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ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion and analysis should be read in conjunction with Part I, Item 1, Business, our audited Consolidated Financial Statements and the Notes to Consolidated Financial Statements in this Annual Report.

RECENT DEVELOPMENTS

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. 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 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.

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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. 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:

Project Scope ApproximateCosts (a) Completion

Natural Gas Gathering and Processing (In millions)

Supported by acreage dedications with primarily fee-based contracts

Natural Gas Liquids

Natural Gas Pipelines

(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. In February 2023, we paid a quarterly common stock dividend of $0.955 per share ($3.82 per share on an annualized basis), an increase of 2% 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

How We Evaluate Our Operations

Management uses a variety of financial and operating metrics to analyze our performance. Our consolidated financial metrics include: (1) operating income; (2) net income; (3) diluted EPS; and (4) adjusted EBITDA. We evaluate segment operating results using adjusted EBITDA and our operating metrics, which include various volume and rate statistics that are relevant for the respective segment. These operating metrics allow investors to analyze the various components of segment financial results in terms of volumes and rate/price. Management uses these metrics to analyze historical segment financial results and as the key inputs for forecasting and budgeting segment financial results. For additional information on our operating metrics, see the respective segment subsections of this “Financial Results and Operating Information” section.

Non-GAAP Financial Measures - Adjusted EBITDA is a non-GAAP measure of our financial performance. Adjusted EBITDA is defined as net income adjusted for interest expense, depreciation and amortization, noncash impairment charges, income taxes, allowance for equity funds used during construction, noncash compensation expense and certain other noncash items. We believe this non-GAAP financial measure is useful to investors because it and similar measures are used by many companies in our industry as a measurement of financial performance and is commonly employed by financial analysts and others to evaluate our financial performance and to compare financial performance among companies in our industry. Adjusted EBITDA should not be considered an alternative to net income, EPS or any other measure of financial performance presented in accordance with GAAP. Additionally, this calculation may not be comparable with similarly titled measures of other companies.

Consolidated Operations

Selected Financial Results - The following table sets forth certain selected financial results for the periods indicated:

(Millions of dollars, except per share amounts)

Revenues

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

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.

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2022 vs. 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; and

•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; offset by

•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; and

•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.

Selected Financial Results and Operating Information for the Year Ended December 31, 2021 vs. 2020 - The consolidated and segment financial results and operating information for the year ended December 31, 2021, compared with the year ended December 31, 2020, are 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.

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.

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:

(Millions of dollars)

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

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

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.

2022 vs. 2021 - Adjusted EBITDA increased $147.5 million, primarily 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; and

•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; offset by

•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 increased due primarily to growth projects, including our Demicks Lake III project.

Years Ended December 31,

Average fee rate ($/MMBtu) $ 1.10 $ 1.04 $ 0.89

(a) - Includes volumes for consolidated entities only.

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

2022 vs. 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.

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

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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.

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

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

(Millions of dollars)

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

See reconciliation of net income to adjusted EBITDA in the “Non-GAAP 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 vs. 2021 - Adjusted EBITDA increased $131.6 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; and

•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; and

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

•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.

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

Years Ended December 31,

(a) - Represents physical raw feed volumes for which we provide transportation and/or fractionation services.

We generally expect ethane volumes to increase or decrease with corresponding increases or decreases in overall NGL production. However, ethane volumes may experience growth or decline greater than corresponding growth or decline in overall NGL production due to ethane economics causing producers to extract or reject ethane.

2022 vs. 2021 - Volumes increased due primarily to increased NGL production in the Rocky Mountain region and Permian Basin, and higher ethane volumes from incentivized ethane recovery in the Rocky Mountain region, offset partially by decreased ethane recovery in the Mid-Continent region due to ethane economics. Volumes also benefited from the unfavorable impact of Winter Storm Uri in the first quarter 2021, offset partially by the impact of winter weather in the Rocky Mountain region in the second and fourth quarters of 2022.

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. 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. 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.

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

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

(Millions of dollars)

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

2022 vs. 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; and

•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;

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•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; and

•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 expenditures increased in 2022 due primarily to capital-growth projects, including the Viking compression project.

Years Ended December 31,

Natural gas transportation capacity contracted (MDth/d) 7,428 7,395 7,461

Transportation capacity contracted 94 % 95 % 96 %

(a) - Includes volumes for consolidated entities only.

In April 2022, the FERC initiated a review of Guardian’s rates pursuant to Section 5 of the Natural Gas Act. In August 2022, Guardian reached a settlement in principle with the participants in the Section 5 rate case. The FERC approved the settlement in February 2023, which will result in a future reduction of rates. We do not expect the reduced rates to have a material impact on our results of operations.

NON-GAAP FINANCIAL MEASURES

The following table sets forth a reconciliation of net income, the nearest comparable GAAP financial performance measure, to adjusted EBITDA for the periods indicated:

Years Ended December 31,

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

Add:

Reconciliation of segment adjusted EBITDA to adjusted EBITDA

Segment adjusted EBITDA:

(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.

CONTINGENCIES

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

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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.

LIQUIDITY AND CAPITAL RESOURCES

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

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. 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 proceeds serve as settlement for property damage, business interruption claims to the date of settlement and as payment in lieu of future business interruption insurance claims. We expect our cash from operations in 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.

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 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 use a centralized cash management program that concentrates the cash assets of our nonguarantor operating subsidiaries in joint accounts for the purposes of providing financial flexibility and lowering the cost of borrowing, transaction costs and bank fees. Our centralized cash management program provides that funds in excess of the daily needs of our operating subsidiaries are concentrated, consolidated or otherwise made available for use by other entities within our consolidated group. Our operating subsidiaries participate in this program to the extent they are permitted pursuant to FERC regulations or their operating agreements. Under the cash management program, depending on whether a participating subsidiary has short-term cash surpluses or cash requirements, we provide cash to the subsidiary or the subsidiary provides cash to us.

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: (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.

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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. 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.

Material Commitments - We have material cash commitments related to our capital expenditures, senior notes and corresponding interest payments, which we expect to fund through our sources of cash inflows discussed above. Our senior notes and interest payments are discussed in Note G of the Notes to Consolidated Financial Statements in this Annual Report. We also have cash commitments related to transportation, storage and other commercial contracts, as well as our financial and physical derivative obligations, which we expect to fund with cash from operations.

Capital Expenditures- We 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. 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:

(Millions of dollars)

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.

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We expect total capital expenditures, excluding AFUDC and capitalized interest, of $1.3-$1.5 billion in 2023.

Credit Ratings - Our long-term debt credit ratings as of February 21, 2023, are shown in the table below:

Rating Agency Long-Term Rating Short-Term Rating Outlook

Moody’s Baa3 Prime-3 Positive

S&P BBB A-2 Stable

Fitch BBB F2 Stable

Our credit ratings, which are investment grade, may be affected by our leverage, liquidity, credit profile or potential transactions. The most common criteria for assessment of our credit ratings are the debt-to-EBITDA ratio, interest coverage, business risk profile and liquidity. If our credit ratings were downgraded, our cost to borrow funds under our $2.5 Billion Credit Agreement could increase and a potential loss of access to the commercial paper market could occur. In the event that we are unable to borrow funds under our commercial paper program and there has not been a material adverse change in our business, we would continue to have access to our $2.5 Billion Credit Agreement, which expires in 2027. An adverse credit rating change alone is not a default under our $2.5 Billion Credit Agreement.

In the normal course of business, our counterparties provide us with secured and unsecured credit. In the event of a downgrade in our credit ratings or a significant change in our counterparties’ evaluation of our creditworthiness, we could be required to provide additional collateral in the form of cash, letters of credit or other negotiable instruments as a condition of continuing to conduct business with such counterparties. We may be required to fund margin requirements with our counterparties with cash, letters of credit or other negotiable instruments.

