ONEOK INC /NEW/ (OKE) FY 2021 MD&A

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 from increased volumes in 2021, compared with 2020, due primarily to increased producer activity and rising gas-to-oil ratios in the Rocky Mountain region, production curtailments in 2020, increased ethane production in the Rocky Mountain region and higher commodity prices in both our Natural Gas Gathering and Processing and Natural Gas Liquids segments, highlighting both the resiliency of our integrated assets and the economic recovery from the pandemic.

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 period to period. Ethane volumes under long-term contracts delivered to our NGL system increased approximately 55 MBbl/d to an average of 430 MBbl/d in 2021, compared with 375 MBbl/d in 2020, 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. Ethane recovery opportunities will fluctuate based on regional natural gas pricing and ethane economics.

Growth Projects - We operate an integrated, reliable and diversified network of NGL and natural gas gathering, processing, fractionation, storage and transportation assets connecting supply in the Rocky Mountain, Mid-Continent and Permian regions with key market centers. Our publicly announced capital-growth projects are outlined in the table below:

(a) - Excludes capitalized interest/AFUDC.

(b) - In November 2021, we announced that we restarted construction of the Demicks Lake III natural gas processing plant. Upon announcement, the expected cost to complete was approximately $140 million.

(c) - In November 2021, we announced that we restarted construction of the MB-5 NGL fractionator. Upon announcement, the expected cost to complete was approximately $250 million.

Debt Repayments - In November 2021, we redeemed the remaining $536.1 million of our $700 million, 4.25% senior notes due February 2022 at 100% of the principal amount, plus accrued and unpaid interest, with cash on hand and short-term borrowings.

In June 2021, we repaid the remaining $11.7 million of Guardian Pipeline’s senior notes due December 2022 with cash on hand.

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In 2021, we repurchased in the open market outstanding principal of certain of our senior notes in the amount of $55.2 million for an aggregate repurchase price of $54.6 million with cash on hand.

Dividends - During 2021, we paid common stock dividends totaling $3.74 per share, which is consistent with the prior year. In February 2022, we paid a quarterly common stock dividend of $0.935 per share ($3.74 per share on an annualized basis), which is consistent with the same quarter in the prior year.

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 consolidated financial results for the periods indicated:

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

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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.

2021 vs. 2020 - Operating income increased $1.2 billion primarily as a result of the following:

•an increase of $607.2 million due to noncash impairment charges in our Natural Gas Gathering and Processing and Natural Gas Liquids segments in 2020;

•Natural Gas Liquids - increases of $421.4 million in exchange services related primarily to higher volumes in the Rocky Mountain region, the Mid-Continent region and Permian Basin and wider commodity price differentials, and $98.3 million in optimization and marketing. These increases were offset partially by a decrease of $46.2 million from the impact of Winter Storm Uri in exchange services;

•Natural Gas Gathering and Processing - increases of $143.5 million due primarily to lower realized prices in 2020 impacting our fee with POP contracts and $115.8 million from higher volumes due primarily to increased production and rising gas-to-oil ratios in the Rocky Mountain region in 2021 and production curtailments in 2020; and

•Natural Gas Pipelines - an increase of $109.1 million due to primarily to increased natural gas sales; offset by

•an increase of $180.9 million in consolidated operating costs due primarily to higher employee costs related to short-term incentives, property taxes, outside services and the impact of a loss on the mark-to-market of our share-based deferred compensation plan in 2021 compared with a benefit in 2020; and

•an increase of $43.0 million in depreciation expense due to capital projects placed in service.

Net income and diluted EPS increased due primarily to the items discussed above and noncash impairment charges related to equity investments in our Natural Gas Gathering and Processing and Natural Gas Liquids segments in the prior year. These increases were offset partially by higher income taxes, higher interest expense related to lower capitalized interest and lower equity AFUDC due to completed projects, lower equity in net earnings from investments and a gain in 2020 on extinguishment of debt related to open market repurchases.

Capital expenditures decreased due primarily to our completed and paused capital-growth projects.

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

Selected Financial Results and Operating Information for the Year Ended December 31, 2020 vs. 2019 - The consolidated and segment financial results and operating information for the year ended December 31, 2020, compared with the year ended December 31, 2019, are included in Part II, Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations of our 2020 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:

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

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

2021 vs. 2020 - Adjusted EBITDA increased $239.1 million, primarily as a result of the following:

•an increase of $143.5 million due primarily to lower realized prices, net of hedging, in 2020 impacting our fee with POP contracts; and

•an increase of $115.8 million from higher volumes due primarily to increased production and rising gas-to-oil ratios in the Rocky Mountain region in 2021 and production curtailments in 2020, offset partially by natural production declines in the Mid-Continent region; and

•an increase of $7.3 million from a gain on the partial sale of an equity investment; offset by

•an increase of $31.4 million in operating costs due primarily to higher employee costs related to short-term incentives.

