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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.

COVID-19 - While we are still experiencing global and regional economic disruption due primarily to COVID-19, our producers have reversed curtailments that were put in place during the second quarter 2020, bringing volumes back to pre-COVID-19 levels as prices significantly improved from second quarter 2020 lows. The full impact of the continued global and regional economic disruption will depend on the unknown duration and severity of COVID-19, and, among other things, the impact of governmental actions imposed in response to COVID-19, the pace and scale of economic recovery and corresponding demand for crude oil, and the impacts to commodity prices. We continue to monitor producers’ drilling, completion and production plans, which are increasingly positive as commodity prices have stabilized and improved, and our expectations for 2021 include the potential for an improving pace of drilling and completion activity.

In this challenging market environment, we expect to maintain sufficient liquidity and financial stability into 2021 due to cash on hand from our June 2020 equity issuance, cash flows from operations and access to our undrawn $2.5 Billion Credit Agreement. We have no debt maturities prior to 2022, and our investment-grade credit ratings have remained stable.

Sustainability - In 2020, we were included in the Dow Jones Sustainability North America Index for the second consecutive year and added to the Dow Jones Sustainability World Index (DJSI World), which recognize companies for industry-leading

environmental, social and governance performance. We are currently the only North American energy company included in the DJSI World group of global sustainability leaders. We continue to look for ways to reduce our environmental impact and utilize more efficient technologies. We are preparing for the future energy transition and our role in meeting the world’s energy needs in an environmentally responsible way.

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. We have completed significant capital-growth projects that include NGL pipelines, NGL fractionators, natural gas processing plants and related natural gas and NGL infrastructure. These projects provide us the capacity to benefit from future supply growth without significant capital investment. In the first quarter 2020, due to the decline in commodity prices and economic demand disruption caused by COVID-19, we suspended our announced plans to construct the Demicks Lake III natural gas processing plant, the fourth expansion of the ONEOK West Texas NGL pipeline system, and reduced the scope of the expansion of our Elk Creek pipeline and various other paused projects. These projects can be restarted quickly when producer activity warrants additional infrastructure. Our announced capital-growth projects are outlined in the table below:

Project (b) Scope ApproximateCosts (a) Completion

Natural Gas Gathering and Processing (In millions)

Supported by acreage dedications with long-term primarily fee-based contracts

Natural Gas Liquids

Anchored by long-term contracts

Expansion capability up to 400 MBbl/d with additional pump facilities

Supported by long-term contracts

Expansion capability up to 1 MMBbl/d

Fully contracted with long-term contracts

Connecting ONEOK West Texas NGL pipeline system to the Arbuckle II pipeline

Supported by a long-term contract with a minimum volume commitment

Increases capacity to 500 MBbl/d

Fully contracted with long-term contracts

(a) - Excludes capitalized interest/AFUDC.

(b) - Projects listed exclude our suspended capital-growth projects, which include the Demicks Lake III natural gas processing plant, the fourth expansion of the ONEOK West Texas NGL pipeline system and a reduction in the scope of the expansion of the Elk Creek pipeline.

(c) - Given the current environment, we paused the majority of construction activities on these projects and do not expect to complete construction by the original target completion date.

(d) - We completed 75 MBbl/d in December 2019 and completed the remaining 50 MBbl/d in March 2020.

(e) - We completed expansions to increase mainline capacity by approximately 45 MBbl/d in the first quarter 2020 and completed the remaining portion of this project in the second quarter 2020, which was delayed due to weather.

Ethane Production - Ethane production fluctuates over short-term periods driven by ethane economics, and as a result, volumes can also fluctuate period to period. Ethane volumes under long-term contracts delivered to our NGL system averaged 375 MBbl/d in 2020, compared with 385 MBbl/d in 2019, but increased by approximately 30 MBbl/d in the second half of 2020, compared with the second quarter 2020, due primarily to improved ethane economics. We expect ethane production to continue to fluctuate throughout 2021.

Debt Issuances and Repayments - In May 2020, we completed an underwritten public offering of $1.5 billion senior unsecured notes consisting of $600 million, 5.85% senior notes due 2026; $600 million, 6.35% senior notes due 2031; and $300 million, 7.15% senior notes due 2051. The net proceeds, after deducting underwriting discounts, commissions and offering expenses, were $1.48 billion. A portion of the proceeds was used to repay the outstanding borrowings under our $1.5 Billion Term Loan Agreement. The remainder was used for general corporate purposes.

In March 2020, we completed an underwritten public offering of $1.75 billion senior unsecured notes consisting of $400 million, 2.2% senior notes due 2025; $850 million, 3.1% senior notes due 2030; and $500 million, 4.5% senior notes due 2050. The net proceeds, after deducting underwriting discounts, commissions and offering expenses, were $1.73 billion. A portion of the proceeds was used to pay all outstanding amounts under our commercial paper program. The remainder was used for general corporate purposes, which included repayment of other existing indebtedness and funding capital expenditures.

In 2020, we repurchased in the open market outstanding principal of certain of our senior notes in the amount of $224.4 million for an aggregate repurchase price of $199.6 million with cash on hand. In connection with these open market repurchases, we recognized $22.3 million of net gains on extinguishment of debt.

Equity Issuances - In June 2020, we completed an underwritten public offering of 29.9 million shares of our common stock at a public offering price of $32.00 per share, generating net proceeds, after deducting underwriting discounts, commissions and offering expenses, of $937.0 million. A portion of the proceeds was, and we anticipate the remainder will be, used for general corporate purposes, including repayment of existing indebtedness and funding capital expenditures.

