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Item 7. Management’s Discussion and Analysis

2022-03-01 compared with 2021-02-23 · 155 added, 293 removed, 331 unchanged (58% of the section changed)

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

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.

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

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

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

Ethane volumes under long-term contracts delivered to our NGL system increased approximately 55 MBbl/d to an average of 430 MBbl/d in 2021, compared with 375 MBbl/d in 2020, due primarily to changes in ethane extraction economics.

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

Ethane recovery opportunities will fluctuate based on regional natural gas pricing and ethane economics.

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

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 Approximate

Natural Gas Gathering and Processing

( In millions )

Demicks Lake I plant and related infrastructure

200 MMcf/d processing plant and related gathering infrastructure in the core of the Williston Basin $400 Completed

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

Demicks Lake II plant and related infrastructure

200 MMcf/d processing plant and related gathering infrastructure in the core of the Williston Basin $410 Completed

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

Bear Creek plant expansion and related infrastructure 200 MMcf/d processing plant expansion and related gathering infrastructure in the Williston Basin $405 Paused (c)

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

Project Scope Approximate

Natural Gas Gathering and Processing ( In millions )

Bear Creek plant expansion and related infrastructure 200 MMcf/d processing plant expansion and related gathering infrastructure in the Williston Basin $405 Completed

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

Demicks Lake III plant 200 MMcf/d processing plant in the core of the Williston Basin $188 (b) First Quarter 2023

Supported by acreage dedications with primarily fee-based contracts

Natural Gas Liquids

Elk Creek pipeline and related infrastructure

900-mile NGL pipeline from the Williston Basin to the Mid-Continent region, with capacity of up to 240 MBbl/d, and related infrastructure $1,400 Completed

December 2019

Anchored by long-term contracts

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

Arbuckle II pipeline and related infrastructure

530-mile NGL pipeline from the STACK area to Mont Belvieu, Texas, and related infrastructure $1,360 Completed

Supported by long-term contracts

Expansion capability up to 1 MMBbl/d

MB-4 fractionator and related infrastructure 125 MBbl/d NGL fractionator in Mont Belvieu, Texas, and related infrastructure, which includes additional NGL storage in Mont Belvieu $575 Completed

March 2020 (d)

Fully contracted with long-term contracts

ONEOK West Texas NGL pipeline expansion and Arbuckle II connection Increasing mainline capacity by 80 MBbl/d with additional pump facilities and pipeline looping $295 Completed

June 2020 (e)

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

Supported by long-term dedicated production from six third-party processing plants expected to produce up to 60 MBbl/d

Bakken NGL pipeline extension

75-mile NGL pipeline in the Williston Basin connecting to a third-party processing plant $100 Completed

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

Arbuckle II extension project and additional gathering infrastructure Provide additional takeaway capacity in the STACK area $240 Completed

Allow increasing volumes on the Elk Creek pipeline access to fractionation capacity at Mont Belvieu, Texas August 2020

Arbuckle II pipeline expansion Increasing mainline capacity with additional pump facilities $60 Paused (c)

Increases capacity to 500 MBbl/d

MB-5 fractionator and related infrastructure

125 MBbl/d NGL fractionator in Mont Belvieu, Texas, and related infrastructure, which includes additional NGL storage in Mont Belvieu $750 Paused (c)

Fully contracted with long-term contracts

ONEOK West Texas NGL pipeline expansion Increasing mainline capacity by 40 MBbl/d $145 Paused (c)

Supported by long-term dedicated production from third-party processing plants expected to produce up to 45 MBbl/d

Mid-Continent fractionation facility expansions

65 MBbl/d of expansions at our Mid-Continent NGL facilities $150 Paused (c)

Arbuckle II pipeline expansion Increased mainline capacity with additional pump facilities $60 Completed

Increased capacity to 500 MBbl/d

MB-5 fractionator 125 MBbl/d NGL fractionator in Mont Belvieu, Texas $750 (c) Third Quarter 2023

(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.

(b) - In November 2021, we announced that we restarted construction of the Demicks Lake III natural gas processing plant.

Upon announcement, the expected cost to complete was approximately $140 million.

Upon announcement, the expected cost to complete was approximately $250 million.

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

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

Table of Cont ents

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

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.

Dividends - During 2021, we paid common stock dividends totaling $3.74 per share, which is consistent with the prior year.