Capital expenditures decreased due primarily to completed capital-growth projects in 2020.

(a) - Includes volumes for consolidated entities only.

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

2021 vs. 2020 - Our natural gas gathered and natural gas processed volumes increased due primarily to increased producer activity and rising gas-to-oil ratios in the Rocky Mountain region and the impact of curtailed production in 2020, offset partially by natural production declines in the Mid-Continent region.

Our average fee rate increased due primarily to production curtailments in the second quarter 2020 on producer contracts with higher fees and lower POP components in the Rocky Mountain region. As these curtailed volumes have returned to our system and producer activity has continued to increase, the Rocky Mountain region’s contribution to our average fee rate increased in 2021.

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

Impairments - The year ended December 31, 2020, includes $382.2 million of noncash impairment charges related primarily to certain long-lived asset groups in the Powder River Basin, western Oklahoma and Kansas that were not recoverable, a

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$153.4 million noncash impairment charge related to goodwill and a $30.5 million noncash impairment charge related to our 10.2% investment in Venice Energy Services Company.

Natural Gas Liquids

Growth Projects - Our Natural Gas Liquids segment invests in projects to transport, fractionate, store and deliver to market centers NGL supply from shale and other resource development areas. Our growth strategy is focused around connecting diversified supply basins from the Rocky Mountain region through the Mid-Continent region and the Permian Basin with NGL product 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 2021, we connected one third-party natural gas processing plant in the Permian Basin and one third-party natural gas processing plant in the Rocky Mountain region to our NGL system. In addition, one affiliate natural gas processing plant in the Rocky Mountain region 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:

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.

2021 vs. 2020 - Adjusted EBITDA increased $346.4 million primarily as a result of the following:

•an increase of $421.4 million in exchange services (excluding the impact of Winter Storm Uri discussed below) due primarily to:

◦$261.6 million in higher volumes primarily in the Rocky Mountain region, Mid-Continent region and Permian Basin, offset partially by lower volumes in the Barnett Shale,

◦$98.9 million related to wider commodity price differentials,

◦$63.8 million in lower transportation costs in the Rocky Mountain region, and

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

•an increase of $98.3 million in optimization and marketing due primarily to wider location and commodity price differentials, increased activities during Winter Storm Uri and higher optimization volumes; offset by

•the negative impact of Winter Storm Uri of $46.2 million in exchange services due primarily to decreased volumes across our operations and higher electricity costs;

•an increase of $103.0 million in operating costs due primarily to increased property taxes associated with our completed capital-growth projects, higher employee costs related to short-term incentives and higher outside services; and

•a decrease of $18.9 million from lower equity in net earnings from investments due primarily to lower volumes on Overland Pass Pipeline.

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Capital expenditures decreased due primarily to completed and paused capital-growth projects in 2020.

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

2021 vs. 2020 - Volumes increased due primarily to increased production primarily in the Rocky Mountain region, Mid-Continent region and Permian Basin, increased ethane production in the Rocky Mountain region, and the impact of curtailed production across our system in 2020, offset partially by the impact of Winter Storm Uri in 2021 and lower volumes in the Barnett Shale.

Impairments - The year ended December 31, 2020, includes $71.6 million of noncash impairment charges related primarily to certain inactive assets and a $7.2 million noncash impairment charge related to our 50% investment in Chisholm Pipeline Company.

Natural Gas Pipelines

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:

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

2021 vs. 2020 - Adjusted EBITDA increased $90.4 million primarily as a result of the following:

•an increase of $109.1 million due primarily to higher average natural gas prices on 5.2 Bcf of natural gas sales in the first quarter 2021 of volumes previously held in inventory, compared with 1.2 Bcf in the first quarter 2020; and

•an increase of $8.9 million from storage services due primarily to higher storage rates; and

•an increase of $4.7 million in transportation services due primarily to higher park-and-loan revenue and higher interruptible transportation revenue in the first quarter 2021, offset partially by a favorable $13.5 million contract settlement in April 2020; offset by

•an increase of $24.9 million in operating costs due primarily to higher employee costs related primarily to short-term incentives, higher outside services and supplies expenses; and

•a decrease of $6.6 million from lower equity in net earnings from investments due primarily to decreased firm transportation revenues on Northern Border Pipeline.

Capital expenditures increased in 2021 due primarily to capital-growth projects.