Dividends - During 2020, we paid dividends totaling $3.74 per share, an increase of 6% from the $3.53 per share paid in 2019. In February 2021, we maintained and paid a quarterly 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.

Impairments-Due to historic events as a result of COVID-19 impacting supply, demand and commodity prices, in 2020 we evaluated our goodwill, certain long-lived asset groups and equity investments for impairment. Based on the results, we recorded the following impairment charges:

Natural Gas Gathering and Processing - In 2020, we recorded $382.2 million of noncash impairment charges related primarily to certain long-lived asset groups that were not recoverable, $153.4 million of noncash impairment charges related to goodwill and $30.5 million of noncash impairment charges related to our 10.2% investment in Venice Energy Services Company.

Natural Gas Liquids - In 2020, we recorded $71.6 million of noncash impairment charges related primarily to certain inactive assets as our expectation for future use of the assets changed and $7.2 million of noncash impairment charges related to our 50% investment in Chisholm Pipeline Company.

For additional information on our impairment charges, see Notes A, D, E and M of the Notes to Consolidated Financial Statements in this Annual Report.

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) the following non-GAAP financial measures: adjusted EBITDA and distributable cash flow. 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, distributable cash flow and dividend coverage ratio are non-GAAP measures 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. Distributable cash flow is defined as adjusted EBITDA, computed as described above, less interest expense, maintenance capital expenditures and equity earnings from investments, excluding noncash impairment charges, adjusted for net cash distributions received from unconsolidated affiliates and certain other items. Dividend coverage ratio is defined as distributable cash flow to common shareholders divided by the dividends paid in the period. We believe these non-GAAP financial measures are useful to investors because they 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, distributable cash flow and dividend coverage ratio should not be considered alternatives to net income, EPS or any other measure of financial performance presented in accordance with GAAP. Additionally, these calculations 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:

(Millions of dollars, except per share amounts)

Revenues

(Gain) loss on sale of assets (1.3) 2.6 (0.6) 3.9 (3.2)

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

See reconciliation of net income to adjusted EBITDA and distributable cash flow in the “Non-GAAP 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.

2020 vs. 2019 - Operating income decreased $553.0 million primarily as a result of the following:

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

•an increase of $102.2 million in depreciation expense due to capital projects placed in service;

•Natural Gas Gathering and Processing - a decrease of $47.6 million due primarily to lower realized prices and a decrease of $42.6 million due primarily to natural production declines in the Mid-Continent region; offset partially by

•Natural Gas Liquids - an increase of $270.6 million in exchange services due primarily to higher volumes in the Rocky Mountain region and Permian Basin and lower rail and pipeline transportation costs, offset partially by a decrease of $123.5 million in optimization and marketing due primarily to narrower location price differentials, lower optimization volumes and lower marketing earnings;

•a decrease of $96.8 million in operating costs due primarily to reduced outside services, lower materials and supplies expenses, lower employee-related costs and the noncash mark-to-market impact of our share-based deferred compensation plan; and

•Natural Gas Pipelines - an increase of $6.7 million in transportation services due primarily to higher firm transportation revenue and a $13.5 million contract settlement, offset partially by lower interruptible revenue.

Net income and diluted EPS decreased due primarily to the items discussed above and higher interest expense related to an increase in our debt balance and lower capitalized interest and noncash impairment charges related to equity investments in our Natural Gas Gathering and Processing and Natural Gas Liquids segments, offset partially by net gains on extinguishment of debt related to open market repurchases. Diluted EPS was also impacted by our equity issuance in June 2020.

Capital expenditures decreased due primarily to our previously completed capital-growth projects as well as our paused and suspended capital-growth projects related to weakened commodity prices and economic disruption caused by COVID-19.

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

Selected Financial Results and Operating Information for the Year Ended December 31, 2019 vs. 2018 - The consolidated and segment financial results and operating information for the year ended December 31, 2019, compared with the year ended December 31, 2018, are included in Part II, Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations of our 2019 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.

See “Capital Expenditures” in “Liquidity and Capital Resources” for additional detail of our projected capital expenditures.

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 (1.1) (6.3) 0.4 5.2 (6.7)

Impairment charges $ 566.1 $ — $ — 566.1 —

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.

2020 vs. 2019 - Adjusted EBITDA decreased $52.7 million, primarily as a result of the following:

•a decrease of $47.6 million due primarily to lower realized prices impacting our fee with POP contracts; and

•a decrease of $42.6 million due primarily to natural production declines in the Mid-Continent region; offset partially by

•a decrease of $32.8 million in operating costs due primarily to lower materials and supplies expenses due to reduced asset utilization, lower employee-related costs and outside services.

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 $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. For additional information on our impairment charges, see Notes A, D, E and M of the Notes to Consolidated Financial Statements in this Annual Report.

Capital expenditures decreased due primarily to capital-growth projects completed in 2019 and early 2020, as well as several paused capital-growth projects in 2020.

Years Ended December 31,

Average fee rate ($/MMBtu) $ 0.89 $ 0.92 $ 0.90

(a) - Includes volumes for consolidated entities only.

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

2020 vs. 2019 - Our natural gas gathered and natural gas processed volumes decreased due primarily to natural production declines in the Mid-Continent region. In the Williston Basin, we saw significant declines in volumes in the second quarter 2020 due to production curtailments from some of our crude oil and natural gas producers. By the end of the third quarter 2020, curtailed volumes returned.

Our average fee rate decreased due primarily to production curtailments in the second quarter 2020 on producer contracts with higher fees and lower POP components in the Williston Basin. As these curtailed volumes returned to our system, the Williston Basin’s contribution to our average fee rate increased in the second half of 2020.