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

FINANCIAL RESULTS AND OPERATING INFORMATION

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(3) diluted EPS;

and (4) the following non-GAAP financial measures:

adjusted EBITDA and distributable cash flow.

and (4) adjusted EBITDA.

We evaluate segment operating results using adjusted EBITDA and our operating metrics, which include various volume and rate statistics that are relevant for the respective segment.

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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.

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

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

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.

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

Adjusted EBITDA should not be considered an alternative to net income, EPS or any other measure of financial performance presented in accordance with GAAP.

Additionally, this calculation may not be comparable with similarly titled measures of other companies.

Consolidated Operations

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Adjusted EBITDA $ 3,379.7 $ 2,723.7 $ 2,580.2 656.0 143.5

Distributable cash flow $ 1,881.6 $ 2,016.1 $ 1,822.4 (134.5) 193.7

Capital expenditures $ 696.9 $ 2,195.4 $ 3,848.3 (1,498.5) (1,652.9)

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

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

Table of Cont ents

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.

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;

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

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

• Natural Gas Liquids - increases of $421.4 million in exchange services related primarily to higher volumes in the Rocky Mountain region, the Mid-Continent region and Permian Basin and wider commodity price differentials, and $98.3 million in optimization and marketing.

These increases were offset partially by a decrease of $46.2 million from the impact of Winter Storm Uri in exchange services;

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

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

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

• an increase of $43.0 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;

• 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.

Net income and diluted EPS increased due primarily to the items discussed above and noncash impairment charges related to equity investments in our Natural Gas Gathering and Processing and Natural Gas Liquids segments in the prior year.

These increases were offset partially by higher income taxes, higher interest expense related to lower capitalized interest and lower equity AFUDC due to completed projects, lower equity in net earnings from investments and a gain in 2020 on extinguishment of debt related to open market repurchases.

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

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

Selected Financial Results and Operating Information for the Year Ended December 31, 2020 vs.

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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.

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

Table of Cont ents

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

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( Millions of dollars )

NGL sales $ 775.9 $ 1,024.3 $ 1,567.2 (248.4) (542.9)

Condensate sales 113.5 200.1 208.8 (86.6) (8.7)

NGL and condensate sales $ 2,821.2 $ 889.4 $ 1,224.4 1,931.8 (335.0)

Residue natural gas sales 1,483.9 771.5 966.1 712.4 (194.6)

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Cost of sales and fuel (exclusive of depreciation and operating costs) (3,226.1) (844.0) (1,302.3) 2,382.1 (458.3)

(844.0) (1,302.3) (2,041.4) (458.3) (739.1)

Operating costs, excluding noncash compensation adjustments

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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.

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;

• 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.

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

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

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

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

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

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

Years Ended December 31,

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

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.

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

Our average fee rate increased due primarily to production curtailments in the second quarter 2020 on producer contracts with higher fees and lower POP components in the Rocky Mountain region.

As these curtailed volumes have returned to our system and producer activity has continued to increase, the Rocky Mountain region’s contribution to our average fee rate increased in 2021.

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

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

Table of Cont ents

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

Natural Gas Liquids

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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.

In 2021, we connected one third-party natural gas processing plant in the Permian Basin and one third-party natural gas processing plant in the Rocky Mountain region to our NGL system.

In addition, one affiliate natural gas processing plant in the Rocky Mountain region connected to our system was expanded.

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

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Cost of sales and fuel (exclusive of depreciation and operating costs) (11,939.7) (5,108.6) (6,690.9) 6,831.1 (1,582.3)

(5,108.6) (6,690.9) (9,176.8) (1,582.3) (2,485.9)

Operating costs, excluding noncash compensation adjustments (499.4) (396.4) (434.4) 103.0 (38.0)

(396.4) (434.4) (378.3) (38.0) 56.1

Equity in net earnings from investments 21.0 39.9 65.1 (18.9) (25.2)

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2020 - Adjusted EBITDA increased $346.4 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;

• 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;

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

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

◦ $98.9 million related to wider commodity price differentials,

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

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

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

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

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

• a decrease of $18.9 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.

Table of Cont ents

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

Years Ended December 31,

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

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.

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

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

Natural Gas Pipelines

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2020 - Adjusted EBITDA increased $90.4 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;

• 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.