Dividends - Holders of our common stock share equally in any common stock dividends declared by our Board of Directors, subject to the rights of the holders of outstanding preferred stock. In 2022, we paid common stock dividends of $3.74 per share, which is consistent with prior year. In February 2023, we paid a quarterly common stock dividend of $0.955 per share ($3.82 per share on an annualized basis), an increase of 2% 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 February 2023, 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. We expect our cash flows from operations to continue to sufficiently fund our cash dividends. To the extent operating cash flows are not sufficient to fund our dividends, we may utilize cash on hand from other sources of short- and long-term liquidity to fund a portion of our dividends.

CASH FLOW ANALYSIS

We use the indirect method to prepare our Consolidated Statements of Cash Flows. Under this method, we reconcile net income to cash flows provided by operating activities by adjusting net income for those items that affect net income but do not result in actual cash receipts or payments during the period and for operating cash items that do not impact net income. These reconciling items can include depreciation and amortization, 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.

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

Years Ended December 31,

(Millions of dollars)

Total cash provided by (used in):

Cash and cash equivalents at beginning of period 146.4 524.5 21.0

Cash and cash equivalents at end of period $ 220.2 $ 146.4 $ 524.5

Operating Cash Flows - Operating cash flows are affected by earnings from our business activities and changes in our operating assets and liabilities. Changes in commodity prices and demand for our services or products, whether because of general economic conditions, changes in supply, changes in demand for the end products that are made with our products or increased competition from other service providers, could affect our earnings and operating cash flows. Our operating cash flows can also be impacted by changes in our NGLs and natural gas inventory balances, which are driven primarily by commodity prices, supply, demand and the operation of our assets.

2022 vs. 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.”

The changes in operating assets and liabilities increased operating cash flows $3.4 million for the year ended December 31, 2022, compared with a decrease of $141.8 million for the same period in 2021. 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.

Investing Cash Flows

2022 vs. 2021 - Cash used in investing activities increased $474.0 million due primarily to capital expenditures related to our capital-growth projects.

Financing Cash Flows

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

Cash Flow Analysis for the Year Ended December 31, 2021 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.

IMPACT OF NEW ACCOUNTING STANDARDS

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

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CRITICAL ACCOUNTING POLICIES AND 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. These estimates and assumptions also affect the reported amounts of revenue and expenses during the reporting period. 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.

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. The accounting for changes in the fair value of a derivative instrument depends on whether it qualifies and has been designated as part of a hedging relationship. When possible, we implement effective hedging strategies using derivative financial instruments that qualify as hedges for accounting purposes. We have not used derivative instruments for trading purposes. 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 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. 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. If further testing is necessary or a quantitative test is elected, we perform a Step 1 analysis for goodwill impairment.

In a Step 1 analysis, an assessment is made by comparing the fair value of a reporting unit with its carrying amount, including goodwill. If the carrying value of a reporting unit exceeds its fair value, an impairment loss is recognized in an amount equal to that excess, limited to the total amount of goodwill allocated to that reporting unit.

We assess our long-lived assets, including intangible assets, for impairment whenever events or changes in circumstances indicate that an asset’s carrying amount may not be recoverable. An impairment is indicated if the carrying amount of a long-lived asset exceeds the sum of the undiscounted future cash flows expected to result from the use and eventual disposition of the asset. 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.

Our impairment tests require the use of assumptions and estimates, such as industry economic factors and the profitability of future business strategies. To estimate undiscounted future cash flows of long-lived assets, we may apply a probability-weighted approach that incorporates different assumptions and potential outcomes related to the underlying long-lived assets. The evaluation is performed at the lowest level for which separately identifiable cash flows exist. To estimate the fair value of

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these assets, we use two generally accepted valuation approaches, an income approach and a market approach. Under the income approach, our discounted cash flow analysis includes the following inputs that are not readily available: a discount rate reflective of industry cost of capital, our estimated contract rates, volumes, operating margins, operating and maintenance costs and capital expenditures. Under the market approach, our inputs include EBITDA multiples, which are estimated from recent peer acquisition transactions, and forecasted EBITDA, which incorporates inputs similar to those used under the income approach. If actual results are not consistent with our assumptions and estimates or our assumptions and estimates change due to new information, we may be exposed to future impairment charges.

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

Depreciation Methods and Estimated Useful Lives of Property, Plant and Equipment - Our property, plant and equipment are depreciated using the straight-line method that incorporates management assumptions regarding useful economic lives and residual values. As we place additional assets in service, our estimates related to depreciation expense have become more significant and changes in estimated useful lives of our assets could have a material effect on our results of operations. At the time we place our assets in service, we believe such assumptions are reasonable; however, circumstances may develop that would cause us to change these assumptions, which would change our depreciation expense prospectively. Examples of such circumstances include changes in (i) competition, (ii) laws and regulations that limit the estimated economic life of an asset, (iii) technology that render an asset obsolete, (iv) expected salvage values, (v) results of rate cases or rate settlements on regulated assets and (vi) forecasts of the remaining economic life for the resource basins where our assets are located, if any. For the fiscal years presented in this Form 10-K, no changes were made to the determinations of useful lives that would have a material effect on the timing of depreciation expense in future periods.

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.

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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;

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•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; and

– 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; and

•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.

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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.

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Our exposure to market risk discussed below includes forward-looking statements and represents an estimate of possible changes in future earnings that could occur assuming hypothetical future movements in interest rates or commodity prices. Our views on market risk are not necessarily indicative of actual results that may occur and do not represent the maximum possible gains and losses that may occur since actual gains and losses will differ from those estimated based on actual fluctuations in interest rates or commodity prices and the timing of transactions.

We are exposed to market risk due to commodity price and interest-rate volatility. Market risk is the risk of loss arising from adverse changes in market rates and prices. We may use financial instruments, including forward sales, swaps, options and futures, to manage the risks of certain identifiable or anticipated transactions and achieve more predictable cash flows. Our risk-management function follows policies and procedures established by our Risk Oversight and Strategy Committee to monitor our natural gas, condensate and NGL marketing activities and interest rates to ensure our hedging activities mitigate market risks and comply with approved thresholds or limits. We do not use financial instruments for trading purposes.

We utilize a sensitivity analysis model to assess the risk associated with our derivative portfolio. The sensitivity analysis measures the potential change in fair value of our derivative instruments based upon a hypothetical 10% movement in the underlying commodity prices or interest rates. In addition to these variables, the fair value of our derivative portfolio is influenced by fluctuations in the notional amounts of the instruments and the discount rates used to determine the present values. Because we enter into these derivative instruments for the purpose of mitigating the risks that accompany certain of our business activities, as described below, the change in the market value of our derivative portfolio would typically be offset largely by a corresponding gain or loss on the hedged item.

See Note Aof the Notes to Consolidated Financial Statements in this Annual Report for discussion on our accounting policies for our derivative instruments and the impact on our Consolidated Financial Statements.

COMMODITY PRICE RISK

As part of our hedging strategy, we use commodity derivative financial instruments and physical-forward contracts described in Note D of the Notes to Consolidated Financial Statements in this Annual Report to reduce the impact of near-term price fluctuations of natural gas, NGLs and condensate.

Although our businesses are primarily fee-based, in our Natural Gas Gathering and Processing segment, we are exposed to commodity price risk as a result of retaining a portion of the commodity sales proceeds associated with our fee with POP contracts. Under certain fee with POP contracts, our contractual fees and POP percentage may increase or decrease if production volumes, delivery pressures or commodity prices change relative to specified thresholds. We are exposed to basis risk between the various production and market locations where we buy and sell commodities.

The following table presents the effect a hypothetical 10% change in the underlying commodity prices would have on the estimated fair value of our commodity derivative instruments as of the dates indicated:

(Millions of dollars)

Crude oil and NGLs $ 34.6 $ 40.6

Total change in estimated fair value of commodity contracts $ 52.6 $ 52.1

Our sensitivity analysis represents an estimate of the reasonably possible gains and losses that would be recognized on our commodity derivative contracts assuming hypothetical movements in future market prices and is not necessarily indicative of

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actual results that may occur. Actual gains and losses may differ from estimates due to actual fluctuations in market prices, as well as changes in our commodity derivative portfolio during the year.