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

Natural Gas Liquids

Growth Projects - Our Natural Gas Liquids segment invests in projects to transport, fractionate, store and deliver to market centers NGL supply from shale and other resource development areas. Our growth strategy is focused around connecting diversified supply basins from the Rocky Mountain region through the Mid-Continent region and the Permian Basin with 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 2020, we connected two third-party natural gas processing plants in the Permian Basin and two third-party natural gas processing plants in the Rocky Mountain region to our NGL system. In addition, one affiliate and two third-party natural gas processing plants in the Rocky Mountain region and one third-party natural gas processing plant in the Mid-Continent region connected to our system were 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.

2020 vs. 2019 - Adjusted EBITDA increased $151.4 million, primarily as a result of the following:

•an increase of $270.6 million in exchange services due primarily to $137.8 million in higher volumes in the Rocky Mountain region and Permian Basin, $128.4 million in lower costs due primarily to lower rail and pipeline transportation costs, $18.8 million in higher fees charged to customers with minimum volume obligations primarily in the Rocky Mountain region, $17.2 million in higher average fee rates primarily in the Permian Basin and $13.7 million related to lower unfractionated NGLs held in inventory, offset partially by $34.2 million in lower volumes in the Mid-Continent region; and

•a decrease of $38.0 million in operating costs due primarily to lower outside services and employee-related costs; offset partially by

•a decrease of $123.5 million in optimization and marketing due primarily to a decrease of $78.2 million related to narrower location price differentials and lower optimization volumes, lower marketing earnings of $53.0 million due to lower earnings from purity NGL inventory sales and changes in the value of NGLs held in inventory; and

•a decrease of $25.2 million from lower equity in net earnings from investments due primarily to lower volumes on Overland Pass Pipeline.

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. For additional information on our impairment charges, see Notes A, D and M of the Notes to Consolidated Financial Statements in this Annual Report.

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

Years Ended December 31,

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

2020 vs. 2019 - Volumes increased due primarily to increased production at new and existing processing plants in the Rocky Mountain region and Permian Basin, offset partially by lower volumes in the Mid-Continent region and the unfavorable impact from producer curtailments primarily in the second quarter 2020.

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:

(Millions of dollars)

Residue natural gas sales and other revenues 9.9 5.7 16.7 4.2 (11.0)

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

2020 vs. 2019 - Adjusted EBITDA increased $28.6 million primarily as a result of the following:

•a decrease of $13.6 million in operating costs due primarily to lower employee-related costs and materials and supplies expenses;

•an increase of $8.7 million from higher equity in net earnings from investments due primarily to additional firm transportation capacity contracted on Northern Border;

•an increase of $6.7 million in transportation services due primarily to higher firm transportation revenue and a $13.5 million contract settlement, offset partially by lower interruptible revenue; and

•an increase of $4.0 million from higher net retained fuel and timing of equity gas sales; offset partially by

•a decrease of $3.9 million from storage services due primarily to lower park-and-loan activity.

Capital expenditures decreased due primarily to the completion of our expansion projects in 2019.

Years Ended December 31,

Natural gas transportation capacity contracted (MDth/d) 7,461 7,618 6,846

Transportation capacity contracted 96 % 98 % 96 %

(a) - Includes volumes for consolidated entities only.

2020 vs. 2019 - Natural gas transportation capacity contracted decreased due to a contract settlement and the impact of market conditions.

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 2021.

In June 2019, our subsidiary, Viking Gas Transmission Company (Viking), filed a proposed change in rates pursuant to Section 4 of the Natural Gas Act with the FERC. In February 2020, Viking filed a Stipulation and Offer of Settlement (Settlement) with the FERC for approval. The FERC accepted the Settlement in July 2020, which did not impact materially our results of operations.

NON-GAAP MEASURES

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

Years Ended December 31,

Add:

Dividends paid to preferred shareholders (1,100) (1,100) (1,100)

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

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

Years Ended December 31,

Segment adjusted EBITDA:

(a) - 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 matters.

Other Legal Proceedings - We are a party to various litigation matters and claims that have arisen in the normal course of our operations. While the results of these litigation matters and claims cannot be predicted with certainty, we believe the reasonably possible losses from such matters, individually and in the aggregate, are not material. Additionally, we believe the probable final outcome of such matters 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. In addition, we expect cash outflows in 2021 to be primarily related to dividends paid to shareholders and capital expenditures.

We expect our sources of cash inflows to provide sufficient resources to finance our operations and quarterly cash dividends. We believe we have sufficient liquidity due to our $2.5 Billion Credit Agreement, which expires in June 2024, cash on hand from our June 2020 equity issuance and access to $1.0 billion available through our “at-the-market” equity program.

We 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 March 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, 2020, we are in compliance with all covenants of our $2.5 Billion Credit Agreement.

At December 31, 2020, we had no borrowings under our $2.5 Billion Credit Agreement and $524.5 million of cash and cash equivalents.

We had a working capital (defined as current assets less current liabilities) surplus of $525.2 million and a working capital deficit of $550.0 million as of December 31, 2020, and December 31, 2019, 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 payments, and (d) accounts receivable and payable; and (ii) the volume and cost of inventory and commodity imbalances; our working capital surplus at December 31, 2020, was driven primarily by cash on hand and our working capital deficit at December 31, 2019, was driven primarily by short-term borrowings and accrued interest. We may have working capital deficits in future periods as we continue to repay long-term debt and finance our capital-growth projects, often initially with short-term borrowings.