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(a) - Includes volumes for consolidated entities only.

Roadrunner, in which we have a 50% ownership interest, has contracted all of its westbound capacity through 2041.

Northern Border Pipeline, in which we have a 50% ownership interest, has contracted substantially all of its long-haul transportation capacity through the fourth quarter 2022.

In February 2021, our subsidiary, Midwestern Gas Transmission Company (Midwestern), filed a proposed change in rates pursuant to Section 4 of the Natural Gas Act with the FERC. In February 2022, Midwestern filed a Stipulation and Offer of Settlement with the FERC for approval. Pending approval by the FERC, the proposed settlement is not expected to impact materially 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:

(a) - Year ended December 31, 2021 and 2020, includes a loss of $7.4 million and a benefit of $11.2 million, respectively, related to the mark-to-market of our share-based deferred compensation plan.

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

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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.

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 2024 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 C of the Notes to Consolidated Financial Statements in this Annual Report.

Guarantees and Cash Management - In 2020, the SEC amended Rule 3-10 of Regulation S-X and created Rule 13-01 to simplify disclosure requirements related to certain registered securities. 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 non-guarantors, and substantially all the assets and operations reside with non-guarantor 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 F 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 non-guarantor 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. As of December 31, 2021, we are in compliance with all covenants of our $2.5 Billion Credit Agreement.

At December 31, 2021, we had no borrowings under our $2.5 Billion Credit Agreement and $146.4 million of cash and cash equivalents.

We had a working capital (defined as current assets less current liabilities) deficit of $810.2 million and a working capital surplus of $525.2 million as of December 31, 2021, and December 31, 2020, respectively. Although working capital is influenced by several factors, including, among other things: (i) the timing of (a) debt and equity issuances, (b) scheduled debt payments, (c) the funding of capital expenditures, and (d) accounts receivable and payable; and (ii) the volume and cost of inventory and commodity imbalances; our working capital deficit at December 31, 2021, was driven primarily by current maturities of long-term debt and our working capital surplus at December 31, 2020, was driven primarily by cash on hand. 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.

For additional information on our $2.5 Billion Credit Agreement, see Note F 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

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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 Repayments - In November 2021, we redeemed the remaining $536.1 million of our $700 million, 4.25% senior notes due February 2022 at 100% of the principal amount, plus accrued and unpaid interest, with cash on hand and short-term borrowings.

In June 2021, we repaid the remaining $11.7 million of Guardian Pipeline’s senior notes due December 2022 with cash on hand.

In 2021, we repurchased in the open market outstanding principal of certain of our senior notes in the amount of $55.2 million for an aggregate repurchase price of $54.6 million 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 F 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:

Total capital expenditures decreased in 2021, compared with 2020, due primarily to our completed capital-growth projects in the prior year. We expect our 2022 capital expenditures to increase relative to 2021 due to our publicly announced capital-growth projects. See discussion of our announced capital-growth projects in the “Recent Developments” section.

We expect total capital expenditures, excluding AFUDC and capitalized interest, of $900-$1,050 million in 2022.

Credit Ratings - Our long-term debt credit ratings as of February 22, 2022, are shown in the table below:

Our credit ratings, which are investment grade, may be affected by a material change in our financial ratios or a material event affecting our business and industry. 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 2024. An adverse credit rating change alone is not a default under our $2.5 Billion Credit Agreement.

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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 2021, we paid common stock dividends of $3.74 per share, which is consistent with prior year. In February 2022, we paid a quarterly common stock dividend of $0.935 per share ($3.74 per share on an annualized basis), which is consistent 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 2021, we paid dividends of $1.1 million for the Series E Preferred Stock. In February 2022, we paid quarterly dividends totaling $0.3 million for the Series E Preferred Stock.

For the year ended December 31, 2021, our cash flows from operations exceeded dividends paid by $878.8 million. 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.

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

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.

2021 vs. 2020 - Cash flows from operating activities, before changes in operating assets and liabilities, increased $628.5 million due primarily to higher net income resulting from higher exchange services in our Natural Gas Liquids segment, higher realized prices and increased volumes in our Natural Gas Gathering and Processing segment and natural gas sales in our Natural Gas Pipelines segment, as discussed in “Financial Results and Operating Information.”

