9)

Adjusted EBITDA from unconsolidated affiliates (a)

Equity in net earnings from investments (a)

— 35 21 (35) 14

Other 778 88 (10) 690 98

Adjusted EBITDA $ 3,045 $ 2,095 $ 1,964 950 131

Impairment charges $ — $ — $ 78.8 — (78.8)

Capital expenditures $ 818 $ 581 $ 307 237 274

See reconciliation of net income to adjusted EBITDA in the “Non-GAAP Measures” section.

(a) - Beginning in 2023, we updated our calculation methodology of adjusted EBITDA to include adjusted EBITDA from our unconsolidated affiliates which resulted in an additional $9 million of adjusted EBITDA in 2023, and we have not restated prior periods.

See reconciliation of net income to adjusted EBITDA in the “Non-GAAP Financial Measures” section.

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

Adjusted EBITDA for the year ended December 31, 2022, includes $96.1 million of business interruption insurance recoveries, which are included in the other line item above, and an approximately $30 million unfavorable impact from the 45-day business interruption coverage waiting period related to the Medford incident.

2022 - Adjusted EBITDA increased $950 million primarily as a result of the following:

• an increase of $102.8 million in exchange services (excluding the impact of Winter Storm Uri discussed below) due primarily to:

◦ $186.3 million in higher average fee rates, primarily as a result of inflation-based and fuel cost escalators in our contracts,

◦ $50.1 million in higher volumes primarily in the Rocky Mountain region and Permian Basin, offset partially by lower volumes in the Mid-Continent region, offset by

◦ $129.9 million in higher costs, primarily fuel and power costs and third-party fractionation costs.

A portion of the third-party fractionation costs relate to the 45-day Medford incident business interruption coverage waiting period, and

◦ $12.9 million related to recognition of proceeds previously considered a gain contingency in 2021;

• an increase of $46.2 million in exchange services due to the unfavorable impact of Winter Storm Uri in the first quarter 2021;

• an increase of $18.2 million in optimization and marketing due primarily to wider location and commodity price differentials, offset partially by nonrecurring activities in the first quarter 2021 during Winter Storm Uri;

• an increase of $13.6 million in equity in net earnings from investments due primarily to higher volumes delivered to the Overland Pass pipeline;

• an increase of $48.8 million in operating costs due primarily to higher property taxes associated with our completed capital-growth projects and higher outside services.

Capital expenditures increased due primarily to capital-growth projects, including our MB-5 fractionator.

• an increase of $663 million related to the Medford incident, due to the settlement gain of $779 million, offset partially by $146 million of third-party fractionation costs, compared with an approximately $30 million unfavorable impact of the 45-day waiting period in 2022;

• an increase of $303 million in exchange services due primarily to higher volumes across the system, offset partially by narrower commodity price differentials;

• an increase of $32 million in earnings from unconsolidated affiliates due primarily to higher volumes delivered to the Overland Pass pipeline and the change in calculation methodology in 2023;

• an increase of $20 million due primarily to higher volumes on the ONEOK North System and higher storage revenue;

• an increase of $12 million in optimization and marketing due primarily to higher earnings on sales of Purity NGLs held in inventory;

• an increase of $88 million in operating costs due primarily to higher employee-related costs and higher outside services due to the growth of our operations, and higher property insurance premiums.

Capital expenditur es increased in 2023 due primarily to capital projects, which includes our MB-6 fractionator and pipeline expansion projects.

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Years Ended December 31,

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We generally expect ethane volumes to increase or decrease with corresponding increases or decreases in overall NGL production.

However, ethane volumes may experience growth or decline greater than corresponding growth or decline in overall NGL production due to ethane economics causing producers to extract or reject ethane.

2021 - Volumes increased due primarily to increased NGL production in the Rocky Mountain region and Permian Basin, and higher ethane volumes from incentivized ethane recovery in the Rocky Mountain region, offset partially by decreased ethane recovery in the Mid-Continent region due to ethane economics.

Volumes also benefited from the unfavorable impact of Winter Storm Uri in the first quarter 2021, offset partially by the impact of winter weather in the Rocky Mountain region in the second and fourth quarters of 2022.

However, ethane volumes may experience growth or decline greater than corresponding growth or decline in overall NGL production due to ethane economics causing producers to recover or reject ethane.

2022 - Volumes increased due primarily to increased production in the Permian Basin and Rocky Mountain region and increased ethane volumes in the Mid-Continent region.

Natural Gas Pipelines

Growth Projects - Our Natural Gas Pipelines segment invests in projects that provide transportation and storage services to end users.

In December 2022, our Saguaro Connector Pipeline L.L.C.

subsidiary filed a Presidential Permit application with the FERC to construct and operate new international border-crossing facilities at the U.S.

Capital Projects - Our Natural Gas Pipelines segment invests in capital projects that provide transportation and storage services to end users.

In February 2024, the FERC approved our Saguaro Connector Pipeline, L.L.C.’s Presidential Permit application to construct and operate new international border-crossing facilities at the U.S.

and Mexico border.

The proposed border facilities would connect upstream with a potential intrastate pipeline, the Saguaro Connector Pipeline, which would be owned and operated by ONEOK.

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 pipeline is expected by mid-2023.

See “Growth Projects” in the “Recent Developments” section for discussion of our capital-growth projects.

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

In 2023, we completed an expansion of our injection capabilities of our Oklahoma natural gas storage facilities, which allowed us to utilize and subscribe an additional 4 Bcf of our existing storage capacity, which is fully subscribed through 2027 and 90% subscribed through 2029.

We are reactivating previously idled storage facilities with 3 Bcf of working gas storage capacity in Texas, which is already fully subscribed on a firm basis.

We are also further expanding our injection capabilities in Oklahoma to allow us to subscribe additional firm storage capacity.

See “Capital Projects” in the “Recent Developments” section for a discussion of our capital projects.

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

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(194) (174) (162) 20 12

Equity in net earnings from investments 108.2 97.8 104.4 10.4 (6.6)

Adjusted EBITDA from unconsolidated affiliates (a)

160 — — 160 —

Equity in net earnings from investments (a)

— 108 97 (108) 11

Other (2) — (3) (2) 3

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Capital expenditures $ 228 $ 123 $ 93 105 30

See reconciliation of net income to adjusted EBITDA in the “Non-GAAP Measures” section.