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

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 May 2020, we completed an underwritten public offering of $1.5 billion senior unsecured notes consisting of $600 million, 5.85% senior notes due 2026; $600 million, 6.35% senior notes due 2031; and $300 million, 7.15% senior notes due 2051. The net proceeds, after deducting underwriting discounts, commissions and offering expenses, were $1.48 billion. A portion of the proceeds was used to repay the outstanding borrowings under our $1.5 Billion Term Loan Agreement. The remainder was used for general corporate purposes.

Debt Repayments - In May 2020, we repaid the remaining $1.25 billion of our $1.5 Billion Term Loan Agreement with cash on hand from our May 2020 public offering of $1.5 billion senior unsecured notes.

For additional information on our long-term debt, see Note F of the Notes to Consolidated Financial Statements in this Annual Report.

Equity Issuances - In July 2020, we established an “at-the-market” equity program for the offer and sale from time to time of our common stock up to an aggregate offering price of $1.0 billion. The program allows us to offer and sell common stock at prices we deem appropriate through a sales agent, in forward sales transactions through a forward seller or directly to one or more of the program’s managers acting as principals. Sales of our common stock may be made by means of ordinary brokers’ transactions on the NYSE, in block transactions or as otherwise agreed to between us and the sales agent. We are under no obligation to offer and sell common stock under the program. No shares have been sold through our “at-the-market” program as of the date of this report.

In June 2020, we completed an underwritten public offering of 29.9 million shares of our common stock at a public offering price of $32.00 per share, generating net proceeds, after deducting underwriting discounts, commissions and offering expenses, of $937.0 million. A portion of the proceeds was, and we anticipate the remainder will be, used for general corporate purposes, including repayment of existing indebtedness and funding capital expenditures.

Capital Expenditures- We classify expenditures that are expected to generate additional revenue, return on investment or significant operating efficiencies as capital-growth 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 and capitalized interest, for the periods indicated:

(Millions of dollars)

Capital expenditures decreased in 2020, compared with 2019, due primarily to our previously completed capital-growth projects, as well as our paused and suspended capital-growth projects. We expect our 2021 capital expenditures to decrease

relative to 2020 due to our previously completed capital-growth projects and paused and suspended capital-growth projects, unless producer activity levels warrant additional infrastructure. See discussion of our announced capital-growth projects in the “Recent Developments” section.

We expect total capital expenditures, excluding AFUDC and capitalized interest, of $525-$675 million in 2021.

Credit Ratings - Our long-term debt credit ratings as of February 16, 2021, are shown in the table below:

Rating Agency Long-Term Rating Short-Term Rating Outlook

Moody’s Baa3 Prime-3 Stable

S&P BBB A-2 Stable

Fitch (a) BBB F2 Stable

(a) - Fitch assigned first-time ratings to ONEOK in November 2020.

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. Although we are in the midst of a challenging market environment, our credit ratings have remained stable. 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.

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 2020, we paid dividends of $3.74 per share, an increase of 6% compared with the prior year. In February 2021, we maintained and paid a quarterly 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 2020, we paid dividends of $1.1 million for the Series E Preferred Stock. In February 2021, we paid quarterly dividends totaling $0.3 million for the Series E Preferred Stock.

For the year ended December 31, 2020, our cash flows from operations exceeded dividends paid by $293.7 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:

Years Ended December 31,

(Millions of dollars)

Total cash provided by (used in):

Change in cash and cash equivalents 503.5 9.0 (25.2)

Cash and cash equivalents at beginning of period 21.0 12.0 37.2

Cash and cash equivalents at end of period $ 524.5 $ 21.0 $ 12.0

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.

2020 vs. 2019 - Cash flows from operating activities, before changes in operating assets and liabilities, decreased $51.1 million due primarily to higher interest expense, lower realized prices in our Natural Gas Gathering and Processing segment and lower optimization and marketing earnings in our Natural Gas Liquids segment. These decreases were offset partially by an increase in exchange services due to higher volumes and lower rail and pipeline transportation costs in our Natural Gas Liquids segment and lower operating costs across our segments, as discussed in “Financial Results and Operating Information.”

The impact of changes in operating assets and liabilities for 2020 was relatively unchanged compared with 2019, due primarily to net decreases from changes in risk-management assets and liabilities, which include a loss on the settlement of $750 million of our forward-starting interest-rate swaps related to our March 2020 issuance 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 accruals and deferrals. These decreases were offset partially by the changes in commodity imbalances and NGLs and natural gas in storage, which also vary from period to period and with changes in commodity prices.

Investing Cash Flows

2020 vs. 2019 - Cash used in investing activities decreased $1.5 billion due primarily to reduced capital expenditures related to our completed and paused capital-growth projects.

Financing Cash Flows

2020 vs. 2019 - Cash from financing activities decreased $956.0 million due primarily to the issuance of $3.2 billion in long-term debt in 2020, compared with $4.2 billion in long-term debt issuances in 2019, and the repayment of long-term debt and short-term borrowings, offset partially by the issuance of common stock in June 2020.

Cash Flow Analysis for the Year Ended December 31, 2019 vs. 2018 - The cash flow analysis for the year ended December 31, 2019, compared with the year ended December 31, 2018, is included in Part II, Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations of our 2019 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.

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 fair value measurements classified as Level 3 are composed predominantly of exchange-cleared and over-the-counter derivatives to hedge NGL price risk and natural gas basis risk between various transaction locations and the NYMEX Henry Hub. 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. Our commodity derivatives are generally valued using forward quotes provided by third-party pricing services that are validated with other market data. We believe any measurement uncertainty at December 31, 2020, is immaterial as our Level 3 fair value measurements are based on unadjusted pricing information from broker quotes and third-party pricing services.