The changes in operating assets and liabilities decreased operating cash flows $141.8 million for the year ended December 31, 2021, compared with a decrease of $160.5 million for the same period in 2020. The change is due primarily to changes in accounts payable resulting from the timing of payments to vendors, suppliers and other third parties and changes in commodity

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prices, which vary from period to period; changes in risk-management assets and liabilities, which include a loss in 2020 on the settlement of $750 million of our forward interest-rate swaps related to our March 2020 issuances of senior unsecured notes and changes in the fair value of risk-management assets and liabilities, which vary from period to period and with changes in commodity prices and interest rates; and changes in other assets and liabilities; offset partially by changes in accounts receivable resulting from the timing of receipt of cash from customers and NGLs and natural gas in storage, both of which vary from period to period and with changes in commodity prices.

Investing Cash Flows

2021 vs. 2020 - Cash used in investing activities decreased $1.6 billion due primarily to reduced capital expenditures related to our completed capital-growth projects.

Financing Cash Flows

2021 vs. 2020 - Cash from financing activities decreased $3.1 billion due primarily to the issuances of $3.25 billion in long-term debt and issuance of common stock in 2020, offset partially by repayments of long-term debt of $0.6 billion in 2021 compared with repayments of $1.5 billion in 2020.

Cash Flow Analysis for the Year Ended December 31, 2020 vs. 2019 - The cash flow analysis for the year ended December 31, 2020, compared with the year ended December 31, 2019, is included in Part II, Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations of our 2020 Annual Report on Form 10-K, which is available via the SEC’s website at www.sec.gov and our website at www.oneok.com.

IMPACT OF NEW ACCOUNTING STANDARDS

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

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

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. Our commodity price risk includes basis risk, which is the difference in price between various locations where commodities are purchased and sold. We record all derivative instruments at fair value, except for normal purchases and normal sales transactions that are expected to result in physical delivery. Many of the contracts in our derivative portfolio are executed in liquid markets where price transparency exists.

Our commodity derivatives are generally valued using quoted prices published by an exchange. Our fair value measurements classified as Level 3 are composed predominantly of exchange-cleared and over-the-counter derivatives to hedge NGL price risk at certain market locations. These measurements are based on inputs that may include one or more unobservable inputs, including internally developed commodity price curves, that incorporate market data from broker quotes and third-party pricing services. We believe any measurement uncertainty at December 31, 2021, is immaterial as our Level 3 fair value measurements are based on unadjusted pricing information from broker quotes and third-party pricing services.

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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 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, B and C 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.

Our impairment tests require the use of assumptions and estimates, such as industry economic factors and the profitability of future business strategies. To estimate the fair value of these assets and investments, 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, D, E and M 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 and (v) 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 D of the Notes to Consolidated Financial Statements in this Annual Report for additional discussion of property, plant and equipment.

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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 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,” “target,” “guidance,” “intend,” “may,” “might,” “outlook,” “plan,” “potential,” “project,” “scheduled,” “should,” “will,” “would,” and other words and terms of similar meaning.

One should not place undue reliance on forward-looking statements. Known and unknown risks, uncertainties and other factors may cause our actual results, performance or achievements to be materially different from any future results, performance or achievements expressed or implied by forward-looking statements. Those factors may affect our operations, markets, products, services and prices. In addition to any assumptions and other factors referred to specifically in connection with the forward-looking statements, factors that could cause our actual results to differ materially from those contemplated in any forward-looking statement include, among others, the following:

•the length, severity and reemergence of a pandemic or other health crisis, such as the COVID-19 pandemic and the measures that international, federal, state and local governments, agencies, law enforcement and/or health authorities implement 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 for an extended period and increase the cost of operating our business;

•operational challenges relating to the COVID-19 pandemic and efforts to mitigate the spread of the virus, including logistical challenges, protecting the health and well-being of our employees, remote work arrangements, performance of contracts and supply chain disruption;

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

•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 transition to a lower-carbon economy, including the timing and extent of the transition, as well as the expected role of different energy sources in such a transition;

•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 strategies, including mitigating cyber- and climate-related risks;

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•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 transition to, various renewable and alternative energy opportunities, including through the positioning and optimization of our assets;

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

•the necessity to direct our focus on maintaining and enhancing our existing assets instead of efforts to reduce our GHG emissions;

•the effects of weather and other natural phenomena, including climate change, on our operations, demand for our services and energy prices;

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

•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;

•the risk of increased costs for insurance premiums, security or other items as a consequence of terrorist attacks;

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

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

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

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

–    competitive conditions in the overall energy market;

–    availability of supplies of United States natural gas and crude oil; 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 energy prices or the financial condition of our counterparties;

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

•the risk 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 make us vulnerable to general adverse economic and industry conditions, limit our ability to borrow additional funds and/or place us at competitive disadvantages compared with our competitors that have less debt or have other adverse consequences;

•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, storage, fractionation and transportation facilities without labor or contractor problems;

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

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•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;

•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; and

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

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.