2021 - Adjusted EBITDA decreased $39.4 million primarily as a result of the following:

• a decrease of $134.7 million due to the favorable impact of Winter Storm Uri in the first quarter 2021 on natural gas sales of volumes previously held in inventory, interruptible transportation revenue and park and loan revenue;

• an increase of $12.0 million in operating expenses due primarily to higher outside services, offset by

• an increase of $51.5 million in storage services due primarily to higher storage rates on renegotiated contracts;

• an increase of $23.1 million in transportation services due primarily to higher interruptible revenue, excluding the impact of Winter Storm Uri in the first quarter 2021 noted above, and higher firm transportation revenue;

• an increase of $17.5 million due primarily to higher average earnings on natural gas sales of volumes previously held in inventory, excluding the impact of Winter Storm Uri in the first quarter 2021 noted above, and higher pricing on compression services;

• an increase of $10.4 million from higher equity in net earnings from investments due primarily to increased volumes on Northern Border and higher firm transportation rates on Roadrunner.

Capital expenditur es increased in 2022 due primarily to capital-growth projects, including the Viking compression project.

(a) - Beginning in 2023, we updated our calculation methodology of adjusted EBITDA to include adjusted EBITDA from our unconsolidated affiliates which resulted in an additional $42 million of adjusted EBITDA in 2023, and we have not restated prior periods.

See reconciliation of net income to adjusted EBITDA in the “Non-GAAP Financial Measures” section.

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2022 - Adjusted EBITDA increased $71 million primarily as a result of the following:

• an increase of $43 million in transportation and storage services due primarily to higher storage rates on renegotiated contracts, higher storage volumes related to completed projects and higher firm and interruptible transportation volumes;

• an increase of $42 million in earnings from unconsolidated affiliates due to the change in calculation methodology in 2023;

• an increase of $20 million in operating costs due primarily to higher employee-related costs.

Capital expenditur es increased in 2023 due primarily to capital projects, including the Viking compression project.

Years Ended December 31,

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In August 2022, Guardian reached a settlement in principle with the participants in the Section 5 rate case.

The FERC approved the settlement in February 2023, which w ill result in a future reduction of rates.

We do not expect the reduced rates to have a material impact on our results of operations.

The FERC approved the settlement in February 2023, which resulted in a reduction of rates starting in April 2023 .

The reduced rates did not have a material impact on our results of operations.

In July 2023, Viking filed a proposed increase in rates pursuant to Section 4 of the Natural Gas Act with the FERC .

The FERC is currently reviewing the filing.

While the ultimate outcome of the filing cannot be predicted, we do not expect it to materially impact our results of operations.

Refined Products and Crude

Capital Projects - Our Refined Products and Crude segment invests in capital projects to transport, store and distribute Refined Products and crude oil primarily throughout the central United States.

Our growth strategy is focused on expanding our core business and marketing presence.

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

Selected Financial Results and Operating Information - The following tables set forth certain selected financial results and operating information for our Refined Products and Crude segment for the period subsequent to the closing of the Magellan Acquisition:

September 25 through December 31, 2023

Financial Results

( Millions of dollars )

Product sales $ 502

Transportation revenues 392

Storage, terminals and other revenues

Cost of sales and fuel (exclusive of depreciation and operating costs)

Operating costs, excluding noncash compensation adjustments

Adjusted EBITDA from unconsolidated affiliates

Adjusted EBITDA $ 465

Capital expenditures $ 52

See reconciliation of net income to adjusted EBITDA in the “Non-GAAP Financial Measures” section.

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Three Months Ended December 31,

Operating Information (a)

Refined Products volume shipped ( MBbl/d )

Crude oil volume shipped ( MBbl/d )

(a) - Includes volumes for consolidated entities only.

NON-GAAP FINANCIAL MEASURES

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2023 2022 2021

Reconciliation of net income to adjusted EBITDA ( Thousands of dollars)

Reconciliation of net income to adjusted EBITDA (Millions of dollars)

Net income $ 2,659 $ 1,722 $ 1,500

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Income taxes 838 528 484

Impairment charges — — 644,930

Noncash compensation expense (a) 70,502 42,592 8,540

Equity AFUDC (2,551) (1,681) (23,661)

Adjusted EBITDA (b) $ 3,619,674 $ 3,379,740 $ 2,723,673

Adjusted EBITDA from unconsolidated affiliates (c)

Equity in net earnings from investments (c)

Noncash compensation expense and other 49 68 41

Adjusted EBITDA (a)(b)(c) $ 5,243 $ 3,620 $ 3,380

Reconciliation of segment adjusted EBITDA to adjusted EBITDA

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Natural Gas Gathering and Processing $ 1,244 $ 1,037 $ 889

Natural Gas Liquids 2,095,212 1,963,639 1,617,241

Natural Gas Liquids (a) 3,045 2,095 1,964

Natural Gas Pipelines 559 488 528

Refined Products and Crude (d)

Other (b) (70) — (1)

Adjusted EBITDA $ 3,619,674 $ 3,379,740 $ 2,723,673

(a) - Years ended December 31, 2022, 2021 and 2020, includes a loss of $18.8 million, and benefits of $10.4 million and $19.8 million, respectively, related to the mark-to-market of investments associated with certain benefit plan investments.

(b) - Year ended December 31, 2020, includes corporate net gains of $22.3 million on extinguishment of debt related to open market repurchases.

Adjusted EBITDA (a)(b)(c) $ 5,243 $ 3,620 $ 3,380

(a) - The year ended December 31, 2023, includes $633 million related to the Medford incident, including a settlement gain of $779 million, offset partially by $146 million of third-party fractionation costs.

(b) - The year ended December 31, 2023, primarily includes transaction costs related to the Magellan Acquisition of $158 million, offset partially by interest income of $49 million and net gains of $41 million on extinguishment of debt related to open market repurchases.

(c) - Beginning in 2023, we updated our calculation methodology of adjusted EBITDA to include adjusted EBITDA from our unconsolidated affiliates using the same recognition and measurement methods used to record equity in net earnings from investments.