The following tables set forth hedging information for our Natural Gas Gathering and Processing segment’s forecasted equity volumes for the period indicated:

VolumesHedged Average Price PercentageHedged

NGLs - excluding ethane (MBbl/d) - Conway/Mont Belvieu 10.7 $ 1.23 / gallon 67%

Condensate (MBbl/d) - WTI-NYMEX 1.7 $ 85.48 / Bbl 67%

Natural gas (BBtu/d) - NYMEX and basis 99.2 $ 3.50 / MMBtu 75%

VolumesHedged Average Price PercentageHedged

Natural gas (BBtu/d) - NYMEX and basis 16.2 $ 7.18 / MMBtu 11%

Our Natural Gas Gathering and Processing segment’s commodity price sensitivity is estimated as a hypothetical change in the price of NGLs, crude oil and natural gas at December 31, 2022. Condensate sales are typically based on the price of crude oil. Assuming normal operating conditions, we estimate the following for our forecasted equity volumes:

•a $0.01 per gallon change in the composite price of NGLs, excluding ethane, would change adjusted EBITDA for the years ending December 31, 2023 and 2024, by $2.5 million and $2.6 million, respectively;

•a $1.00 per barrel change in the price of crude oil would change adjusted EBITDA for the years ending December 31, 2023 and 2024, by $0.9 million and $1.0 million, respectively; and

•a $0.10 per MMBtu change in the price of residue natural gas would change adjusted EBITDA for the years ending December 31, 2023 and 2024, by $4.8 million and $5.2 million, respectively.

These estimates do not include any effects of hedging or effects on demand for our services or natural gas processing plant operations that might be caused by, or arise in conjunction with, commodity price fluctuations. For example, a change in the gross processing spread may cause a change in the amount of ethane extracted from the natural gas stream, impacting gathering and processing financial results for certain contracts.

INTEREST-RATE RISK

We are exposed to interest-rate risk through borrowings under our $2.5 Billion Credit Agreement, commercial paper program and long-term debt issuances. Future increases in commercial paper rates or bond rates could expose us to increased interest costs on future borrowings. We may manage interest-rate risk through the use of fixed-rate debt, floating-rate debt and interest-rate swaps. Interest-rate swaps are agreements to exchange interest payments at some future point based on specified notional amounts.

In 2022, we settled $750 million of our forward-starting interest-rate swaps related to our underwritten public offering of $750 million senior unsecured notes, resulting in a gain of $28.1 million, which is included in accumulated other comprehensive loss and amortized into interest expense over the term of the related debt. In December 2022, we terminated the remaining $375 million of our forward-starting interest swaps that had mandatory termination dates of December 31, 2022. We simultaneously entered into forward-starting interest-rate swaps with the same notional amounts at current market rates to hedge the variability of interest payments on a portion of our forecasted debt issuances that may result from changes in the benchmark interest rate before the debt is issued.

At December 31, 2022, and December 31, 2021, we had forward-starting interest-rate swaps with notional amounts totaling $0.4 billion and $1.1 billion, respectively, to hedge the variability of interest payments on a portion of our forecasted debt issuances. All of our interest-rate swaps are designated as cash flow hedges. At December 31, 2022 and 2021, we had derivative assets of $10.9 million and derivative liabilities of $145.5 million, respectively, related to these interest-rate swaps.

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The following table presents the effect of a 10% hypothetical change in interest rates on the estimated fair value of our interest-rate derivative instruments as of the dates indicated:

(Millions of dollars)

Forward-starting interest-rate swaps $ 13.0 $ 19.6

Our sensitivity analysis represents an estimate of the reasonably possible gains and losses that would be recognized on our interest-rate derivative contracts assuming hypothetical movements in future interest rates and is not necessarily indicative of actual results that may occur. Actual gains and losses may differ from estimates due to actual fluctuations in interest rates, as well as changes in our interest-rate derivative portfolio during the year.

See Note D of the Notes to Consolidated Financial Statements in this Annual Report for more information on our hedging activities.

COUNTERPARTY CREDIT RISK

We assess the creditworthiness of our counterparties on an ongoing basis and require security, including prepayments and other forms of collateral, when appropriate. Certain of our counterparties may be impacted by a relatively low commodity price environment and could experience financial problems, which could result in nonpayment and/or nonperformance, which could impact adversely our results of operations.

Natural Gas Gathering and Processing - Our Natural Gas Gathering and Processing segment derives services revenue primarily from major and independent crude oil and natural gas producers, which include both large integrated and independent exploration and production companies. In this segment, our downstream commodity sales customers are primarily utilities, large industrial companies, marketing companies and our NGL affiliate. We are not typically exposed to material credit risk with producers under fee with POP contracts as we sell the commodities and remit a portion of the sales proceeds back to the producer less our contractual fees. In 2022 and 2021, approximately 95% and 90%, respectively, of the downstream commodity sales in our Natural Gas Gathering and Processing segment were made to customers rated investment-grade by S&P, approved through comparable internal counterparty analysis, or were secured by letters of credit or other collateral.

Natural Gas Liquids - Our Natural Gas Liquids segment’s counterparties are primarily NGL and natural gas gathering and processing companies; major and independent crude oil and natural gas production companies; utilities; large industrial companies; natural gasoline distributors; propane distributors; municipalities; and petrochemical, refining and marketing companies. We charge fees to NGL and natural gas gathering and processing counterparties and NGL pipeline transportation customers. We are not typically exposed to material credit risk on the majority of our exchange services fees, as we purchase NGLs from our gathering and processing counterparties and deduct our fee from the amounts we remit. We also earn sales revenue on the downstream sales of purity NGLs. In 2022 and 2021, approximately 85% and 70%, respectively, of this segment’s commodity sales were made to customers rated investment-grade by S&P, approved through comparable internal counterparty analysis, or were secured by letters of credit or other collateral. In addition, the majority of our Natural Gas Liquids segment’s pipeline tariffs provide us the ability to require security from shippers.

Natural Gas Pipelines - Our Natural Gas Pipelines segment’s customers are primarily local natural gas distribution companies, electric-generation facilities, large industrial companies, municipalities, producers, processors and marketing companies. In 2022 and 2021, approximately 90% and 85%, respectively, of our revenues in this segment were from customers rated investment-grade by S&P, approved through comparable internal counterparty analysis, or were secured by letters of credit or other collateral. In addition, the majority of our Natural Gas Pipelines segment’s pipeline tariffs provide us the ability to require security from shippers.

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

Report of Independent Registered Public Accounting Firm

To theBoard of Directors and Shareholders of ONEOK, Inc.

Opinions on the Financial Statements and Internal Control over Financial Reporting

We have audited the accompanying consolidated balance sheets of ONEOK, Inc.and its subsidiaries(the “Company”) as of December 31, 2022 and 2021, and the related consolidated statements of income, of comprehensive income, of changes in equity and of cash flowsfor each of the three years in the period ended December 31, 2022, including the related notes (collectively referred to as the “consolidated financial statements”).We also have audited the Company's internal control over financial reporting as of December 31, 2022, based on criteria established in Internal Control - Integrated Framework(2013)issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).

In our opinion, the consolidatedfinancial statements referred to above present fairly, in all material respects, the financial position of the Company as of December 31, 2022 and 2021, and the results of itsoperations and itscash flows for each of the three years in the period ended December 31, 2022, in conformity with accounting principles generally accepted in the United States of America. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2022, based on criteria established in Internal Control - Integrated Framework(2013)issued by the COSO.

Basis for Opinions

The Company's management is responsible for these consolidated financial statements, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in Management's Report on Internal Control Over Financial Reporting appearing under Item 9A. Our responsibility is to express opinions on the Company’s consolidatedfinancial statements and on the Company's internal control over financial reporting based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the consolidatedfinancial statements are free of material misstatement, whether due to error or fraud, and whether effective internal control over financial reporting was maintained in all material respects.

Our audits of the consolidated financial statements included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidatedfinancial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidatedfinancial statements. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.