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 income (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, 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. Due to historic events as a result of COVID-19 impacting supply, demand and commodity prices, we performed a Step 1 analysis in the first quarter 2020 to test our goodwill for impairment and evaluated certain long-lived asset groups and equity investments for impairment.

Goodwill- In the 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. In January 2020, we adopted ASU 2017-04 in which the requirement to calculate the implied fair value of goodwill under the two-step impairment test was eliminated.

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. Under the market approach, we apply EBITDA multiples to forecasted EBITDA. The multiples used are consistent with historical asset transactions. The forecasted cash flows are based on average forecasted cash flows for a reporting unit over a period of years.

Based on the results of our impairment test, we concluded that the carrying value of the Natural Gas Gathering and Processing reporting unit exceeded its estimated fair value, resulting in a noncash impairment charge of $153.4 million. The estimated fair value of our Natural Gas Liquids and Natural Gas Pipelines reporting units substantially exceeded their respective carrying values.

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. At July 1, 2020, we assessed qualitative factors subsequent to our first quarter 2020 impairment charges discussed below, to determine whether it was more likely than not that the fair value of our Natural Gas Liquids and Natural Gas Pipelines reporting units were less than their carrying amount. After assessing qualitative factors (including macroeconomic conditions, industry and market considerations, cost factors and overall financial performance), we determined that it was more likely than not that the fair value of our Natural Gas Liquids and Natural Gas Pipelines reporting units were not less than their respective carrying value, no further testing was necessary and goodwill was not considered impaired. At July 1, 2020, there was no remaining goodwill associated with our Natural Gas Gathering and Processing reporting unit.

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.

In 2020, we evaluated our Natural Gas Gathering and Processing segment asset groups and determined that the carrying value of certain long-lived asset groups in the Powder River Basin, western Oklahoma and Kansas were not recoverable and exceeded their estimated fair value. We recorded noncash impairment charges of $382.2 million, which includes a natural gas processing plant and infrastructure in the Powder River Basin and its related supply contracts and natural gas processing plants and infrastructure in western Oklahoma and Kansas. In our Natural Gas Liquids segment, we recorded noncash impairment charges of $71.6 million related primarily to certain inactive assets, as our expectation for future use of the assets changed.

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.

In 2020, we evaluated our investments in unconsolidated affiliates and concluded that the carrying value of our 10.2% investment in Venice Energy Services Company in our Natural Gas Gathering and Processing segment exceeded its estimated fair value, resulting in a noncash impairment charge of $30.5 million, which includes an impairment to our equity-method goodwill of $22.3 million. We also concluded that the carrying value of our 50% investment in Chisholm Pipeline Company in our Natural Gas Liquids segment exceeded its estimated fair value, resulting in a noncash impairment charge of $7.2 million.

Our impairment tests required 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 used two generally accepted valuation approaches, an income approach and a market approach. Under the income approach, our discounted cash flow analysis included 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 included EBITDA multiples, which were 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.

CONTRACTUAL OBLIGATIONS AND COMMERCIAL COMMITMENTS

The following table sets forth our contractual obligations related to debt, leases and other long-term obligations as of December 31, 2020. For additional discussion of the debt and lease agreements, see Notes F and O, respectively, of the Notes to Consolidated Financial Statements in this Annual Report.

Payments Due by Period

(Millions of dollars)

Guardian Pipeline senior notes 13.7 7.7 6.0 — — — —

Financial and physical derivatives 393.4 377.9 15.5 — — — —

Senior notes - Represents the amount of principal due in each period.

Interest payments on debt - Interest payments are calculated by multiplying long-term debt principal amount by the respective coupon rates.

Operating leases - Our operating leases primarily include leases for pipeline capacity, certain buildings, warehouses, office space, land and equipment, including pipeline equipment, rail cars and information technology equipment.

Finance lease - We lease certain compression facilities under a finance lease that has a fixed-price purchase option in 2028.

Firm transportation and storage contracts - Our Natural Gas Gathering and Processing and Natural Gas Liquids segments are party to fixed-rate contracts for firm transportation and storage capacity.

Financial and physical derivatives - These are obligations arising from our fixed- and variable-price purchase commitments for physical and financial commodity derivatives. Estimated future variable-price purchase commitments are based on market information at December 31, 2020. Actual future variable-price purchase obligations may vary depending on market prices at the time of delivery. Sales of the related physical volumes and net positive settlements of financial derivatives are not reflected in the table above.

Employee benefit plans - Represents projected minimum required cash contributions. We contributed $11.2 million to our defined benefit pension plan in January 2021 and do not expect to make any contributions to our other postretirement plans in

the remainder of 2021. See Note K of the Notes to Consolidated Financial Statements in this Annual Report for discussion of our employee benefit plans.

Purchase commitments and other - Purchase commitments include payments for NGL fractionation capacity and other contractual commitments. Purchase commitments exclude commodity purchase contracts, which are included in the “Financial and physical derivatives” amounts.

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,” “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 recent outbreak of COVID-19 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, climate change initiatives, 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 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 recent 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 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, 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;

•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.