In prior periods, our calculation included equity in net earnings from investments.

This change resulted in an additional $62 million of adjusted EBITDA in 2023, and we have not restated prior periods.

(d) - Includes segment adjusted EBITDA for the period September 25, 2023, through December 31, 2023.

CONTINGENCIES

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

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

Other Legal Proceedings - We are a party to various legal proceedings that have arisen in the normal course of our operations.

While the results of these proceedings cannot be predicted with certainty, we believe the reasonably possible losses from such

proceedings, individually and in the aggregate, are not material.

While the results of these proceedings cannot be predicted with certainty, we believe the reasonably possible losses from such proceedings, individually and in the aggregate, are not material.

Additionally, we believe the probable final outcome of such proceedings will not have a material adverse effect on our consolidated results of operations, financial position or cash flows.

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General - Our primary sources of cash inflows are operating cash flows, proceeds from our commercial paper program and our $2.5 Billion Credit Agreement, debt issuances and the issuance of common stock for our liquidity and capital resources requirements.

On January 9, 2023, we reached an agreement with our insurers to settle all claims for physical damage and business interruption related to the Medford incident.

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In January 2023, we reached an agreement with our insurers to settle all claims for physical damage and business interruption related to the Medford incident.

Under the terms of the settlement agreement, we agreed to resolve the claims for total insurance payments of $930 million, $100 million of which was received in 2022.

The remaining $830 million was received in the first quarter 2023.

The remaining $830 million was received in the first quarter of 2023.

The proceeds serve as settlement for property damage, business interruption claims to the date of settlement and as payment in lieu of future business interruption insurance claims.

We expect our sources of cash inflows to provide sufficient resources to finance our operations, quarterly cash dividends, capital expenditures and maturities of long-term debt.

We expect our cash from operations in 2024 to be impacted by incurred costs resulting from the Medford incident for which we no longer receive business interruption proceeds.

We expect our sources of cash inflows to provide sufficient resources to finance our operations, capital expenditures, quarterly cash dividends, maturities of long-term debt, share repurchases and contributions to unconsolidated affiliates.

We believe we have sufficient liquidity due to our $2.5 Billion Credit Agreement, which expires in June 2027, and access to $1.0 billion available through our “at-the-market” equity program.

As of the date of this report, no shares have been sold through our “at-the-market” equity program.

We may manage interest-rate risk through the use of fixed-rate debt, floating-rate debt and interest-rate swaps.

For additional information on our interest-rate swaps, see Note D of the Notes to Consolidated Financial Statements in this Annual Report.

Guarantees and Cash Management - We and ONEOK Partners are issuers of certain public debt securities.

We guarantee certain indebtedness of ONEOK Partners, and ONEOK Partners and the Intermediate Partnership guarantee certain of our indebtedness.

The guarantees in place for our and ONEOK Partners’ indebtedness are full, irrevocable, unconditional and absolute joint and several guarantees to the holders of each series of outstanding securities.

Liabilities under the guarantees rank equally in right of payment with all existing and future senior unsecured indebtedness.

As ONEOK Partners and the Intermediate Partnership are consolidated subsidiaries of ONEOK, separate financial statements for the guarantors are not required, as long as the alternative disclosure required by Rule 13-01 is provided, which includes narrative disclosure and summarized financial information.

The Intermediate Partnership holds all of ONEOK Partners’ interests and equity in its subsidiaries, which are nonguarantors, and substantially all the assets and operations reside with nonguarantor operating subsidiaries.

Therefore, as allowed under Rule 13-01, we have excluded the summarized financial information for each issuer and guarantor as the combined financial information of the subsidiary issuer and parent guarantor, excluding our ownership of all the interests in ONEOK Partners, reflect no material assets, liabilities or results of operations, apart from the guaranteed indebtedness.

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

We may manage interest-rate risk through the use of fixed-rate debt, floating-rate debt, Treasury locks and interest-rate swaps.

For additional information on our interest-rate swaps, see Note E of the Notes to Consolidated Financial Statements in this Annual Report.

Cash Management - At December 31, 2023, we had $338 million of cash and cash equivalents.

We use a centralized cash management program that concentrates the cash assets of our nonguarantor operating subsidiaries in joint accounts for the purposes of providing financial flexibility and lowering the cost of borrowing, transaction costs and bank fees.

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Under the cash management program, depending on whether a participating subsidiary has short-term cash surpluses or cash requirements, we provide cash to the subsidiary or the subsidiary provides cash to us.

Guarantees - In December 2023, ONEOK assumed the debt obligations of Magellan under its previous debt indentures and Magellan provided a guarantee of the outstanding notes.

As of December 31, 2023, Magellan no longer had debt obligations outstanding.

We guarantee certain debt securities of ONEOK Partners, and ONEOK Partners, the Intermediate Partnership and Magellan guarantee certain of our debt securities.

Liabilities under the guarantees rank equally in right of payment with all existing and future senior unsecured indebtedness.

Magellan holds interests in its subsidiaries, which are nonguarantors, and substantially all the assets and operations reside with nonguarantor operating subsidiaries.

Therefore, as allowed under Rule 13-01, we have excluded the summarized financial information for each issuer and guarantor as the combined financial information of the subsidiary issuers and parent guarantor, excluding our ownership of all the interests in ONEOK Partners and Magellan, reflect no material assets, liabilities or results of operations, apart from the guaranteed indebtedness.

For additional information on our and ONEOK Partners’ indebtedness, please see Note H of the Notes to Consolidated Financial Statements in this Annual Report.

Short-term Liquidity - Our principal sources of short-term liquidity consist of cash generated from operating activities, distributions received from our equity-method investments, proceeds from our commercial paper program and our $2.5 Billion Credit Agreement.

We had working capital (defined as current assets less current liabilities) deficits of $503.9 million and $810.2 million as of December 31, 2022, and December 31, 2021, respectively.

Although working capital is influenced by several factors, including, among other things:

As of December 31, 2023, we had no borrowings under our $2.5 Billion Credit Agreement and we are in compliance with all covenants.

We had working capital (defined as current assets less current liabilities) deficits of $344 million and $503 million as of December 31, 2023, and December 31, 2022, respectively due primarily to current maturities of long-term debt.