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

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

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

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

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

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

Table of Cont ents

Years Ended December 31,

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(a) - Includes volumes for consolidated entities only.

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 2022.

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:

In February 2021, our subsidiary, Midwestern Gas Transmission Company (Midwestern), filed a proposed change in rates pursuant to Section 4 of the Natural Gas Act with the FERC.

In February 2022, Midwestern filed a Stipulation and Offer of Settlement with the FERC for approval.

Pending approval by the FERC, the proposed settlement is not expected to impact materially our results of operations.

NON-GAAP FINANCIAL MEASURES

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

Years Ended December 31,

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2021 2020 2019

Reconciliation of net income to adjusted EBITDA, distributable cash flow and dividend coverage ( Thousands of dollars, except per share amounts and coverage ratios )

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

Net income $ 1,499,706 $ 612,809 $ 1,278,577

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Adjusted EBITDA (b) $ 3,379,740 $ 2,723,673 $ 2,580,187

Interest expense, net of capitalized interest (712,886) (491,773) (469,620)

Maintenance capital (136,920) (195,631) (188,420)

Equity in net earnings from investments (143,241) (154,541) (158,383)

Distributions received from unconsolidated affiliates 176,160 257,644 197,285

Other (b) (25,195) 20,227 (5,994)

Distributable cash flow 1,881,591 2,016,113 1,822,389

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

Distributable cash flow to shareholders 1,880,491 2,015,013 1,821,289

Dividends paid (1,604,266) (1,456,528) (1,333,958)

Distributable cash flow in excess of dividends paid $ 276,225 $ 558,485 $ 487,331

Dividends paid per share $ 3.74 $ 3.53 $ 3.245

Dividend coverage ratio 1.17 1.38 1.37

Number of shares used in computation ( thousands )

428,948 412,614 411,081

(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,

( Unaudited )

2020 2019 2018

Reconciliation of segment adjusted EBITDA to adjusted EBITDA ( Thousands of dollars )

Reconciliation of segment adjusted EBITDA to adjusted EBITDA

Segment adjusted EBITDA:

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Natural Gas Pipelines 527,810 437,426 408,816

Other (a) 18,970 2,956 9,058

Other (b) (836) 18,970 2,956

Adjusted EBITDA $ 3,379,740 $ 2,723,673 $ 2,580,187

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

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

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

CONTINGENCIES

See Note N of the Notes to Consolidated Financial Statements in this Annual Report for a discussion of regulatory 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.

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

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

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

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

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LIQUIDITY AND CAPITAL RESOURCES

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

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.

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

We believe we have sufficient liquidity due to our $2.5 Billion Credit Agreement, which expires in June 2024 and access to $1.0 billion available through our “at-the-market” equity program.

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

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

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

Guarantees and Cash Management - In 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.

Guarantees and Cash Management - In 2020, the SEC amended Rule 3-10 of Regulation S-X and created Rule 13-01 to simplify disclosure requirements related to certain registered securities.

We and ONEOK Partners are issuers of certain public debt securities.

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

We had a working capital (defined as current assets less current liabilities) surplus of $525.2 million and a working capital deficit of $550.0 million as of December 31, 2020, and December 31, 2019, respectively.

We had a working capital (defined as current assets less current liabilities) deficit of $810.2 million and a working capital surplus of $525.2 million as of December 31, 2021, and December 31, 2020, respectively.

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

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

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

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

our working capital 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.

our working capital deficit at December 31, 2021, was driven primarily by current maturities of long-term debt and our working capital surplus at December 31, 2020, was driven primarily by cash on hand.

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

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

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

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Other options to obtain financing include, but are not limited

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to, issuing common stock, loans from financial institutions, issuance of convertible debt securities or preferred equity securities, asset securitization and the sale and lease-back of facilities.

Debt 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.

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.

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.

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

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

In connection with these open market repurchases, we recognized $22.3 million of net gains on extinguishment of debt.

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.

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

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

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

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

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

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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:

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

Capital Expenditures 2021 2020 2019

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Total capital expenditures $ 696.9 $ 2,195.4 $ 3,848.3

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.

Total capital expenditures decreased in 2021, compared with 2020, due primarily to our completed capital-growth projects in the prior year.

We expect our 2022 capital expenditures to increase relative to 2021 due to our publicly announced capital-growth projects.

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

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S&P BBB A-2 Stable

Fitch (a) BBB F2 Stable

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

Fitch BBB F2 Stable

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.