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 C 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 for the periods indicated:

(Millions of dollars)

Crude oil and NGLs $ 20.0 $ 26.1

Total change in estimated fair value of commodity contracts $ 30.6 $ 38.8

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 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 periods indicated:

VolumesHedged Average Price PercentageHedged

NGLs - excluding ethane (MBbl/d) - Conway/Mont Belvieu 10.4 $ 0.51 / gallon 60%

Condensate (MBbl/d) - WTI-NYMEX 2.9 $ 42.87 / Bbl 74%

Natural gas (BBtu/d) - NYMEX and basis 118.6 $ 2.64 / MMBtu 75%

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, 2020. 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 year ending December 31, 2021, by $2.7 million;

•a $1.00 per barrel change in the price of crude oil would change adjusted EBITDA for the year ending December 31, 2021, by $1.4 million; and

•a $0.10 per MMBtu change in the price of residue natural gas would change adjusted EBITDA for the year ending December 31, 2021, by $5.8 million.

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 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 2020, we settled $750 million of our forward-starting interest-rate swaps related to our underwritten public offerings of $1.75 billion senior unsecured notes and the remaining $1.3 billion of our interest-rate swaps used to hedge our LIBOR-based interest payments upon repayment of the remaining balance of our $1.5 Billion Term Loan Agreement.

At December 31, 2020 and 2019, we had forward-starting interest-rate swaps with notional amounts totaling $1.1 billion and $1.8 billion, respectively, to hedge the variability of interest payments on a portion of our forecasted debt issuances. At December 31, 2019, we had interest-rate swaps with notional amounts totaling $1.3 billion to hedge the variability of our LIBOR-based interest payments, all of which have settled as of December 31, 2020. All of our interest-rate swaps are designated as cash flow hedges. At December 31, 2020, we had derivative liabilities of $203.4 million related to these interest-rate swaps. At December 31, 2019, we had derivative assets of $0.6 million and derivative liabilities of $201.9 million related to these interest-rate swaps.

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 for the periods indicated:

(Millions of dollars)

Forward-starting interest-rate swaps $ 12.9 $ 40.5

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 C 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 2020 and 2019, approximately 90% 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 NGL products. In 2020 and 2019, approximately 75% and 80%, 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 2020 and 2019, approximately 85% 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.

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, 2020 and 2019, 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, 2020, 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, 2020, 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, 2020 and 2019, and the results of itsoperations and itscash flows for each of the three years in the period ended December 31, 2020 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, 2020, based on criteria established in Internal Control - Integrated Framework(2013)issued by the COSO.

Change in Accounting Principle

As discussed in Note A to the consolidated financial statements, the Company changed the manner in which it accounts for revenue from contracts with customers in 2018.

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.

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 matters communicated beloware mattersarising from the current period audit of the consolidated financial statements that were communicated or required to be communicated to the audit committee and that (i) relate 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 matters below, providing separate opinions on the critical audit matters or on the accounts or disclosures to which they relate.

Valuation of Level 3 Commodity Derivative Assets and Liabilities

As described in Notes A and B to the consolidated financial statements, the Company’s level 3 commodity contracts derivative assets and liabilities total $103.8 million and $135.1 million, respectively, as of December 31, 2020. As disclosed by management, commodity price risk includes basis risk, which is the difference in price between various locations where commodities are purchased and sold. Management records all derivative instruments at fair value, with the exception of normal purchases and normal sales transactions that are expected to result in physical delivery. Many of the contracts in its derivative portfolio are executed in liquid markets where price transparency exists. Fair value measurements classified as Level 3 are composed predominantly of exchange-cleared and over-the-counter derivatives to hedge NGL price risk and natural gas basis risk. 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. The commodity derivatives are generally valued using forward quotes provided by third-party pricing services that are validated with other market data.

The principal considerations for our determination that performing procedures relating to the valuation of level 3 commodity derivative assets and liabilities is a critical audit matter are (i) the significant judgment by management to determine the fair value of these derivatives; (ii) a high degree of auditor judgment, subjectivity and effort in evaluating audit evidence related to the valuation due to the use of internally developed commodity price curves that incorporate market data from broker quotes and third-party pricing services; and (iii) the audit effort involved the use of professionals with specialized skill and knowledge.

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 valuation of level 3 commodity derivative assets and liabilities, including controls over the Company’s model, significant assumptions, and data. These procedures alsoincluded, among others, the involvement of professionals with specialized skill and knowledge to assist in developing an independent estimate of the level 3 commodity derivative assets and liabilities and comparison of the independent estimate to management’s estimate to evaluate the reasonableness of management’s estimate. Developing the independent estimate involved testing the completeness and accuracy of data provided by management and evaluating management’s assumptions related to the internally developed commodity price curves which incorporate market data from broker quotes and third-party pricing services.

Long-Lived Asset Impairment – Asset Group in the Powder River Basin

As described in NotesA and B to the consolidated financial statements, the Company’s net property, plant and equipment balance was $19.2 billion as of December 31, 2020. Management assesses the Company’s 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, the Company will record an impairment loss equal to the difference between the carrying value and the fair value of the long-lived asset. In 2020, Management evaluated the Natural Gas Gathering and Processing segment asset groups and determined that the carrying value of certain long-lived asset groups were not recoverable and exceeded their estimated fair value. The Company recorded noncash impairment charges of $382.2 million in its Natural Gas Gathering and Processing segment, of which a portion includes a natural gas processing plant and infrastructure in the Powder River Basin and its related supply contracts. To estimate the fair value, Management used the income approach. Under the income approach, the discounted cash flow analysis included the following inputs that are not readily available: a discount rate reflective of industry cost of capital, estimated contract rates, volumes, operating margins, operating and maintenance costs, and capital expenditures.

