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Item 7. Management’s Discussion and Analysis

2022-02-28 compared with 2021-02-24 · 225 added, 299 removed, 310 unchanged (63% of the section changed)

Management’s Discussion and Analysis of Financial Condition and Results of Operations

We are an energy infrastructure company focused on connecting North America’s significant hydrocarbon resource plays to growing markets for natural gas and NGLs through our gas pipeline and midstream business.

We are an energy company committed to being the leader in providing infrastructure that safely delivers natural gas products to reliably fuel the clean energy economy.

Our operations are located in the United States.

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Our gas pipeline businesses’ interstate transmission and storage activities are subject to regulation by the FERC and as such, our rates and charges for the transportation of natural gas in interstate commerce, and the extension, expansion or abandonment of jurisdictional facilities and accounting, among other things, are subject to regulation.

Rates are established in accordance with the FERC’s ratemaking process.

The rates are established primarily through the FERC’s ratemaking process, but we also may negotiate rates with our customers pursuant to the terms of our tariffs and FERC policy.

Changes in commodity prices and volumes transported have limited near-term impact on these revenues because the majority of cost of service is recovered through firm capacity reservation charges in transportation rates.

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Consistent with the manner in which our chief operating decision maker evaluates performance and allocates resources, our operations are conducted, managed, and presented within the following reportable segments:

Transmission & Gulf of Mexico, Northeast G&P, and West.

All remaining business activities as well as corporate activities are included in Other.

Our reportable segments are comprised of the following businesses:

Transmission & Gulf of Mexico, Northeast G&P, West, and Sequent.

All remaining business activities are included in Other.

As of December 31, 2021, our reportable segments are comprised of the following businesses:

• Transmission & Gulf of Mexico is comprised of our interstate natural gas pipelines, Transco and Northwest Pipeline, as well as natural gas gathering and processing and crude oil production handling and transportation assets in the Gulf Coast region, including a 51 percent interest in Gulfstar One (a consolidated variable interest entity), which is a proprietary floating production system, a 50 percent equity-method investment in Gulfstream, and a 60 percent equity-method investment in Discovery.

• Northeast G&P is comprised of our midstream gathering, processing, and fractionation businesses in the Marcellus Shale region primarily in Pennsylvania and New York, and the Utica Shale region of eastern Ohio, as well as a 65 percent interest in our Northeast JV (a consolidated variable interest entity) which operates in West Virginia, Ohio, and Pennsylvania, a 66 percent interest in Cardinal (a consolidated variable interest entity) which operates in Ohio, a 69 percent equity-method investment in Laurel Mountain, a 99 percent interest in Caiman II (a former equity-method investment which is a consolidated entity following our November 2020 acquisition of an additional ownership interest) which owns a 50 percent equity-method investment in Blue Racer, and Appalachia Midstream Investments, a wholly owned subsidiary that owns equity-method investments with an approximate average 66 percent interest in multiple gas gathering systems in the Marcellus Shale region.

• West is comprised of our gas gathering, processing, and treating operations in the Rocky Mountain region of Colorado and Wyoming, the Barnett Shale region of north-central Texas, the Eagle Ford Shale region of south Texas, the Haynesville Shale region of northwest Louisiana, and the Mid-Continent region which includes the Anadarko, Arkoma, and Permian basins.

This segment also includes our NGL and natural gas marketing business, storage facilities, an undivided 50 percent interest in an NGL fractionator near Conway, Kansas, a 50 percent equity-method investment in OPPL, a 50 percent equity-method investment in RMM, a 20 percent equity-method investment in Targa Train 7, and a 15 percent interest in Brazos Permian II, LLC (Brazos Permian II).

• Other includes certain previously owned operations, minor business activities that are not reportable segments, as well as corporate operations.

• Northeast G&P is comprised of our midstream gathering, processing, and fractionation businesses in the Marcellus Shale region primarily in Pennsylvania and New York, and the Utica Shale region of eastern Ohio, as well as a 65 percent interest in our Northeast JV (a consolidated variable interest entity) which operates in West Virginia, Ohio, and Pennsylvania, a 66 percent interest in Cardinal (a consolidated variable interest entity) which operates in Ohio, a 69 percent equity-method investment in Laurel Mountain, a 50 percent equity-method investment in Blue Racer (we previously effectively owned a 29 percent indirect interest in Blue Racer through our 58 percent equity-method investment in BRMH until acquiring a controlling interest of BRMH in November 2020 and the remaining interest in September 2021), and Appalachia Midstream Investments, a wholly owned subsidiary that owns equity-method investments with an approximate average 66 percent interest in multiple gas gathering systems in the Marcellus Shale region.

This segment also includes NGL and natural gas marketing business (excluding the activities within the Sequent segment described below), storage facilities, an undivided 50 percent interest in an NGL fractionator near Conway, Kansas, a 50 percent equity-method investment in OPPL, a 50 percent equity-method investment in RMM, a 20 percent equity-method investment in Targa Train 7, and a 15 percent interest in Brazos Permian II, LLC (Brazos Permian II).