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An adverse credit rating change alone is not a default under our $2.5 Billion Credit Agreement.

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In the normal course of business, our counterparties provide us with secured and unsecured credit.

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

In 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.

In 2021, we paid common stock dividends of $3.74 per share, which is consistent with prior year.

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

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

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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.

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.

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

The changes in operating assets and liabilities decreased operating cash flows $141.8 million for the year ended December 31, 2021, compared with a decrease of $160.5 million for the same period in 2020.

The change is due primarily to changes in accounts payable resulting from the timing of payments to vendors, suppliers and other third parties and changes in commodity

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prices, which vary from period to period;

changes in risk-management assets and liabilities, which include a loss in 2020 on the settlement of $750 million of our forward interest-rate swaps related to our March 2020 issuances of senior unsecured notes and changes in the fair value of risk-management assets and liabilities, which vary from period to period and with changes in commodity prices and interest rates;

and changes in other assets and liabilities;

offset partially by changes in accounts receivable resulting from the timing of receipt of cash from customers and NGLs and natural gas in storage, both of which vary from period to period and with changes in commodity prices.

Investing Cash Flows

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.

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

Financing Cash Flows

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.

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

Cash Flow Analysis for the Year Ended December 31, 2020 vs.

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CRITICAL ACCOUNTING POLICIES AND ESTIMATES

reported amounts of assets and liabilities, and the disclosure of contingent assets and liabilities at the date of the Consolidated Financial Statements.

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.

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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.

Our commodity derivatives are generally valued using quoted prices published by an exchange.

Our fair value measurements classified as Level 3 are composed predominantly of exchange-cleared and over-the-counter derivatives to hedge NGL price risk at certain market locations.

These measurements are based on inputs that may include one or more unobservable inputs, including internally developed commodity price curves, that incorporate market data from broker quotes and third-party pricing services.

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, 2021, is immaterial as our Level 3 fair value measurements are based on unadjusted pricing information from broker quotes and third-party pricing services.

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The accounting for changes in the fair value of a derivative instrument depends on whether it qualifies and has been designated as part of a hedging relationship.

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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.

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

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

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

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

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

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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.

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

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

In a Step 1 analysis, an assessment is made by comparing the fair value of a reporting unit with its carrying amount, including goodwill.

If the carrying value of a reporting unit exceeds its fair value, an impairment loss is recognized in an amount equal to that excess, limited to the total amount of goodwill allocated to that reporting unit.

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:

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

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

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

a discount rate reflective of industry cost of capital, our estimated contract rates, volumes, operating margins, operating and maintenance costs and capital expenditures.

Under the market approach, our inputs 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.

Under the market approach, our inputs include EBITDA multiples, which are estimated from recent peer acquisition transactions, and forecasted EBITDA, which incorporates inputs similar to those used under the income approach.

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

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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

Contractual Obligations Total 2021 2022 2023 2024 2025 Thereafter

( Millions of dollars )

Senior notes $ 14,347.9 $ — $ 1,437.7 $ 925.0 $ 500.0 $ 887.0 $ 10,598.2

Guardian Pipeline senior notes 13.7 7.7 6.0 — — — —

Interest payments on debt 9,710.4 704.2 675.0 631.4 586.8 555.7 6,557.3

Operating leases 116.1 16.5 15.1 13.8 12.5 11.1 47.1

Finance lease 35.1 4.5 4.5 4.5 4.5 4.5 12.6

Firm transportation and storage contracts

516.7 70.9 60.9 55.8 53.4 47.9 227.8

Financial and physical derivatives 393.4 377.9 15.5 — — — —

Employee benefit plans 57.0 11.2 11.8 12.9 10.3 10.8 —

Purchase commitments and other 369.6 83.8 83.4 81.6 41.1 40.7 39.0

Total $ 25,559.9 $ 1,276.7 $ 2,309.9 $ 1,725.0 $ 1,208.6 $ 1,557.7 $ 17,482.0

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.

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FORWARD-LOOKING STATEMENTS

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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.

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

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

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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;

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

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

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• 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;

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

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

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

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

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

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

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

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

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

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

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• 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;

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

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

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

• the mechanical integrity of facilities and pipelines operated;

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

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

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

What changed 10-K

Item 7. Management’s Discussion and Analysis