Definition and Limitations of Internal Control over Financial Reporting

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

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Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

Critical Audit Matters

The critical audit matter communicated below is a matterarising from the current period audit of the consolidated financial statements that was communicated or required to be communicated to the audit committee and that (i) relates to accounts or disclosures that are material to the consolidated financial statements and (ii) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the consolidatedfinancial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.

Accounting for the Medford Incident

As described in Note B to the consolidated financial statements, on July 9, 2022, a fire occurred at the Company’s 210 MBbl/d Medford, Oklahoma, natural gas liquids fractionation facility. The Company has property damage and business interruption coverage against which they developed claims related to the Medford incident and recorded accruals for the expected insurance recoveries. Management records recoveries for incurred costs and lost earnings related to its business interruption coverage for the amount probable of recovery, not to exceed the actual losses incurred, and for lost earnings that have been realized and are no longer considered a gain contingency. Management assessed property damage to the facility and incurred costs and lost earnings related to business interruption, as well as timing of recognition under applicable insurance recovery guidance, and recorded accruals of $150.7 million for the year ended December 31, 2022, which was comprised of property damage of $45.6 million, with a corresponding write off of assets due to property damage of the facility; $9 million related to incurred costs in excess of the deductible that were probable of recovery, with an offset to the operating and maintenance line item; and $96.1 million primarily related to third-party fractionation costs incurred subsequent to the 45-day business interruption waiting period, with an offset to other operating (income) expense. The Company received a $100 million unallocated payment from the insurers in the fourth quarter of 2022, and had recorded an outstanding insurance receivable of $50.7 million as of December 31, 2022.

The principal considerations for our determination that performing procedures relating to the accounting for the Medford incident is a critical audit matter are (i) the significant judgment by management when assessing the application of accounting guidance for business interruption and the resulting recognition of incurred costs and lost earnings; (ii) a high degree of auditor judgment, subjectivity, and effort in performing procedures and evaluating management’s assessment of the application of accounting guidance for business interruption and the resulting recognition of incurred costs and lost earnings.

Addressing the matter involved performing procedures and evaluating audit evidence in connection with forming our overall opinion on the consolidated financial statements. These procedures included testing the effectiveness of controls relating to the application of accounting guidance for business interruption and recognition of the incurred costs and lost earnings. These procedures also included, among others, (i) reading the related customer contracts to assess lost earnings; (ii) evaluating management’s assessment of the incurred costs and lost earnings, including their assessment of the application of the appropriate accounting guidance for business interruption; (iii) testing the incurred costs, lost earnings, and related recovery, which included testing the appropriate presentation within the financial statements; and (iv) tracing the insurance payments received to the Company’s general ledger.

/s/ PricewaterhouseCoopers LLP

Tulsa, Oklahoma

February 28, 2023

We have served as the Company’s auditor since 2007.

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ONEOK, Inc. and Subsidiaries

CONSOLIDATED STATEMENTS OF INCOME

Years Ended December 31,

(Thousands of dollars, except per share amounts)

Revenues

Impairment charges (Notes E and F) — — 607,200

Other operating (income) expense, net (Note B) (106,229) (1,394) (1,327)

Impairment of equity investments (Note N) — — (37,730)

Allowance for equity funds used during construction 2,551 1,682 23,662

Average shares (thousands)

See accompanying Notes to Consolidated Financial Statements.

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ONEOK, Inc. and Subsidiaries

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

Years Ended December 31,

(Thousands of dollars)

Other comprehensive income (loss), net of tax

See accompanying Notes to Consolidated Financial Statements.

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ONEOK, Inc. and Subsidiaries

CONSOLIDATED BALANCE SHEETS

December 31, December 31,

Assets (Thousands of dollars)

Current assets

Property, plant and equipment

Investments and other assets

Investments in unconsolidated affiliates (Note N) 801,794 797,613

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ONEOK, Inc. and Subsidiaries

CONSOLIDATED BALANCE SHEETS

(Continued)

December 31, December 31,

Liabilities and equity (Thousands of dollars)

Current liabilities

Current maturities of long-term debt (Note G) $ 925,000 $ 895,814

Deferred credits and other liabilities

Commitments and contingencies (Note O)

Equity (Note H)

ONEOK shareholders’ equity:

Accumulated other comprehensive loss (Note I) (108,256) (471,351)

Retained earnings 50,396 —

See accompanying Notes to Consolidated Financial Statements.

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ONEOK, Inc. and Subsidiaries

CONSOLIDATED STATEMENTS OF CASH FLOWS

Years Ended December 31,

(Thousands of dollars)

Operating activities

Changes in assets and liabilities:

Investing activities

Financing activities

Borrowing (repayment) of short-term borrowings, net — — (220,000)

Supplemental cash flow information:

Cash paid for income taxes, net of refunds $ 58,935 $ 8,864 $ 342

See accompanying Notes to Consolidated Financial Statements.

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ONEOK, Inc. and Subsidiaries

CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY

(Shares) (Thousands of dollars)

Net income — — — — —

Other comprehensive loss — — — — —

Preferred stock dividends - $55.00 per share (Note H) — — — — (550)

Common stock dividends - $3.74 per share (Note H) — — — — (992,741)

Other, net — — — — 8,319

Net income — — — — —

Other comprehensive income (Note I) — — — — —

Preferred stock dividends - $55.00 per share (Note H) — — — — —

Common stock issued — — — — 6,680

Common stock dividends - $3.74 per share (Note H) — — — — (168,145)

Net income — — — — —

Other comprehensive income (Note I) — — — — —

Preferred stock dividends - $55.00 per share (Note H) — — — — —

Common stock issued — — — — 12,716

Common stock dividends - $3.74 per share (Note H) — — — — —

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ONEOK, Inc. and Subsidiaries

CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY

(Continued)

AccumulatedOtherComprehensiveLoss RetainedEarnings TreasuryStock TotalEquity

(Thousands of dollars)

Preferred stock dividends - $55.00 per share (Note H) — (550) — (1,100)

Other, net — — — 8,319

Other comprehensive income (Note I) 80,098 — — 80,098

Preferred stock dividends - $55.00 per share (Note H) — (1,100) — (1,100)

Preferred stock dividends - $55.00 per share (Note H) — (1,100) — (1,100)

See accompanying Notes to Consolidated Financial Statements.

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ONEOK, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

A. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Organization and Nature of Operations - We are a corporation incorporated under the laws of the state of Oklahoma.

Our Natural Gas Gathering and Processing segment provides midstream services to producers in North Dakota, Montana, Wyoming, Kansas and Oklahoma. Raw natural gas is typically gathered at the wellhead, compressed and transported through pipelines to our processing facilities. Processed natural gas, usually referred to as residue natural gas, is then recompressed and delivered to natural gas pipelines, storage facilities and end users. The NGLs separated from the raw natural gas are sold and delivered through NGL pipelines to fractionation facilities for further processing.

Our Natural Gas Liquids segment owns and operates facilities that gather, fractionate, treat and distribute NGLs and store purity NGLs, primarily in Oklahoma, Kansas, Texas, New Mexico and the Rocky Mountain region, which includes the Williston, Powder River and DJ Basins. We provide midstream services to producers of NGLs and deliver those products to the two primary market centers, one in the Mid-Continent in Conway, Kansas, and the other in the Gulf Coast in Mont Belvieu, Texas. We own or have an ownership interest in FERC-regulated NGL gathering and distribution pipelines in Oklahoma, Kansas, Texas, New Mexico, Montana, North Dakota, Wyoming and Colorado, and terminal and storage facilities in Kansas, Nebraska, Iowa and Illinois. We have a 50% ownership interest in Overland Pass, which operates an interstate NGL pipeline originating in Wyoming and Colorado and terminating in Kansas. The majority of the pipeline-connected natural gas processing plants in the Williston Basin, Oklahoma, Kansas and the Texas Panhandle are connected to our NGL gathering systems. We lease rail cars and own and operate truck- and rail-loading and -unloading facilities connected to our NGL fractionation, storage and pipeline assets. We also own FERC-regulated NGL distribution pipelines in Kansas, Missouri, Nebraska, Iowa, Illinois and Indiana that connect our Mid-Continent assets with Midwest markets, including Chicago, Illinois. A portion of our ONEOK North System transports refined petroleum products, including unleaded gasoline and diesel, from Kansas to Iowa.