The principal considerations for our determination that performing procedures relating to long-lived asset impairments of an asset group in the Powder River Basin is a critical audit matter are (i) the significant judgment by management when developing the fair value of the long-lived asset and (ii) a high degree of auditor judgment, subjectivity, and effort in performing procedures andevaluating management’s significant assumptions related to volumes and operating margins.

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 management’s long-lived asset impairment assessment, including the controls over the valuation of long-lived assets. These procedures also included, among others (i) testing management’s process for developing the fair value estimate of an asset group in the Powder River Basin; (ii) evaluating the appropriateness of the discounted cash flow model; (iii) testing the completeness and accuracy of underlying data used in the model; and (iv) evaluating the reasonableness of the significant assumptions used by management related to the volumes and operating margins. Evaluating management’s assumptions related to the volumes and operating margins involved evaluating whether the assumptions used by management were reasonable considering (i) the current and past performance of the asset group and (ii) whether these assumptions were consistent with evidence obtained in other areas of the audit.

/s/ PricewaterhouseCoopers LLP

Tulsa, Oklahoma

February 23, 2021

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

ONEOK, Inc. and Subsidiaries

CONSOLIDATED STATEMENTS OF INCOME

Years Ended December 31,

(Thousands of dollars, except per share amounts)

Revenues

Impairment charges (Note A) 607,200 — —

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

Allowance for equity funds used during construction 23,662 64,815 7,962

Less: Net income attributable to noncontrolling interests — — 3,329

Average shares (thousands)

See accompanying Notes to Consolidated Financial Statements.

ONEOK, Inc. and Subsidiaries

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

Years Ended December 31,

(Thousands of dollars)

Other comprehensive income (loss), net of tax

Less: Comprehensive income attributable to noncontrolling interests — — 3,329

See accompanying Notes to Consolidated Financial Statements.

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 M) 805,032 861,844

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 F) $ 7,650 $ 7,650

Short-term borrowings (Note F) — 220,000

Operating lease liability (Note O) 13,610 1,883

Deferred credits and other liabilities

Commitments and contingencies (Note N)

Equity (Note G)

ONEOK shareholders’ equity:

Accumulated other comprehensive loss (Note H) (551,449) (374,000)

Retained earnings — —

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

Distributions to noncontrolling interests — — (3,500)

Acquisition of noncontrolling interests — — (195,000)

Supplemental cash flow information:

Cash paid for income taxes, net of refunds $ 342 $ 2,690 $ 2,225

See accompanying Notes to Consolidated Financial Statements.

ONEOK, Inc. and Subsidiaries

CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY

ONEOK Shareholders’ Equity

(Shares) (Thousands of dollars)

Cumulative effect adjustment for adoption of ASUs (a) — — — — —

Net income — — — — —

Other comprehensive income — — — — —

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

Common stock dividends - $3.245 per share (Note G) — — — — (144,805)

Distributions to noncontrolling interests — — — — —

Contributions from noncontrolling interests — — — — —

Acquisition of noncontrolling interests (Note G) — — — — (21,220)

Other, net — — — — 8,964

Net income — — — — —

Other comprehensive loss (Note H) — — — — —

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

Common stock issued — — — — (7,667)

Common stock dividends - $3.53 per share (Note G) — — — — (180,421)

Other, net — — — — (23,155)

Net income — — — — —

Other comprehensive loss (Note H) — — — — —

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

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

Other, net — — — — 8,319

ONEOK, Inc. and Subsidiaries

CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY

(Continued)

ONEOK Shareholders’ Equity

(Thousands of dollars)

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

Distributions to noncontrolling interests — — — (3,500) (3,500)

Contributions from noncontrolling interests — — — 16,449 16,449

Acquisition of noncontrolling interests (Note G) — — — (173,780) (195,000)

Other, net — — — — 8,964

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

Other, net — — — — (23,155)

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

Other, net — — — — 8,319

(a) - Includes cumulative effect for adoption of the following: ASU 2014-09, “Revenue from Contracts with Customers (Topic 606)”; ASU 2017-12, “Derivatives and Hedging (Topic 815): Targeted Improvements to Accounting for Hedging Activities”; and ASU 2018-02, “Income Statement - Reporting Comprehensive Income (Topic 220): Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income.”

See accompanying Notes to Consolidated Financial Statements.

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 NGL products, 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, Missouri, Nebraska, Iowa and Illinois. We have a 50% ownership interest in Overland Pass Pipeline Company, 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 products, including unleaded gasoline and diesel, from Kansas to Iowa.

Our Natural Gas Pipelines segment, through its wholly owned assets, provides intrastate and interstate transportation and storage services to end users. We have 50% ownership interests in Northern Border Pipeline and Roadrunner, which provide transportation services to various end users. Our interstate pipelines are regulated by the FERC and are located in North Dakota, Minnesota, Wisconsin, Illinois, Indiana, Kentucky, Tennessee, Oklahoma, Texas and New Mexico. Our intrastate natural gas pipeline and storage assets are located in Oklahoma, Kansas and Texas. Our assets connect major natural gas producing basins and market hubs with end-use customers.

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 underlying fair value of 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 M 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, provisions for uncollectible accounts receivable, 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 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 and prices.

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.

Many 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 LIBOR yield curve. The fair value of our forward-starting interest-rate swaps is determined using financial models that incorporate the implied forward LIBOR 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 over-the-counter interest-rate derivatives.

•Level 3 - fair value 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. These balances are composed predominantly of exchange-cleared and over-the-counter derivatives to hedge NGL price risk and natural gas basis risk between various transaction locations and the NYMEX Henry Hub. Our commodity derivatives are generally valued using forward quotes provided by third-party pricing services that are validated with other market data. We believe any measurement uncertainty at December 31, 2020, is immaterial as our Level 3 fair value measurements are based on unadjusted pricing information from broker quotes and third-party pricing services. We do not believe that our Level 3 fair value estimates have a material impact on our results of operations, as our derivatives are primarily accounted for as hedges.

