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Item 7. Management’s Discussion and Analysis

2023-02-28 compared with 2022-03-01 · 202 added, 160 removed, 326 unchanged (53% of the section changed)

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

Market Conditions - We experienced earnings growth 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.

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

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

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

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

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

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

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

2022 Insurance Accruals

(Millions of dollars)

Business interruption $ 96.1

Noncash property losses 45.6

Medford response expenses 9.0

Total insurance recoveries accrued (a) $ 150.7

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

The MB-6 fractionator will have the capability to produce purity ethane instead of the ethane/propane mix previously produced at the Medford facility.

The 125 MBbl/d capacity of the MB-6 fractionator is expected to be economically equivalent to the capacity lost at Medford.

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

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

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

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

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

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

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

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

however, price fluctuations are expected to continue.

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

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

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

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

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

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

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

Project Scope 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

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

Supported by acreage dedications with primarily fee-based contracts

Natural Gas Liquids

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

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

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

Natural Gas Pipelines

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

(a) - Excludes capitalized interest/AFUDC.

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

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

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.

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

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

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

The remainder was used for general corporate purposes.

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

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

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

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

In February 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.

In February 2023, we paid a quarterly common stock dividend of $0.955 per share ($3.82 per share on an annualized basis), an increase of 2% compared with the same quarter in the prior year.

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

FINANCIAL RESULTS AND OPERATING INFORMATION

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Consolidated Operations

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

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

Years Ended December 31, 2022 vs.

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Impairment charges — — 607.2 — (607.2)

(Gain) loss on sale of assets (1.4) (1.3) 2.6 0.1 3.9

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

Operating income $ 2,807.4 $ 2,596.3 $ 1,361.4 211.1 1,234.9

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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.

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.

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.

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

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

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

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

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

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

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

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

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

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

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

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

Selected Financial Results and Operating Information for the Year Ended December 31, 2021 vs.

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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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Capital expenditures $ 444.9 $ 275.2 $ 446.1 169.7 (170.9)

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

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

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

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.

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

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

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

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

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

Years Ended December 31,

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(a) - Includes volumes for consolidated entities only.

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

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.

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

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

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

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

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

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

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.

Our growth strategy is focused around connecting

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

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

In 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.

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

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

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

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NGL and condensate sales $ 18,329.3 $ 13,653.1 $ 6,409.3 4,676.2 7,243.8

Exchange service revenues and other 559.2 497.8 424.2 61.4 73.6

Exchange service and other revenues 557.5 559.2 497.8 (1.7) 61.4

Transportation and storage revenues 180.0 179.6 182.9 0.4 (3.3)

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

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

2021 - Adjusted EBITDA increased $131.6 million primarily as a result of the following:

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

◦ $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.

Table of Cont ents

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

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

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

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

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

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

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

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

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

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

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

Years Ended December 31,

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$ 0.04 $ (0.01) $ 0.01

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

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.

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

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

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

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

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

Natural Gas Pipelines

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

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

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

and Mexico border.

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

Additionally, the proposed border facilities would connect at the international boundary with a new pipeline under development in Mexico for delivery to a liquefied natural gas export facility on the west coast of Mexico.

The final investment decision on the pipeline is expected by mid-2023.

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

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

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

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

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

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

• 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

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

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

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

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

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

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

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

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

Years Ended December 31,

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(a) - Includes volumes for consolidated entities only.

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

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

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

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

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

In April 2022, the FERC initiated a review of Guardian’s rates pursuant to Section 5 of the Natural Gas Act.

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

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

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

NON-GAAP FINANCIAL MEASURES

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Depreciation and amortization 626,132 621,701 578,662

Income tax expense 484,498 189,507 372,414

Income taxes 527,424 484,498 189,507

Impairment charges — — 644,930

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

Equity AFUDC and other noncash items (1,681) (23,661) (65,811)

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

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

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

(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.

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

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

CONTINGENCIES

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

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

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.

Table of Cont ents

LIQUIDITY AND CAPITAL RESOURCES

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

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

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

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

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

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

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

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

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

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

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

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

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

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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.

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

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

For additional information on our and ONEOK Partners’ indebtedness, see Note 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.

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

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

Our centralized cash management program provides that funds in excess of the daily needs of our operating subsidiaries are concentrated, consolidated or otherwise made available for use by other entities within our consolidated group.

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

As of December 31, 2021, we are in compliance with all covenants of our $2.5 Billion Credit Agreement.

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

Other options to obtain financing include, but are not limited

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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.

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.

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

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

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

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

The remainder was used for general corporate purposes.

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

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

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

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

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

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

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

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

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

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Total capital expenditures $ 1,202.1 $ 696.9 $ 2,195.4

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.

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

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

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

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

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

Rating Agency Long-Term Rating Short-Term Rating Outlook

Moody’s Baa3 Prime-3 Stable

Moody’s Baa3 Prime-3 Positive

S&P BBB A-2 Stable

Fitch BBB F2 Stable

Our credit ratings, which are investment grade, may be affected by a material change in our financial ratios or a material event affecting our business and industry.

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

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

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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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In 2022, 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.

In February 2023, we paid a quarterly common stock dividend of $0.955 per share ($3.82 per share on an annualized basis), an increase of 2% compared with the same quarter in the prior year.

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

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In February 2023, we paid quarterly dividends totaling $0.3 million for the Series E Preferred Stock.

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

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

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

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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.

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.

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

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

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

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

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

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

Investing Cash Flows

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

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

Financing Cash Flows

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.

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

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

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

Our commodity price risk includes basis risk, which is the difference in price between various locations where commodities are purchased and sold.

We record all derivative instruments at fair value, except for normal purchases and normal sales transactions that are expected to result in physical delivery.

Many of the contracts in our derivative portfolio are executed in liquid markets where price transparency exists.

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

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

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

We believe any measurement uncertainty at December 31, 2021, is immaterial as our Level 3 fair value measurements are based on unadjusted pricing information from broker quotes and third-party pricing services.

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

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

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

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

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

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

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

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

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

We assess our long-lived assets, including intangible assets, for impairment whenever events or changes in circumstances indicate that an asset’s carrying amount may not be recoverable.

An impairment is indicated if the carrying amount of a long-lived asset exceeds the sum of the undiscounted future cash flows expected to result from the use and eventual disposition of the asset.

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

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

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

To estimate undiscounted future cash flows of long-lived assets, we may apply a probability-weighted approach that incorporates different assumptions and potential outcomes related to the underlying long-lived assets.

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

To estimate the fair value of

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

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

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

See Notes A, 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.

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

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

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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.

Examples of such circumstances include changes in (i) competition, (ii) laws and regulations that limit the estimated economic life of an asset, (iii) technology that render an asset obsolete, (iv) expected salvage values, (v) results of rate cases or rate settlements on regulated assets and (vi) forecasts of the remaining economic life for the resource basins where our assets are located, if any.

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

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

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

FORWARD-LOOKING STATEMENTS

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

• the ability of our existing assets and our ability to apply and continue to develop our expertise to support the growth of, and 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;

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

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

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

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

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

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

• delays in receiving insurance proceeds from covered losses;

• the risk of increased costs for insurance premiums;

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

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

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• 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;

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

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

• the 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;

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

implementation of new software and hardware;

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

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

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

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

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

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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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• 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 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;

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

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

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

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

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

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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