• Sequent includes the operations of Sequent Energy Management, L.P.

and Sequent Energy Canada, Corp.

acquired on July 1, 2021 (Sequent Acquisition).

Sequent focuses on risk management and the marketing,

trading, storage, and transportation of natural gas for a diverse set of natural gas utilities, municipalities, power generators, and producers, and moves gas to markets through transportation and storage agreements on strategically positioned assets, including our Transco system.

• Other includes our upstream operations and minor business activities that are not reportable segments, as well as corporate operations.

Unless indicated otherwise, the following discussion and analysis of results of operations and financial condition and liquidity relates to our current continuing operations and should be read in conjunction with the consolidated financial statements and notes thereto included in Part II, Item 8 of this report.

In December 2021, we paid a regular quarterly dividend of $0.41 per share.

On January 26, 2021, our board of directors approved a regular quarterly dividend of $0.41 per share payable on March 29, 2021.

On February 1, 2022, our board of directors approved a regular quarterly dividend of $0.425 per share payable on March 28, 2022.

Net income (loss) attributable to The Williams Companies, Inc.

, for the year ended December 31, 2020, decreased $639 million compared to the year ended December 31, 2019, reflecting:

• An $860 million increase in Impairment of equity-method investments ;

• A $187 million Impairment of goodwill in 2020;

• A $123 million unfavorable change in Net income (loss) attributable to noncontrolling interests primarily driven by a reduced share of certain impairment charges attributable to noncontrolling interests;

• The absence of a $122 million gain recognized on the sale of our interest in an equity-method investment in 2019;

• A $76 million unfavorable change in Other income (expense) – net.

These unfavorable changes were partially offset by:

• A $282 million decrease in Impairment of certain assets ;

• A $234 million favorable change in Operating and maintenance expenses and Selling, general, and administrative expenses , driven by lower employee-related expenses, including the absence of 2019 severance and related costs and the associated reduced costs in 2020 as well as the benefit of a change in an employee benefit policy;

• A $256 million favorable change in Provision (benefit) for income taxes.

Acquisition of Caiman II (Blue Racer)

As of December 31, 2019, we effectively owned a 29 percent indirect interest in Blue Racer through our 58 percent interest in Caiman II, whose primary asset is a 50 percent interest in Blue Racer.

On November 18, 2020, we paid $157 million, net of cash acquired, to acquire an additional 41 percent ownership interest in Caiman II.

We now control and consolidate Caiman II, reporting the 50 percent interest in Blue Racer as an equity-method investment.

Expansion Project Updates

Significant expansion project updates for the period, including projects placed into service are described below.

Ongoing major expansion projects are discussed later in Company Outlook.

for the year ended December 31, 2021, increased by $1.3 billion over the prior year, reflecting $223 million of higher net realized commodity margins, $280 million of increased earnings from equity-method investments, primarily due to the absence of our $78 million share of a 2020 impairment of goodwill at West and higher volumes within Northeast G&P, as well as net realized product sales from upstream operations of $313 million and $106 million of higher transportation fee revenues associated with expansion projects placed in service at Transco in 2020 and 2021.

The improvement over last year was partially offset by $314 million of higher operating and administrative costs, $121 million of higher depreciation and amortization expense, and a $109 million unfavorable impact of 2021 net unrealized losses from commodity derivative instruments at Sequent.

The improvement over last year also reflects the absence of $1.4 billion in pre-tax charges in 2020 related to impairments of equity-method investments, goodwill, and certain assets, of which $65 million was attributable to noncontrolling interests.

The provision for income taxes changed unfavorably by $432 million primarily due to higher pre-tax income.

The Sequent segment includes $109 million of net unrealized losses from commodity derivatives not designated as hedges for accounting purposes.

Sequent can experience significant earnings volatility from the fair value accounting required for the derivatives used to hedge a portion of the economic value of the underlying transportation and storage portfolio.

However, the unrealized fair value measurement gains and losses are generally offset by valuation changes in the economic value of the underlying transportation and storage portfolio, which is not recognized until the underlying transportation and storage transaction occurs.

Recent Developments

Share Repurchase Program

In September 2021, our Board of Directors authorized a share repurchase program with a maximum dollar limit of $1.5 billion.

Repurchases may be made from time to time in the open market, by block purchases, in privately negotiated transactions, or in such other manner as determined by our management.

Our management will also determine the timing and amount of any repurchases based on market conditions and other factors.

The share repurchase program does not obligate us to acquire any particular amount of common stock, and it may be suspended or discontinued at any time.

This stock repurchase program does not have an expiration date.

There were no repurchases under the program as of December 31, 2021.

Sequent Acquisition

In July 2021, we completed the acquisition of 100 percent of Sequent.

Total consideration for this acquisition was $159 million, which included $109 million related to working capital.

Sequent focuses on risk management and the marketing, trading, storage, and transportation of natural gas for a diverse set of natural gas utilities, municipalities, power generators, and producers, and moves gas to markets through transportation and storage agreements on strategically positioned assets, including our Transco system.

The addition of Sequent complements

the geographic footprint of our core pipeline transportation and storage business, enhances our gas marketing capabilities, and expands the suite of services we provide to our existing midstream customers.