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 for which fair value is determined using multiple inputs within a single level, based on the lowest level input that is significant to the fair value measurement in its entirety.

See Note B 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.

Upon adoption of Topic 606 in January 2018, we determined that certain Natural Gas Gathering and Processing segment fee with POP contracts and Natural Gas Liquids segment exchange services contracts that include the purchase of commodities are supplier contracts. Contractual fees in these identified contracts are recorded as a reduction of the commodity purchase price in cost of sales and fuel. In 2017 and prior periods, these fees were recorded as services revenue.

Performance Obligations and Revenue Sources - Revenue sources are disaggregated in Note Q 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 NGL products 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 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.

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 NGL products 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 nomination 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.

See Note P 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 contributions in aid of construction received from customers for which revenue is recognized over the contract periods, which range from 5 to 10 years, and deferred revenue on NGL storage contracts for which revenue is recognized over a one-year term.

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 of our customer’s NGLs.

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. Upon adoption of ASU 2016-13 in January 2020, 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, 2020, our allowance for credit losses was not material. See “Recently Issued Accounting Standards Update” table below for more information.

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 capitalized to 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 NGL products 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 NGL products 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.

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 B and C 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 composite depreciation rates to functional groups of property having similar economic circumstances. 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.

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 D 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. At July 1, 2020, we assessed qualitative factors subsequent to our first quarter 2020 impairment charges discussed below to determine whether it was more likely than not that the fair value of our Natural Gas Liquids and Natural Gas Pipelines reporting units were less than their carrying amount. After assessing qualitative factors (including macroeconomic conditions, industry and market considerations, cost factors and overall financial performance), we determined that it was more likely than not that the fair value of our Natural Gas Liquids and Natural Gas Pipelines reporting units were not less than their respective carrying value, no further testing was necessary and goodwill was not considered impaired. At July 1, 2020, there was no remaining goodwill associated with our Natural Gas Gathering and Processing reporting unit.

Late in the first quarter 2020, we experienced a significant decline in our share price and market capitalization as the energy industry experienced historic events that led to a simultaneous demand and supply disruption. The World Health Organization declared COVID-19 a global pandemic and recommended containment and mitigation measures worldwide, which contributed to a massive economic slowdown and decreased demand for crude oil, natural gas and NGLs. In addition, Saudi Arabia and Russia increased production of crude oil as the two countries competed for market share. As a result, the global supply of crude oil significantly exceeded demand and led to a collapse in crude oil prices. Due to the impact of these events, we performed a Step 1 analysis in the first quarter 2020 to test our goodwill for impairment and evaluated certain long-lived asset groups and equity investments for impairment.

Goodwill - In the 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. In January 2020, we adopted ASU 2017-04 in which the requirement to calculate the implied fair value of goodwill under the two-step impairment test was eliminated.

Based on the results of our impairment test, we concluded that the carrying value of the Natural Gas Gathering and Processing reporting unit exceeded its estimated fair value, resulting in a noncash impairment charge of $153.4 million, which is included within impairment charges in our Consolidated Statement of Income for the year ended December 31, 2020. The estimated fair value of our Natural Gas Liquids and Natural Gas Pipelines reporting units substantially exceeded their respective carrying values.

charges are included within impairment charges in our Consolidated Statement of Income for the year ended December 31, 2020.

See Notes D, E and M for our long-lived assets, goodwill and intangible assets and investments in unconsolidated affiliates disclosures, 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. In our Consolidated Financial Statements and our Notes to Consolidated Financial Statements, regulated operations are defined pursuant to Financial Accounting Standards Board’s (FASB) ASC 980, Regulated Operations. 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.

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 K 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. During 2020, 2019 and 2018, 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 L 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 2020, 2019 and 2018. Actual results may differ from our estimates resulting in an impact, positive or negative, on earnings.

See Note N 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 J 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 I 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 to investors 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 Q for our segments disclosures.

Reclassifications - Certain reclassifications have been made in the prior-year financial statements to conform to the current-year presentation.

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 listed below were assessed and determined to be either not applicable or clarifications of ASUs previously issued or listed below. Except as discussed below, there have been no new accounting pronouncements that have become effective or have been issued that are of significance or potential significance to us. The following table provides a brief description of recently adopted accounting pronouncements and our analysis of the effects on our financial statements:

Standards that were adopted as of December 31, 2020

Standards that are not yet adopted as of December 31, 2020

B. FAIR VALUE MEASUREMENTS

Recurring Fair Value Measurements - The following tables set forth our recurring fair value measurements for the periods 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, 2020, we held no cash and posted $63.1 million of cash with various counterparties, including $35.1 million of cash collateral that is offsetting derivative net liability positions under master-netting arrangements in the table above. The remaining $28.0 million of cash collateral in excess of derivative net liability positions is included in other current assets in our Consolidated Balance Sheet.

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

(Thousands of dollars)

Derivative assets

Commodity contracts

Derivative liabilities

Commodity contracts

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) 2020 2019

(Thousands of dollars)

Net assets at beginning of period $ 30,772 $ 40,484

Total changes in fair value:

Settlements included in net income (a) (31,660) (40,344)

OKE US Equity

OKE · 10-K · period ended 2020-12-31

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

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

OKE US Equity☆

OKE · 10-K · period ended 2020-12-31

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

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

OKE US Equity