Generally, our working capital is influenced by several factors, including, among other things:

(i) the timing of (a) debt and equity issuances, (b) the funding of capital expenditures, (c) scheduled debt repayments, and (d) accounts receivable and payable;

and (ii) the volume and cost of inventory and commodity imbalances, our working capital deficits at December 31, 2022 and 2021, were driven primarily by current maturities of long-term debt.

We may have working capital deficits in future periods as we continue to repay long-term debt.

We do not expect this working capital deficit to have an adverse impact to our cash flows or operations.

At December 31, 2022, we had no borrowings under our $2.5 Billion Credit Agreement and $220.2 million of cash and cash equivalents.

In June 2022, we amended and restated our $2.5 Billion Credit Agreement, which matures in June 2027.

As of December 31, 2022, we are in compliance with all covenants of our $2.5 Billion Credit Agreement.

For additional information on our $2.5 Billion Credit Agreement, see Note G of the Notes to Consolidated Financial Statements in this Annual Report.

Long-term Financing - In addition to our principal sources of short-term liquidity discussed above, we expect to fund our longer-term financing requirements by issuing long-term notes.

and (ii) the volume and cost of inventory and commodity imbalances.

We may have working capital deficits in future periods as our long-term debt becomes current.

We do not expect a working capital deficit of this nature to have a material adverse impact to our cash flows or operations.

For additional information on our $2.5 Billion Credit Agreement, see Note H of the Notes to Consolidated Financial Statements in this Annual Report.

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Long-term Financing - In addition to our principal sources of short-term liquidity discussed above, we expect to fund our longer-term financing requirements by issuing long-term notes, as needed.

Other options to obtain financing include, but are not limited to, issuing common stock, loans from financial institutions, issuance of convertible debt securities or preferred equity securities, asset securitization and the sale and lease-back of facilities.

Debt Issuances - In November 2022, we completed an underwritten public offering of $750 million, 6.1% senior unsecured notes due 2032.

The net proceeds, after deducting underwriting discounts, commissions and offering expenses, were $742 million.

The proceeds were used primarily to repay all outstanding amounts under our commercial paper program.

The remainder was used for general corporate purposes.

In June 2022, Guardian entered into a $120 million unsecured term loan agreement.

During the second quarter 2022, Guardian drew the full $120 million available under the agreement and used the proceeds to repay intercompany debt with ONEOK.

Debt Repayments - In July 2022, we redeemed the remaining $895.8 million of our 3.375% senior notes due October 2022 at 100% of the principal amount, plus accrued and unpaid interest, with cash on hand and short-term borrowings.

Subsequent event - We elected to redeem our $425 million, 5.0% senior notes due September 2023, with a redemption effective date in late February 2023.

We expect the redemption price to equal 100% of the principal amount of the notes, plus accrued and unpaid interest, which we will pay with cash on hand.

We may, at any time, seek to retire or purchase our or ONEOK Partners’ outstanding debt through cash purchases and/or exchanges for equity or debt, in open-market repurchases, privately negotiated transactions or otherwise.

Such repurchases and exchanges, if any, will be on such terms and prices as we may determine, and will depend on prevailing market conditions, or liquidity requirements, contractual restrictions and other factors.

The amounts involved may be material.

Debt Issuances - In August 2023, we completed an underwritten public offering of $5.25 billion senior unsecured notes consisting of $750 million, 5.55% senior notes due 2026;

$750 million, 5.65% senior notes due 2028;

$500 million, 5.80% senior notes due 2030;

$1.5 billion, 6.05% senior notes due 2033;

and $1.75 billion, 6.625% senior notes due 2053.

The net proceeds, after deducting underwriting discounts, commissions and offering expenses, were $5.2 billion.

The net proceeds were used to fund the cash consideration and other costs related to the Magellan Acquisition.

In connection with the underwritten public offering, we terminated the undrawn commitment letter for the $5.25 billion unsecured 364-day bridge loan facility.

In connection with these open market repurchases, we recognized $41 million of net gains on extinguishment of debt.

In November 2023, we made an equity contribution of $91 million to Northern Border, which in combination with an equal contribution from our joint venture partner, was used to partially repay the outstanding balance of its revolving credit facility and fund capital projects.

In June 2023, we redeemed our $500 million, 7.5% senior notes due September 2023 at 100% of the principal amount, plus accrued and unpaid interest, with cash on hand.

In June 2023, we made an equity contribution of $105 million to Roadrunner, which, in combination with an equal contribution from our joint venture partner, was used to repay Roadrunner’s outstanding debt.

In February 2023, we redeemed our $425 million, 5.0% senior notes due September 2023 at 100% of the principal amount, plus accrued and unpaid interest, with cash on hand.

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

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.

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 expect shares to be acquired from time to time in open-market transactions or through privately negotiated transactions at our discretion, subject to market conditions and other factors.

We expect any purchases to be funded by cash on hand, cash flow from operations and short-term borrowings.

The program will terminate upon completion of the repurchase of $2.0 billion of common stock or on January 1, 2029, whichever occurs first.

As of February 20, 2024, no shares have been repurchased under the program.

Material Commitments - We have material cash commitments related to our capital expenditures, senior notes and corresponding interest payments, which we expect to fund through our sources of cash inflows discussed above.

Our senior notes and interest payments are discussed in Note G of the Notes to Consolidated Financial Statements in this Annual Report.

Our senior notes and interest payments are discussed in Note H of the Notes to Consolidated Financial Statements in this Annual Report.

We also have cash commitments related to transportation, storage and other commercial contracts, as well as our financial and physical derivative obligations, which we expect to fund with cash from operations.

Capital Expenditures - We classify expenditures that are expected to generate additional revenue, return on investment or significant operating or environmental efficiencies as growth capital expenditures.

Maintenance capital expenditures are those capital expenditures required to maintain our existing assets and operations and do not generate additional revenues.

Maintenance capital expenditures are made to replace partially or fully depreciated assets, to maintain the existing operating capacity of our assets and to extend their useful lives.

Capital Expenditures - We proactively monitor lead times on materials and equipment used in constructing capital projects, and we enter into procurement agreements for long-lead items for potential projects to plan for future growth.