Our Natural Gas Pipelines segment, through its wholly owned assets primarily in Oklahoma, Texas and the upper Midwest, provides transportation and storage services to end users, such as natural gas distribution and electric-generation companies that require natural gas to operate their businesses regardless of location price differentials. We have 50% ownership interests in Northern Border and Roadrunner, which provide transportation services to various end users. Our assets are connected to key supply areas and demand centers, including supply areas in Canada and the United States via our intrastate and interstate natural gas pipelines and Northern Border, and export markets in Mexico via Roadrunner which enable us to provide essential natural gas transportation and storage services.

Consolidation - Our Consolidated Financial Statements include our accounts and the accounts of our subsidiaries over which we have control or are the primary beneficiary. All intercompany balances and transactions have been eliminated in consolidation.

Investments in unconsolidated affiliates are accounted for using the equity method if we have the ability to exercise significant influence over operating and financial policies of our investee. Under this method, an investment is carried at its acquisition cost and adjusted each period for contributions made, distributions received and our share of the investee’s comprehensive income. For the investments we account for under the equity method, the premium or excess cost over the fair value of the underlying net assets is referred to as equity-method goodwill. Impairment of equity investments is recorded when the impairments are other than temporary. These amounts are recorded as investments in unconsolidated affiliates on our accompanying Consolidated Balance Sheets. See Note N for disclosures of our unconsolidated affiliates.

Distributions paid to us from our unconsolidated affiliates are classified as operating activities on our Consolidated Statements of Cash Flows until the cumulative distributions exceed our proportionate share of income from the unconsolidated affiliate since the date of our initial investment. The amount of cumulative distributions paid to us that exceeds our cumulative proportionate share of income in each period represents a return of investment and is classified as an investing activity on our Consolidated Statements of Cash Flows.

Use of 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 on our Consolidated Financial Statements. Items that may be estimated include, but are not limited to, the economic useful life of assets, fair value of assets, liabilities and equity-method investments, obligations under employee benefit plans, allowance for credit losses, expenses for services received but for which no invoice has been received, provision for income taxes, including any deferred tax valuation allowances, the results of litigation and various other recorded or

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disclosed amounts. In addition, a portion of our revenues and cost of sales and fuel are recorded based on current month prices and estimated volumes. The estimates are reversed in the following month when we record actual volumes.

We evaluate our estimates on an ongoing basis using historical experience, consultation with experts and other methods we consider reasonable based on the particular circumstances. Nevertheless, actual results may differ significantly from the estimates. Any effects on our financial position or results of operations from revisions to these estimates are recorded in the period when the facts that give rise to the revision become known.

Fair Value Measurements - For our fair value measurements, we utilize market prices, third-party pricing services, present value methods and standard option valuation models to determine the price we would receive from the sale of an asset or the transfer of a liability in an orderly transaction at the measurement date. We measure the fair value of a group of financial assets and liabilities consistent with how a market participant would price the net risk exposure at the measurement date.

Most of the contracts in our derivative portfolio are executed in liquid markets where price transparency exists. Our financial commodity derivatives are generally settled through a NYMEX or ICE clearing broker account with daily margin requirements. We validate our valuation inputs with third-party information and settlement prices from other sources, where available.

We compute the fair value of our derivative portfolio by discounting the projected future cash flows from our derivative assets and liabilities to present value using interest-rate yields to calculate present-value discount factors derived from the implied forward SOFR yield curve. The fair value of our forward-starting interest-rate swaps is determined using financial models that incorporate the implied forward SOFR yield curve for the same period as the future interest-rate swap settlements. We consider current market data in evaluating counterparties’, as well as our own, nonperformance risk, net of collateral, by using counterparty-specific bond yields. Although we use our best estimates to determine the fair value of the derivative contracts we have executed, the ultimate market prices realized could differ materially from our estimates.

Fair Value Hierarchy - At each balance sheet date, we utilize a fair value hierarchy to classify fair value amounts recognized or disclosed in our financial statements based on the observability of inputs used to estimate such fair value. The levels of the hierarchy are described below:

•Level 1 - fair value measurements are based on unadjusted quoted prices for identical securities in active markets. These balances are composed predominantly of exchange-traded derivative contracts for natural gas and crude oil.

•Level 2 - fair value measurements are based on significant observable pricing inputs, including quoted prices for similar assets and liabilities in active markets and inputs from third-party pricing services supported with corroborative evidence. These balances are composed of exchange cleared and over-the-counter derivatives to hedge natural gas basis and NGL price risk and over-the-counter interest-rate derivatives.

•Level 3 - fair value measurements are based on inputs that may include one or more unobservable inputs.

Determining the appropriate classification of our fair value measurements within the fair value hierarchy requires management’s judgment regarding the degree to which market data is observable or corroborated by observable market data. We categorize derivatives based on the lowest level input that is significant to the fair value measurement in its entirety.

See Note C for our fair value measurements disclosures.

Cash and Cash Equivalents - Cash equivalents consist of highly liquid investments, which are readily convertible into cash and have original maturities of three months or less.

Revenue Recognition - Revenues are recognized when control of the promised goods or services is transferred to our customers in an amount that reflects the consideration we expect to be entitled to receive in exchange for those goods or services. Our payment terms vary by customer and contract type, including requiring payment before products or services are delivered to certain customers. However, the term between customer prepayments, completion of our performance obligations, invoicing and receipt of payment due is not significant.

Performance Obligations and Revenue Sources - Revenue sources are disaggregated in Note R and are derived from commodity sales and services revenues, as described below:

Commodity Sales(all segments) - We contract to deliver residue natural gas, condensate, unfractionated NGLs and/or purity NGLs to customers at a specified delivery point. Our sales agreements may be daily or longer-term contracts for a specified volume. We consider the sale and delivery of each unit of a commodity an individual performance obligation as the customer is expected to control, accept and benefit from each unit individually. We record revenue when the commodity is delivered tothe

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customer as this represents the point in time when control of the product is transferred to the customer. Revenue is recorded based on the contracted selling price, which is generally index-based and settled monthly. Occasionally, we sell unfractionated NGLs to customers at an index-based price less third-party fractionation costs. These costs are included as a reduction to commodity sales revenue. The third-party fractionation costs we incurred associated with the Medford incident (Note B) were primarily under this type of agreement.

Services

Gathering only contracts (Natural Gas Gathering and Processing segment) - Under this type of contract, we charge fees for providing midstream services, which include gathering and treating our customer’s natural gas. Our performance obligation begins with delivery of raw natural gas to our system. This service is treated as one performance obligation that is satisfied over time. We use the output method based on delivery of product to our system as the measure of progress, as our services are performed simultaneously.

Fee with POP contracts with producer take-in-kind rights (Natural Gas Gathering and Processing segment) - Under this type of contract, we do not control the stream of unprocessed natural gas that we receive at the wellhead due to the producer’s take-in-kind rights. We purchase a portion of the raw natural gas stream, charge fees for providing midstream services, which include gathering, treating, compressing and processing our customer’s natural gas. After performing these services, we return primarily the residue natural gas to the producer, sell the remaining commodities and remit a portion of the commodity sales proceeds to the producer less our contractual fees. Our performance obligation begins with delivery of raw natural gas to our system. This service is treated as one performance obligation that is satisfied over time. We use the output method based on delivery of product to our system as the measure of progress, as our services are performed simultaneously.

Transportation and exchange contracts (Natural Gas Liquids segment) - Under this type of contract, we charge fees for providing midstream services, which may include a bundled combination of gathering, transporting and/or fractionation of our customer’s NGLs. Our performance obligation begins with delivery of unfractionated NGLs or purity NGLs to our system. These services represent a series of distinct services that are treated as one performance obligation that is satisfied over time. We use the output method based on delivery of product to our system as the measure of progress, as our services are performed simultaneously. For transportation services under a tariff on our NGL transportation pipelines, fees are recorded upon redelivery to our customer at the completion of the transportation services.

Storage contracts (Natural Gas Liquids and Natural Gas Pipelines segments) - We reserve a stated storage capacity and inject/withdraw/store commodities for our customer. The capacity reservation and injection/withdrawal/storage services are considered a bundled service, as we integrate them into one stand-ready obligation provided on a daily basis over the life of the agreement and satisfied over time. Fixed capacity reservation fees are allocated and evenly recognized in revenue. Capacity reservation fees that vary based on a stated or implied economic index and correspond with the costs to provide our services are recognized in revenue as invoiced to our customers. For contracts that do not include a capacity reservation, transportation, injection and withdrawal fees are recognized in revenue as those services are provided and are dependent on the volume transported, injected or withdrawn by our customer, which is at our customer’s discretion. We use the output method based on the passage of time to measure satisfaction of the performance obligation associated with our daily stand-ready services.

Firm service transportation contracts (Natural Gas Pipelines segment) - We reserve a stated transportation capacity and transport commodities for our customer. The capacity reservation and transportation services are considered a bundled service, as we integrate them into one stand-ready obligation provided on a daily basis over the life of the agreement and satisfied over time. Fixed capacity reservation fees are allocated and evenly recognized in revenue. Capacity reservation fees that vary based on a stated or implied economic index and correspond with the costs to provide our services are recognized in revenue based on a daily effective fee rate. If the capacity reservation fees vary solely as a contract feature, contract assets or liabilities are recorded for the difference between the amount recorded in revenue and the amount billed to the customer. Transportation fees are recognized in revenue as those services are provided and are dependent on the volume transported by our customer, which is at our customer’s discretion. We use the output method based on the passage of time to measure satisfaction of the performance obligation associated with our daily stand-ready services.

Interruptible transportation contracts (Natural Gas Pipelines segment) - We agree to transport natural gas on our pipelines between the customer’s specified nominated-receipt and delivery points if capacity is available after satisfying firm transportation service obligations. The transaction price is based on the transportation fees times the volumes transported. We use the output method based on delivery of product to the customer to measure satisfaction of the performance obligation. The total consideration for delivered volumes is recorded in revenue at the time of delivery, when the customer obtains control.

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Many of the contract types described above contain additional fees or charges payable by customers for nonperformance (e.g., minimum volume commitments or product specifications), which are considered to be variable consideration. These fees and charges are not recorded until it is probable that a significant reversal of the associated revenue will not occur.

See Note Q for our revenue disclosures.

Contract Assets and Contract Liabilities - Contract assets and contract liabilities are recorded when the amount of revenue recognized from a contract with a customer differs from the amount billed to the customer and recorded in accounts receivable. Our contract asset balances at the beginning and end of the period primarily relate to our firm service transportation contracts with tiered rates. Our contract liabilities primarily represent deferred revenue on NGL storage contracts for which revenue is recognized over a one-year term, and deferred revenue on contributions in aid of construction received from customers for which revenue is recognized over the contract periods, which range from 5 to 10 years.

Cost of Sales and Fuel - Cost of sales and fuel primarily includes (i) the cost of purchased commodities, including NGLs, natural gas and condensate, (ii) fees incurred for third-party transportation, fractionation and storage of commodities, (iii) fuel and power costs incurred to operate our own facilities that gather, process, transport and store commodities, and (iv) an offset from the contractual fees deducted from the cost of purchased commodities under the contract types below:

Fee with POP contracts with no producer take-in-kind rights (Natural Gas Gathering and Processing segment) - We purchase raw natural gas and charge contractual fees for providing midstream services, which include gathering, treating, compressing and processing the producer’s natural gas. After performing these services, we sell the commodities and return a portion of the commodity sales proceeds to the producer less our contractual fees.

Purchase with fee (Natural Gas Liquids segment) - Under this type of contract, we purchase raw, unfractionated NGLs at an index price and charge fees for providing midstream services, which may include a bundled combination of gathering, transporting and/or fractionation.

Operations and Maintenance - Operations and maintenance primarily includes (i) payroll and benefit costs, (ii) third-party costs for operations, maintenance and integrity management, regulatory compliance and environmental and safety, and (iii) other business-related service costs.

Accounts Receivable - Accounts receivable represent valid claims against nonaffiliated customers for products sold or services rendered. We present accounts receivable net of an allowance for credit losses to reflect the net amount expected to be collected. We assess the creditworthiness of our counterparties on an ongoing basis and require security, including prepayments and other forms of collateral, when appropriate. Outstanding customer receivables are reviewed regularly for possible nonpayment indicators, and allowances for credit losses are recorded based upon management’s estimate of collectability, current conditions and supportable forecasts at each balance sheet date. At December 31, 2022, our allowance for credit losses was not material.

Inventory - The values of current NGLs and natural gas in storage are determined using the lower of weighted-average cost or net realizable value. Noncurrent NGLs and natural gas are classified as property and valued at cost. Materials and supplies are valued at average cost. Certain large equipment inventory, which will ultimately be included in property, plant and equipment when utilized, is included in other assets in our Consolidated Balance Sheets and is valued at weighted-average cost.

Commodity Imbalances - Commodity imbalances represent amounts payable or receivable for NGL exchange contracts and natural gas pipeline imbalances and are valued at market prices. Under the majority of our NGL exchange agreements, we physically receive volumes of unfractionated NGLs, including the risk of loss and legal title to such volumes, from the exchange counterparty. In turn, we deliver purity NGLs back to the customer and charge them gathering, transportation and fractionation fees. To the extent that the volumes we receive under such agreements differ from those we deliver, we record a net exchange receivable or payable position with the counterparties. These net exchange receivables and payables are generally settled with movements of purity NGLs rather than with cash. Natural gas pipeline imbalances are settled in cash or in-kind, subject to the terms of the pipelines’ tariffs or by agreement.

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Derivatives and Risk Management - We utilize derivatives to reduce our market-risk exposure to commodity price and interest-rate fluctuations and to achieve more predictable cash flows. We record all derivative instruments at fair value, with the exception of normal purchases and normal sales transactions that are expected to result in physical delivery. Commodity price and interest-rate volatility may have a significant impact on the fair value of derivative instruments as of a given date. The accounting for changes in the fair value of a derivative instrument depends on whether it has been designated and qualifies as part of a hedging relationship and, if so, the reason for holding it. The table below summarizes the various ways in which we account for our derivative instruments and the impact on our Consolidated Financial Statements:

Recognition and Measurement

Accounting Treatment Balance Sheet Income Statement

To reduce our exposure to fluctuations in natural gas, NGLs and condensate prices, we periodically enter into futures, forward purchases and sales, options or swap transactions in order to hedge anticipated purchases and sales of natural gas, NGLs and condensate. Interest-rate swaps are used from time to time to manage interest-rate risk. Under certain conditions, we designate our derivative instruments as a hedge of exposure to changes in fair values or cash flows. We formally document all relationships between hedging instruments and hedged items, as well as risk-management objectives and strategies for undertaking various hedge transactions, and methods for assessing and testing correlation and hedge effectiveness. We specifically identify the forecasted transaction that has been designated as the hedged item in a cash flow hedge relationship. 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 also document our normal purchases and normal sales transactions that we expect to result in physical delivery and that we elect to exempt from derivative accounting treatment.

The realized revenues and purchase costs of our derivative instruments not considered held for trading purposes and derivatives that qualify as normal purchases or normal sales that are expected to result in physical delivery are reported on a gross basis.

Cash flows from futures, forwards, options and swaps that are accounted for as hedges are included in the same category as the cash flows from the related hedged items in our Consolidated Statements of Cash Flows.

See Notes C and D for disclosures of our fair value measurements and risk-management and hedging activities, respectively.