Our capital expenditures are financed typically through operating cash flows and short- and long-term debt.

The following table sets forth our growth and maintenance capital expenditures, excluding AFUDC, for the periods indicated:

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The following table sets forth our capital expenditures, excluding AFUDC, for the periods indicated:

Capital Expenditures 2023 2022 2021

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Natural Gas Pipelines 228 123 93

Refined Products and Crude (a)

Other 49 53 22

Total capital expenditures $ 1,595 $ 1,202 $ 697

Capital expenditures increased in 2022, compared with 2021, due primarily to our capital-growth projects, including the construction of our Demicks Lake III natural gas processing plant, our MB-5 fractionator and the Viking compression project.

See discussion of our announced capital-growth projects in the “Recent Developments” section.

(a) - Includes capital expenditures for the period September 25, 2023, through December 31, 2023.

Capital expenditures increased in 2023, compared with 2022, due primarily to our capital projects, including our MB-6 fractionator, NGL pipeline expansion projects and the Viking compression project.

See discussion of our announced capital projects in the “Recent Developments” section.

We expect total capital expenditures, excluding AFUDC and capitalized interest, of $1.75-$1.95 billion in 2024.

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Rating Agency Long-Term Rating Short-Term Rating Outlook

Moody’s Baa3 Prime-3 Positive

Moody’s Baa2 Prime-2 Stable

S&P BBB A-2 Stable

Fitch BBB F2 Stable

BBB F2 Stable

Our credit ratings, which are investment grade, may be affected by our leverage, liquidity, credit profile or potential transactions.

In April 2023, Moody’s upgraded the rating on our long-term debt to Baa2 from Baa3, the rating on our short-term debt to Prime-2 from Prime-3 and changed the outlook to stable from positive.

The most common criteria for assessment of our credit ratings are the debt-to-EBITDA ratio, interest coverage, business risk profile and liquidity.

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Dividends - Holders of our common stock share equally in any common stock dividends declared by our Board of Directors, subject to the rights of the holders of outstanding preferred stock.

In 2022, we paid common stock dividends of $3.74 per share, which is consistent with prior year.

In 2023, we paid common stock dividends totaling $3.82 per share, an increase of 2% compared to the 2022 dividend of $3.74 per share.

In February 2024, we paid a quarterly common stock dividend of $0.99 per share ($3.96 per share on an annualized basis), an increase of 3.7% compared with the same quarter in the prior year.

Our Series E Preferred Stock pays quarterly dividends on each share of Series E Preferred Stock, when, as and if declared by our Board of Directors, at a rate of 5.5% per year.

In 2022, we paid dividends of $1.1 million for the Series E Preferred Stock.

In 2023, we paid dividends for the Series E Preferred Stock of $1 million for the series E preferred stock.

In February 2024, we paid quarterly dividends totaling $0.3 million for the Series E Preferred Stock.

For the year ended December 31, 2022, our cash flows from operations exceeded dividends paid by $1.2 billion.

For the year ended December 31, 2023, our cash flows from operations exceeded dividends paid by $2.6 billion, due in part to the insurance proceeds received from the Medford settlement in 2023.

We expect our cash flows from operations to continue to sufficiently fund our cash dividends.

To the extent operating cash flows are not sufficient to fund our dividends, we may utilize cash on hand from other sources of short- and long-term liquidity to fund a portion of our dividends.

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CASH FLOW ANALYSIS

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Under this method, we reconcile net income to cash flows provided by operating activities by adjusting net income for those items that affect net income but do not result in actual cash receipts or payments during the period and for operating cash items that do not impact net income.

These reconciling items can include depreciation and amortization, impairment charges, allowance for equity funds used during construction, gain or loss on sale of assets, deferred income taxes, net undistributed earnings from equity-method investments, share-based compensation expense, other amounts and changes in our assets and liabilities not classified as investing or financing activities.

These reconciling items can include depreciation and amortization, deferred income taxes, impairment charges, allowance for equity funds used during construction, gain or loss on sale of assets, net undistributed earnings from equity-method investments, share-based compensation expense, other amounts and changes in our assets and liabilities not classified as investing or financing activities.

The following table sets forth the changes in cash flows by operating, investing and financing activities for the periods indicated:

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Changes in commodity prices and demand for our services or products, whether because of general economic conditions, changes in supply, changes in demand for the end products that are made with our products or increased competition from other service providers, could affect our earnings and operating cash flows.

Our operating cash flows can also be impacted by changes in our NGLs and natural gas inventory balances, which are driven primarily by commodity prices, supply, demand and the operation of our assets.

2021 - Cash flows from operating activities, before changes in operating assets and liabilities, increased $214.5 million due primarily to higher net income resulting from higher realized commodity prices, net of hedging, and higher average fee rates in our Natural Gas Gathering and Processing segment and higher exchange services in our Natural Gas Liquids segment.

These increases were offset partially by the impact of Winter Storm Uri in our Natural Gas Pipelines segment in the first quarter 2021, as discussed in “Financial Results and Operating Information.”

Our operating cash flows can also be impacted by changes in our inventory balances, which are driven primarily by commodity prices, supply, demand and the operation of our assets.

2022 - Cash flows from operating activities, before changes in operating assets and liabilities increased $1.1 billion for the year ended December 31, 2023, compared with the same period in 2022, due primarily to higher operating income resulting from higher volumes from increased production and higher average fee rates in our Natural Gas Gathering and Processing segment, higher exchange services in our Natural Gas Liquids segment, higher transportation and storage services in our Natural Gas Pipelines segment and an increase due to the impact of the Magellan Acquisition in our Refined Products and Crude segment;

and insurance proceeds received from the Medford settlement.

Please see “Financial Results and Operating Information” for a discussion of operating results.

The changes in operating assets and liabilities increased operating cash flows $358 million for the year ended December 31, 2023, compared with a decrease of $58 million for the same period in 2022.

The change is due primarily to changes in risk management assets and liabilities, which include the gains associated with the settlements of forward-starting interest rate swaps in 2022 and changes in the fair value of risk-management assets and liabilities;

accounts receivable resulting from the timing of receipt of cash from customers and NGLs and natural gas in inventory, both of which vary from period to period and with changes in commodity prices;

offset partially by changes in accounts payable, which also vary from period to period with changes in commodity prices, and from the timing of payments to vendors, suppliers and other third parties and changes in other assets and liabilities.

This change is due primarily to changes in accounts receivable resulting from the timing of receipt of cash from counterparties and from inventory, both of which vary from period to period, and with changes in commodity prices;

offset partially by changes in risk management assets and liabilities.

Investing Cash Flows

2021 - Cash used in investing activities increased $474.0 million due primarily to capital expenditures related to our capital-growth projects.

2022 - Cash used in investing activities for the year ended December 31, 2023, increased $5.3 billion, compared with the same period in 2022, due primarily to the $5.0 billion of cash paid for the Magellan Acquisition.

Financing Cash Flows

2021 - Cash used in financing activities decreased $566.2 million due primarily to the issuance of long-term debt in 2022.

2022 - Cash from financing activities for the year ended December 31, 2023, increased $3.8 billion compared with the same period in 2022, due primarily to the issuance of $5.25 billion senior unsecured notes associated with the Magellan Acquisition.

Cash Flow Analysis for the Year Ended December 31, 2022 vs.

2020 - The cash flow analysis for the year ended December 31, 2021, compared with the year ended December 31, 2020, is included in Part II, Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations of our 2021 Annual Report on Form 10-K, which is available via the SEC’s website at www.sec.gov and our website at www.oneok.com.

2021 - The cash flow analysis for the year ended December 31, 2022, compared with the year ended December 31, 2021, is included in Part II, Item 7, Management’s

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Discussion and Analysis of Financial Condition and Results of Operations of our 2022 Annual Report on Form 10-K, which is available via the SEC’s website at www.sec.gov and our website at www.oneok.com.

IMPACT OF NEW ACCOUNTING STANDARDS

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

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

CRITICAL ACCOUNTING ESTIMATES

The preparation of our Consolidated Financial Statements and related disclosures in accordance with GAAP requires us to make estimates and assumptions with respect to values or conditions that cannot be known with certainty that affect the reported amounts of assets and liabilities, and the disclosure of contingent assets and liabilities at the date of the Consolidated Financial Statements.

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Although we believe these estimates and assumptions are reasonable, actual results could differ from our estimates.

The following is a summary of our most critical accounting policies and estimates, which are defined as those estimates and policies most important to the portrayal of our financial condition and results of operations and requiring management’s most difficult, subjective or complex judgment, particularly because of the need to make estimates concerning the impact of inherently uncertain matters.

We have discussed the development and selection of our estimates and critical accounting policies with the Audit Committee of our Board of Directors.

See Note A of the Notes to Consolidated Financial Statements in this Annual Report for the description of our accounting policies and additional information about our critical accounting policies and estimates.

The following is a summary of our most critical accounting estimates, which are defined as those estimates most important to the portrayal of our financial condition and results of operations and requiring management’s most difficult, subjective or complex judgment, particularly because of the need to make estimates concerning the impact of inherently uncertain matters.

We have discussed the development and selection of our critical accounting estimates with the Audit Committee of our Board of Directors.

See Note A of the Notes to Consolidated Financial Statements in this Annual Report for the description of our accounting policies.

Fair Value Estimates in Business Combination Accounting - Business combination accounting requires that assets and liabilities be recorded at their estimated fair value in connection with the initial recognition of the transaction.

Estimating the fair value of assets and liabilities in connection with business combination accounting requires management to make estimates, assumptions and judgments, and in some cases management may also utilize third-party specialists to assist and advise on those estimates.

In order to estimate the fair value of assets acquired and liabilities assumed, we utilized widely accepted valuation techniques that included discounted cash flow and cost methods.

The discounted cash flow method utilizes assumptions that include, but are not limited to, estimated future cash flows, discount rates applied to estimated future cash flows, estimated rates of return and estimated customer attrition rates.

Cost methods estimate the fair value of assets based on the estimated construction cost of the assets, and requires the use of various inputs and assumptions.

While we believe we have made reasonable assumptions to estimate the fair value, these assumptions are inherently uncertain.

An estimate of the sensitivity to changes in our assumptions is not practicable given the numerous assumptions, and their interdependence, that can materially affect our estimates.

The purchase price allocation recorded in a business combination may change during the measurement period, which is a period not to exceed one year from the date of acquisition, as additional information about conditions existing at the acquisition date becomes available.

See Note B of the Notes to Consolidated Financial Statements in this Annual Report for additional discussion of the business combination.

Derivatives and Risk-Management Activities - We utilize derivatives to reduce our market-risk exposure to commodity price and interest-rate fluctuations and to achieve more predictable cash flows.

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For a derivative designated as a cash flow hedge, the gain or loss from a change in fair value of the derivative instrument is deferred in accumulated other comprehensive loss until the forecasted transaction affects earnings, at which time the fair value of the derivative instrument is reclassified into earnings.

We assess hedging relationships at the inception of the hedge and on an ongoing basis to determine whether the hedging relationship is, and is expected to remain, highly effective.

We assess hedging relationships at the inception of the hedge, and periodically thereafter, to determine whether the hedging relationship is, and is expected to remain, highly effective.

We do not believe that changes in our fair value estimates of our derivative instruments have a material impact on our results of operations, as the majority of our derivatives are accounted for as effective cash flow hedges.

However, if a derivative instrument is ineligible for cash flow hedge accounting or if we fail to appropriately designate it as a cash flow hedge, changes in fair value of the derivative instrument would be recorded currently in earnings.

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Additionally, if a cash flow hedge ceases to qualify for hedge accounting treatment because it is no longer probable that the forecasted transaction will occur, the change in fair value of the derivative instrument would be recognized in earnings.

For more information on commodity price sensitivity and a discussion of the market risk of pricing changes, see Item 7A, Quantitative and Qualitative Disclosures about Market Risk.

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

Impairment of Goodwill and Long-Lived Assets, Including Intangible Assets - We assess our goodwill for impairment at least annually as of July 1, unless events or changes in circumstances indicate an impairment may have occurred before that time.