Property, Plant and Equipment - Our properties are stated at cost, including AFUDC and capitalized interest. In some cases, the cost of regulated property retired or sold, plus removal costs, less salvage, is charged to accumulated depreciation. Gains and losses from sales or transfers of nonregulated properties or an entire operating unit or system of our regulated properties are recognized in income. Maintenance and repairs are charged directly to expense.

The interest portion of AFUDC and capitalized interest represent the cost of borrowed funds used to finance construction activities for regulated and nonregulated projects, respectively. We capitalize interest costs during the construction or upgrade of qualifying assets. These costs are recorded as a reduction to interest expense. The equity portion of AFUDC represents the capitalization of the estimated average cost of equity used during the construction of major projects and is recorded in the cost of our regulated properties and as a credit to the allowance for equity funds used during construction.

Our properties are depreciated using the straight-line method over their estimated useful lives. Generally, we apply depreciation rates to functional groups of property having similar economic lives. We periodically conduct depreciation studies to assess the economic lives of our assets. For our regulated assets, these depreciation studies are completed as a part of our rate proceedings or tariff filings, and the changes in economic lives, if applicable, are implemented prospectively when the new rates are approved. For our nonregulated assets, if it is determined that the estimated economic life changes, the changes are made prospectively. Changes in the estimated economic lives of our property, plant and equipment could have a material effect on our financial position or results of operations.

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Property, plant and equipment on our Consolidated Balance Sheets includes construction work in process for capital projects that have not yet been placed in service and therefore are not being depreciated. Assets are transferred out of construction work in process when they are substantially complete and ready for their intended use.

See Note E for our property, plant and equipment disclosures.

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. Our qualitative goodwill impairment analysis performed as of July 1, 2022, did not result in an impairment charge nor did our analysis reflect any reporting units at risk, and subsequent to that date, no event has occurred indicating that the implied fair value of our reporting units with goodwill are less than the carrying value of their net assets.

Goodwill - As part of our goodwill impairment test, we assess qualitative factors (including macroeconomic conditions, industry and market considerations, cost factors and overall financial performance) to determine whether it was more likely than not that the fair value of our reporting units with goodwill are less than their carrying amount. If further testing is necessary or a quantitative test is elected, we perform a Step 1 analysis. In a Step 1 analysis, an assessment is made by comparing the fair value of a reporting unit with its carrying amount, including goodwill. If the carrying value of a reporting unit exceeds its fair value, an impairment loss is recognized in an amount equal to that excess, limited to the total amount of goodwill allocated to that reporting unit.

To estimate the fair value of our reporting units, we use two generally accepted valuation approaches, an income approach and a market approach, using assumptions consistent with a market participant’s perspective. Under the income approach, we use anticipated cash flows over a period of years plus a terminal value and discount these amounts to their present value using appropriate discount rates. The forecasted cash flows are based on probability weighted-average possible future cash flows for a reporting unit over a period of years. Under the market approach, we apply EBITDA multiples to forecasted EBITDA. The multiples used are consistent with recent market transactions.

Long-lived assets - We assess our long-lived assets for impairment whenever events or changes in circumstances indicate that an asset’s carrying amount may not be recoverable. An impairment is indicated if the carrying amount of a long-lived asset exceeds the sum of the undiscounted future cash flows expected to result from the use and eventual disposition of the asset. 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.

Investments in unconsolidated affiliates - The impairment test for equity-method investments considers whether the fair value of the equity investment as a whole, not the underlying net assets, has declined and whether that decline is other than temporary. Therefore, we periodically evaluate the amount at which we carry our equity-method investments to determine whether current events or circumstances warrant adjustments to our carrying values.

See Notes E, F and N for our disclosures and related impairment charges related to long-lived assets, goodwill and intangible assets and investments in unconsolidated affiliates, respectively.

Regulation -Depending on the specific service provided, our natural gas transmission pipelines, NGL pipelines and certain natural gas storage facilities are subject to rate regulation and/or accounting requirements by one or more of the FERC, OCC, KCC and RRC. Accordingly, portions of our Natural Gas Liquids and Natural Gas Pipelines segments follow the accounting and reporting guidance for regulated operations as defined pursuant to Financial Accounting Standards Board’s (FASB) Accounting Standards Codification 980, Regulated Operations. In our Notes to Consolidated Financial Statements, we also state separately certain amounts for regulated operations where they are defined by the SEC. In Notes E and R we have made certain reclassifications to prior year amounts to conform to current year presentation. During the rate-making process for certain of our assets, regulatory authorities set the framework for what we can charge customers for our services and establish the manner that our costs are accounted for, including allowing us to defer recognition of certain costs and permitting recovery of the amounts through rates over time as opposed to expensing such costs as incurred. Certain examples of types of regulatory guidance include costs for fuel and losses, acquisition costs, contributions in aid of construction, charges for depreciation, and gains or losses on disposition of assets. This allows us to stabilize rates over time rather than passing such costs on to the customer for immediate recovery. Actions by regulatory authorities could have an effect on the amounts we may charge our customers. Any difference in the amount recoverable and the amount deferred is recorded as income or expense at the time of the regulatory action. A write-off of regulatory assets and costs not recovered may be required if all or a portion of the regulated operations have rates that are no longer (i) established by independent, third-party regulators and (ii) set at levels that will recover our costs when considering the demand and competition for our services.

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Retirement and Other Postretirement Employee Benefits - We have defined benefit retirement plans covering certain employees and former employees. We sponsor welfare plans that provide postretirement medical and life insurance benefits to certain employees hired prior to 2017 who retire with at least five years of service. The expense and liability related to these plans is calculated using statistical and other factors that attempt to anticipate future events. These factors include assumptions about the discount rate, expected return on plan assets, rate of future compensation increases, mortality and employment length. In determining the projected benefit obligations and costs, assumptions can change from period to period and may result in changes in the costs and liabilities we recognize.

See Note L for our retirement and other postretirement employee benefits disclosures.

Income Taxes - Deferred income taxes are provided for the difference between the financial statement and income tax basis of assets and liabilities and carryforward items based on income tax laws and rates existing at the time the temporary differences are expected to reverse. Generally, the effect of a change in tax rates on deferred tax assets and liabilities is recognized in income in the period that includes the enactment date of the rate change.

We utilize a more-likely-than-not recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position that is taken or expected to be taken in a tax return. We reflect penalties and interest as part of income tax expense as they become applicable for tax provisions that do not meet the more-likely-than-not recognition threshold and measurement attribute. For all periods presented, we had no uncertain tax positions that required the establishment of a material reserve.

We utilize the “with-and-without” approach for intra-period tax allocation for purposes of allocating total tax expense (or benefit) for the year among the various financial statement components.

We file numerous consolidated and separate income tax returns with federal tax authorities of the United States along with the tax authorities of several states. We are not under any United States federal audits or statute waivers at this time.

See Note M for our income taxes disclosures.

Asset Retirement Obligations - Asset retirement obligations represent legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction, development and/or normal use of the asset. Certain of our natural gas gathering and processing, NGL and natural gas pipeline facilities are subject to agreements or regulations that give rise to our asset retirement obligations for removal or other disposition costs associated with retiring the assets in place upon the discontinued use of the assets. We recognize the fair value of a liability for an asset retirement obligation in the period when it is incurred if a reasonable estimate of the fair value can be made. We are not able to estimate reasonably the fair value of the asset retirement obligations for portions of our assets, primarily certain pipeline assets, because the settlement dates are indeterminable given our expected continued use of the assets with proper maintenance. We expect our pipeline assets, for which we are unable to estimate reasonably the fair value of the asset retirement obligation, will continue in operation as long as supply and demand for natural gas and NGLs exist. Based on the widespread use of natural gas for heating and cooking activities for residential users and electric-power generation for commercial users, as well as use of NGLs by the petrochemical industry, we expect supply and demand to exist for the foreseeable future.

For our assets that we are able to make an estimate, the fair value of the liability is added to the carrying amount of the associated asset, and this additional carrying amount is depreciated over the life of the asset. The liability is accreted at the end of each period through charges to operating expense. If the obligation is settled for an amount other than the carrying amount of the liability, we will recognize a gain or loss on settlement. The depreciation and accretion expense are immaterial to our Consolidated Financial Statements.