As part of our goodwill impairment test, we may first assess qualitative factors (including macroeconomic conditions, industry and market considerations, cost factors and overall financial performance) to determine whether it is more likely than not that the fair value of each of our reporting units is less than its carrying amount.

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

Impairment of Goodwill, Long-Lived Assets, Including Intangible Assets and Equity Method Investments - We assess our goodwill for impairment at least annually as of July 1, unless events or changes in circumstances indicate an impairment may have occurred before that time.

If further testing is necessary or a quantitative test is elected, we perform a Step 1 analysis for goodwill impairment.

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If an impairment is indicated, we record an impairment loss equal to the difference between the carrying value and the fair value of the long-lived asset.

We evaluate equity method investments in unconsolidated affiliates for impairment whenever events or circumstances indicate that there is an other-than-temporary loss in value of the investment.

When evidence of loss in value has occurred, we compare our estimate of fair value of the investment to the carrying value of the investment to determine whether an impairment has occurred.

If the estimated fair value is less than the carrying value and we consider the decline in value to be other-than-temporary, the excess of the carrying value over the fair value is recognized in our consolidated financial statements as an impairment charge.

Our impairment tests require the use of assumptions and estimates, such as industry economic factors and the profitability of future business strategies.

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The evaluation is performed at the lowest level for which separately identifiable cash flows exist.

To estimate the fair value of

these assets, we use two generally accepted valuation approaches, an income approach and a market approach.

To estimate the fair value of these assets, we use two generally accepted valuation approaches, an income approach and a market approach.

Under the income approach, our discounted cash flow analysis includes the following inputs that are not readily available:

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If actual results are not consistent with our assumptions and estimates or our assumptions and estimates change due to new information, we may be exposed to future impairment charges.

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

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

Depreciation Methods and Estimated Useful Lives of Property, Plant and Equipment - Our property, plant and equipment are depreciated using the straight-line method that incorporates management assumptions regarding useful economic lives and residual values.

As we place additional assets in service, our estimates related to depreciation expense have become more significant and changes in estimated useful lives of our assets could have a material effect on our results of operations.

As we place additional assets in service or acquire assets as a result of an acquisition or asset purchase, our estimates related to depreciation expense have become more significant and changes in estimated useful lives of our assets could have a material effect on our results of operations.

At the time we place our assets in service, we believe such assumptions are reasonable;

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For the fiscal years presented in this Form 10-K, no changes were made to the determinations of useful lives that would have a material effect on the timing of depreciation expense in future periods.

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

FORWARD-LOOKING STATEMENTS

Some of the statements contained and incorporated in this Annual Report are forward-looking statements as defined under federal securities laws.

The forward-looking statements relate to our anticipated financial performance (including projected operating income, net income, capital expenditures, cash flows and projected levels of dividends), liquidity, management’s plans and objectives for our future capital-growth projects and other future operations (including plans to construct additional natural gas and NGL pipelines, processing and fractionation facilities and related cost estimates), our business prospects, the outcome of regulatory and legal proceedings, market conditions and other matters.

We make these forward-looking statements in reliance on the safe harbor protections provided under federal securities legislation and other applicable laws.

The following discussion is intended to identify important factors that could cause future outcomes to differ materially from those set forth in the forward-looking statements.

Forward-looking statements and other statements in this Annual Report regarding our environmental, social and other sustainability targets, plans and goals are not an indication that these statements are required to be disclosed in our filings with the SEC, or that we will continue to make similar statements in the same extent or manner in future filings.

In addition, historical, current and forward-looking environmental, social and sustainability-related statements may be based on standards and processes for measuring progress that are still developing and that continue to evolve, and assumptions that are subject to change in the future.

Forward-looking statements include the items identified in the preceding paragraph, the information concerning possible or assumed future results of our operations and other statements contained or incorporated in this Annual Report identified by words such as “anticipate,” “believe,” “continue,” “could,” “estimate,” “expect,” “forecast,” “goal,” “guidance,” “intend,” “may,” “might,” “outlook,” “plan,” “potential,” “project,” “scheduled,” “should,” “target,” “will,” “would,” and other words and terms of similar meaning.

One should not place undue reliance on forward-looking statements.

Known and unknown risks, uncertainties and other factors may cause our actual results, performance or achievements to be materially different from any future results, performance or achievements expressed or implied by forward-looking statements.

Those factors may affect our operations, markets, products, services and prices.

In addition to any assumptions and other factors referred to specifically in connection with the forward-looking statements, factors that could cause our actual results to differ materially from those contemplated in any forward-looking statement include, among others, the following:

• the impact of inflationary pressures, including increased interest rates, which may increase our capital expenditures and operating costs, raise the cost of capital or depress economic growth;

• the impact on drilling and production by factors beyond our control, including the demand for natural gas, NGLs and crude oil;

producers’ desire and ability to drill and obtain necessary permits;

regulatory compliance;

reserve performance;

and capacity constraints and/or shut downs on the pipelines that transport crude oil, natural gas and NGLs from producing areas and our facilities;

• risks associated with adequate supply to our gathering, processing, fractionation and pipeline facilities, including production declines that outpace new drilling, the shutting-in of production by producers, actions taken by federal, state or local governments to require producers to prorate or to cut their production levels as a way to address any excess market supply situations or extended periods of ethane rejection;

• demand for our services and products in the proximity of our facilities;

• economic climate and growth in the geographic areas in which we operate;

• the risk of a slowdown in growth or decline in the United States or international economies, including liquidity risks in United States or foreign credit markets;

• the possibility of future terrorist attacks or the possibility or occurrence of an outbreak of, or changes in, hostilities or changes in the political conditions throughout the world, including the current conflict in Ukraine and the surrounding region;

• performance of contractual obligations by our customers, service providers, contractors and shippers;

• the effects of changes in governmental policies and regulatory actions, including changes with respect to income and other taxes, pipeline safety, environmental compliance, cybersecurity, climate change initiatives, emissions credits, carbon offsets, carbon pricing, production limits and authorized rates of recovery of natural gas and natural gas transportation costs;

• changes in demand for the use of natural gas, NGLs and crude oil because of the development of new technologies or other market conditions caused by concerns about climate change;

• the impact of the transformation to a lower-carbon economy, including the timing and extent of the transformation, as well as the expected role of different energy sources, including natural gas, NGLs and crude oil, in such a transformation;