Contingencies - Our accounting for contingencies covers a variety of business activities, including contingencies for legal and environmental exposures. We accrue these contingencies when our assessments indicate that it is probable that a liability has been incurred or an asset will not be recovered and an amount can be estimated reasonably. We expense legal fees as incurred and base our legal liability estimates on currently available facts and our estimates of the ultimate outcome or resolution. Accruals for estimated losses from environmental remediation obligations generally are recognized no later than completion of a remediation feasibility study. Recoveries of environmental remediation costs from other parties are recorded as assets when their receipt is deemed probable. Our expenditures for environmental evaluation, mitigation, remediation and compliance to date have not been significant in relation to our financial position or results of operations, and our expenditures related to environmental matters had no significant effect on earnings or cash flows during 2022, 2021 and 2020. Actual results may differ from our estimates resulting in an impact, positive or negative, on earnings.

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See Note O for additional discussion of contingencies.

Share-Based Payments - We expense the fair value of share-based payments net of estimated forfeitures. We estimate forfeiture rates based on historical forfeitures under our share-based payment plans.

See Note K for our share-based payments disclosures.

Earnings per Common Share - Basic EPS is calculated based on the daily weighted-average number of shares of common stock outstanding during the period, vested restricted and performance units that have been deferred and share awards deferred under the compensation plan for non-employee directors. Diluted EPS is calculated based on the daily weighted-average number of shares of common stock outstanding during the period plus potentially dilutive components. The dilutive components are calculated based on the dilutive effect for each quarter. For fiscal-year periods, the dilutive components for each quarter are averaged to arrive at the fiscal year-to-date dilutive component.

See Note J for our EPS disclosures.

Segment Reporting - Our chief operating decision-maker reviews the financial performance of each of our three segments, as well as our financial performance as a whole, on a regular basis. Adjusted EBITDA by segment is utilized in this evaluation. We believe this financial measure is useful because it and similar measures are used by many companies in our industry as a measurement of financial performance and are commonly employed by financial analysts and others to evaluate our financial performance and to compare financial performance among companies in our industry. Adjusted EBITDA for each segment 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 other noncash items. This calculation may not be comparable with similarly titled measures of other companies.

See Note R for our segments disclosures.

Recently Issued Accounting Standards Update - Changes to GAAP are established by the FASB in the form of ASUs to the FASB Accounting Standards Codification. We consider the applicability and impact of all ASUs. ASUs not discussed herein were assessed and determined to be either not applicable or clarifications of ASUs previously issued. There have been no new accounting pronouncements that have become effective or have been issued that are of significance or potential significance to us.

B. 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. Subject to the terms and conditions of our insurance policies and any applicable sub-limits, we have property damage and business interruption coverage with a combined per occurrence limit of $2 billion and deductibles of $5 million per occurrence for property damage and a 45-day waiting period per occurrence for business interruption coverage. Beginning in August 2022, we developed claims related to the Medford incident and recorded accruals for the expected insurance recoveries. We assessed incurred costs and lost earnings related to business interruption and property damage to our facility, as well as timing of recognition under applicable insurance recovery guidance, and recorded accruals of $150.7 million in 2022. We received a $100 million unallocated payment from our insurers in the fourth quarter 2022.

We assessed the property damage to our facility and wrote off assets totaling $45.6 million for the year ended December 31, 2022, which represents the value associated with certain damaged Medford facility property. We recorded an insurance receivable that was probable of recovery and fully offsets our noncash property losses, resulting in no impact to our Consolidated Statement of Income. 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. Our property insurance policy also includes coverage for expenses incurred in response to the Medford incident. For the year ended December 31, 2022, we recorded accruals of $9 million related to the incurred costs in excess of our $5 million deductible that were probable of recovery, with an offset to the operations and maintenance line item in our Consolidated Statement of Income.

Our business interruption insurance provides coverage including, but not limited to (i) incurred costs and losses that are either unavoidable or incurred to mitigate or reduce losses and (ii) lost earnings. We record recoveries for incurred costs and losses related to our business interruption coverage for the amount probable of recovery, not to exceed the actual losses incurred and

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for lost earnings that have been realized and are no longer considered a gain contingency. For the year ended December 31, 2022, we recorded accruals of $96.1 million, related primarily to third-party fractionation costs incurred subsequent to the 45-day business interruption waiting period. Accruals for business interruption insurance proceeds are recorded to other operating (income) expense, net in our Consolidated Statement of Income.

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. 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 January and February 2023. The proceeds serve as settlement for property damage, business interruption claims to the date of the 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 an operational gain for the remaining $779.3 million.

C. FAIR VALUE MEASUREMENTS

Recurring Fair Value Measurements - The following tables set forth our recurring fair value measurements as of the dates indicated:

Level 1 Level 2 Level 3 Total - Gross Netting (a) Total - Net

(Thousands of dollars)

Derivative assets

Commodity contracts

Derivative liabilities

Commodity contracts

(a) - Derivative assets and liabilities are presented in our Consolidated Balance Sheet on a net basis. We net derivative assets and liabilities when a legally enforceable master-netting arrangement exists between the counterparty to a derivative contract and us. At December 31, 2022, we held no cash and posted $8.9 million of cash with various counterparties, which is included in other current assets in our Consolidated Balance Sheets.

Level 1 Level 2 Level 3 Total - Gross Netting (a) Total - Net

(Thousands of dollars)

Derivative assets

Commodity contracts

Derivative liabilities

Commodity contracts

(a) - Derivative assets and liabilities are presented in our Consolidated Balance Sheet on a net basis. We net derivative assets and liabilities when a legally enforceable master-netting arrangement exists between the counterparty to a derivative contract and us. At December 31, 2021, we held no cash and posted $157.0 million of cash with various counterparties, including $99.6 million of cash collateral that is offsetting derivative net liability positions under master-netting arrangements in the table above. The remaining $57.4 million of cash collateral in excess of derivative net liability positions is included in other current assets in our Consolidated Balance Sheet.

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The following table sets forth a reconciliation of our Level 3 fair value measurements for the periods indicated:

Years Ended

December 31,

Derivative Assets (Liabilities) 2022 2021

(Thousands of dollars)

Net liabilities at beginning of period $ (114,283) $ (31,321)

Total changes in fair value:

Settlements included in net income (a) 99,567 31,003

Unrealized change included in other comprehensive income (loss) (b) 7,072 3,271

Net liabilities at end of period $ — $ (114,283)

(a) - Included in commodity sales revenues/cost of sales and fuel in our Consolidated Statements of Income.

(b) - Included in change in fair value of derivatives in our Consolidated Statements of Comprehensive Income.

During the years ended December 31, 2022 and 2021, transfers out of Level 3 related to commodity derivatives associated with certain locations for both NGL and natural gas basis swaps were principally due to improved transparency of market prices as a result of the volume and frequency of transactions in these markets. We consider the valuation of these commodity derivatives transacted through a clearing broker and valued with an unadjusted published price from an exchange as a Level 2 valuation.

Other Financial Instruments - The approximate fair value of cash and cash equivalents, accounts receivable, accounts payable and short-term borrowings is equal to book value due to the short-term nature of these items. Our cash and cash equivalents are composed of bank and money market accounts and are classified as Level 1. Our short-term borrowings are classified as Level 2 since the estimated fair value of the short-term borrowings can be determined using information available in the commercial paper market. We have investments associated with our supplemental executive retirement plan and nonqualified deferred compensation plan that are carried at fair value and primarily are composed of exchange-traded mutual funds classified as Level 1.

The estimated fair value of our consolidated long-term debt, including current maturities, was $12.7 billion and $15.6 billion at December 31, 2022 and 2021, respectively. The book value of our consolidated long-term debt, including current maturities, was $13.6 billion at December 31, 2022 and 2021. The estimated fair value of the aggregate senior notes outstanding was determined using quoted market prices for similar issues with similar terms and maturities. The estimated fair value of our consolidated long-term debt is classified as Level 2.