• the pace of technological advancements and industry innovation, including those focused on reducing GHG emissions and advancing other climate-related initiatives, and our ability to take advantage of those innovations and developments;

• the effectiveness of our risk-management function, including mitigating cyber- and climate-related risks;

• our ability to identify and execute opportunities, and the economic viability of those opportunities, including those relating to renewable natural gas, carbon capture, use and storage, other renewable energy sources such as solar and wind and alternative low carbon fuel sources such as hydrogen;

• the ability of our existing assets and our ability to apply and continue to develop our expertise to support the growth of, and transformation to, various renewable and alternative energy opportunities, including through the positioning and optimization of our assets;

• our ability to efficiently reduce our GHG emissions (both Scope 1 and 2 emissions), including through the use of lower carbon power alternatives, management practices and system optimizations;

• the necessity to focus on maintaining and enhancing our existing assets while reducing our Scope 1 and 2 GHG emissions;

• the effects of weather and other natural phenomena and the effects of climate change (including physical and transformation-related effects) on our operations, demand for our services and commodity prices;

• acts of nature, sabotage, terrorism or other similar acts that cause damage to our facilities or our suppliers’, customers’ or shippers’ facilities;

• the inability of insurance proceeds to cover all liabilities or incurred costs and losses, or lost earnings, resulting from a loss;

• delays in receiving insurance proceeds from covered losses;

• the risk of increased costs for insurance premiums;

• increased costs associated with insurance coverage, security or other items as a consequence of terrorist attacks;

• the timing and extent of changes in energy commodity prices, including changes due to production decisions by other countries, such as the failure of countries to abide by agreements to reduce production volumes;

• competition from other United States and foreign energy suppliers and transporters, as well as alternative forms of energy, including, but not limited to, solar power, wind power, geothermal energy and biofuels such as ethanol and biodiesel;

• the ability to market pipeline capacity on favorable terms, including the effects of:

– future demand for and prices of natural gas, NGLs and crude oil;

– competitive conditions in the overall energy market;

– availability of supplies of United States natural gas and crude oil;

– availability of additional storage capacity;

• the efficiency of our plants in processing natural gas and extracting and fractionating NGLs;

• the composition and quality of the natural gas and NGLs we gather and process in our plants and transport on our pipelines;

• risks of marketing, trading and hedging activities, including the risks of changes in commodity prices or the financial condition of our counterparties;

• our ability to control operating costs and make cost-saving changes;

• the risks inherent in the use of information systems in our respective businesses and those of our counterparties and service providers, including cyber-attacks, which, according to experts, have increased in volume and sophistication since the beginning of the COVID-19 pandemic;

implementation of new software and hardware;

and the impact on the timeliness of information for financial reporting;

• the timely receipt of approval by applicable governmental entities for construction and operation of our pipeline and other projects and required regulatory clearances;

• the ability to recover operating costs and amounts equivalent to income taxes, costs of property, plant and equipment and regulatory assets in our state and FERC-regulated rates;

• the results of governmental actions, administrative proceedings and litigation, regulatory actions, executive orders, rule changes and receipt of expected clearances involving any local, state or federal regulatory body, including the FERC, the National Transportation Safety Board, Homeland Security, the PHMSA, the EPA and the CFTC;

• the mechanical integrity of facilities and pipelines operated;

• the capital-intensive nature of our businesses;

• the impact of unforeseen changes in interest rates, debt and equity markets, inflation rates, economic recession and other external factors over which we have no control, including the effect on pension and postretirement expense and funding resulting from changes in equity and bond market returns;

• actions by rating agencies concerning our credit;

• our indebtedness and guarantee obligations could cause adverse consequences, including making us vulnerable to general adverse economic and industry conditions, limiting our ability to borrow additional funds and placing us at competitive disadvantages compared with our competitors that have less debt;

• our ability to access capital at competitive rates or on terms acceptable to us;

• our ability to acquire all necessary permits, consents or other approvals in a timely manner, to promptly obtain all necessary materials and supplies required for construction, and to construct gathering, processing, fractionation, transportation and storage facilities without labor or contractor problems;

• our ability to control construction costs and completion schedules of our pipelines and other projects;

• difficulties or delays experienced by trucks, railroads or pipelines in delivering products to or from our terminals or pipelines;

• the uncertainty of estimates, including accruals and costs of environmental remediation;

• the impact of uncontracted capacity in our assets being greater or less than expected;

• the impact of potential impairment charges;

• the profitability of assets or businesses acquired or constructed by us;

• the risks associated with pending or possible acquisitions and dispositions, including our ability to finance or integrate any such acquisitions and any regulatory delay or conditions imposed by regulatory bodies in connection with any such acquisitions and dispositions;

• the risk that material weaknesses or significant deficiencies in our internal controls over financial reporting could emerge or that minor problems could become significant;

• the impact and outcome of pending and future litigation;

• the impact of recently issued and future accounting updates and other changes in accounting policies;

• the risk factors listed in the reports we have filed, which are incorporated by reference, and may file with the SEC;

• the length, severity and reemergence of a pandemic or other health crisis, such as the COVID-19 pandemic and the measures taken to address it, which may (as with COVID-19) precipitate or exacerbate one or more of the factors herein, reduce the demand for natural gas, NGLs and crude oil and significantly disrupt or prevent us and our customers and counterparties from operating in the ordinary course of business for an extended period and increase the cost of operating our business.

These factors are not necessarily all of the important factors that could cause actual results to differ materially from those expressed in any of our forward-looking statements.

Other factors could also affect adversely our future results.

These and other risks are described in greater detail in Part I, Item 1A, Risk Factors, in this Annual Report and in our other filings that we make with the SEC, which are available via the SEC’s website at www.sec.gov and our website at www.oneok.com.

All forward-looking statements attributable to us or persons acting on our behalf are expressly qualified in their entirety by these factors.

Any such forward-looking statement speaks only as of the date on which such statement is made, and other than as required under securities laws, we undertake no obligation to update publicly any forward-looking statement whether as a result of new information, subsequent events or change in circumstances, expectations or otherwise.

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

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.

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Item 7. Management’s Discussion and Analysis