Upstream Joint Ventures

In the third quarter of 2021, we conveyed certain oil and gas properties in the Wamsutter field, which we acquired in 2021, to a venture along with certain oil and gas properties conveyed by a third-party operator in the region.

Under the terms of the agreement, the third party owns a 25 percent and we own a 75 percent undivided interest in each well’s working interest.

We will retain ownership in the undeveloped acreage until certain acreage earning hurdles are met, at which time the remaining undeveloped acreage will be conveyed to the third party resulting in the third party owning 50 percent and us owning 50 percent.

The combined properties consist of over 1.2 million net acres and an interest in over 3,500 wells.

In the third quarter of 2021, we sold 50 percent of certain existing wells and wellbore rights in the South Mansfield area of the Haynesville Shale region to a third party operator, in a strategic effort to develop the acreage, thereby enhancing the value of our midstream natural gas infrastructure.

Under the agreement, the third party will operate the upstream position and develop the undeveloped acreage.

We will retain ownership in the undeveloped acreage until certain acreage earning and carried interest hurdles are met, at which time remaining undeveloped acreage will be conveyed to the third party resulting in the third party owning 75 percent and us owning 25 percent.

Expansion Project Update

Transmission & Gulf of Mexico

In February 2016, the FERC issued a certificate order for the initial phases of Transco’s Hillabee Expansion Project.

The project involves an expansion of Transco’s existing natural gas transmission system from Station 85 in west central Alabama to an interconnection with the Sabal Trail pipeline in east central Alabama.

The project is being constructed in phases, and all of the project expansion capacity is dedicated to Sabal Trail pursuant to a capacity lease agreement.

Phase I was completed in 2017 and it increased capacity by

We placed Phase II into service on May 1, 2020.

Together, the first two phases of the project increased capacity by 1,025 Mdth/d.

In July 2020, we received approval from the FERC for the project to expand Transco’s existing natural gas transmission system and also extend its system through a capacity lease with National Fuel Gas Supply Corporation that will enable us to provide incremental firm transportation from Clermont, Pennsylvania and from the Zick interconnection on Transco’s Leidy Line to the River Road regulating station in Lancaster County, Pennsylvania.

We placed 125 Mdth/d of capacity under the project into service in the fourth quarter of 2020, and in September and October of 2021, we placed approximately 382 Mdth/d of additional capacity into service.

We placed the remainder of the project into service in December 2021.

The project increased capacity by 582 Mdth/d.

Southeastern Trail

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In total, the project increased capacity by 296 Mdth/d.

Project Bluestem

We expanded our presence in the Mid-Continent region through building a 189-mile NGL pipeline from our fractionator and NGL storage facilities near Conway, Kansas, to an interconnection with a third-party NGL pipeline system in Oklahoma, providing us with firm access to Mt.

Belvieu pricing.

As part of the project, the third party constructed a 110-mile pipeline extension of its existing NGL pipeline system that will have an initial capacity of 120 Mbbls/d.

The pipeline and extension projects were placed into service on December 1, 2020.

Further, during the first quarter of 2019, we exercised an option to purchase a 20 percent equity interest in Targa Train 7, a Mt.

Belvieu fractionation train developed by the third party, which was placed into service in the first quarter of 2020.

The outbreak of COVID-19 has severely impacted global economic activity and caused significant volatility and negative pressure in financial markets.

We are monitoring the COVID-19 pandemic and have taken steps intended to protect the safety of our customers, employees, and communities, and to support the continued delivery of safe and reliable service to our customers and the communities we serve.

We are continuing to monitor developments with respect to the outbreak and note the following:

• Our financial condition, results of operations, and liquidity have not been materially impacted by direct effects of COVID-19.

• We believe we have the ability to access the debt market, if necessary, as evidenced by the successful completion of debt offerings during second-quarter 2020, and continue to have significant levels of unused capacity on our revolving credit facility.

• We continue to monitor and adapt our remote working arrangements and limit business-related travel.

Implementation of these measures has not required material expenditures or significantly impacted our ability to operate our business.

• Our remote working arrangements have not significantly impacted our internal controls over financial reporting and disclosure controls and procedures.

Customer Bankruptcy

In June 2020, our customer, Chesapeake Energy Corporation (Chesapeake), announced that it had voluntarily filed for relief under Chapter 11 of the U.S.

Bankruptcy Code.

We provide midstream services, including wellhead gathering, for the natural gas that Chesapeake and its joint interest owners produce, primarily in the Eagle Ford Shale, Haynesville Shale, and Marcellus Shale regions (through Appalachia Midstream Investments).

In November 2020, we reached a global resolution with Chesapeake as part of Chesapeake’s restructuring process.

The resolution was approved by the bankruptcy court in December 2020 and per the terms, Chesapeake paid all outstanding pre-petition amounts due to us.

Additional terms include reduced gathering fees in the Haynesville Shale region, continuation of the gathering agreements in the Eagle Ford Shale and Marcellus Shale

regions, a long-term gas supply commitment for Transco’s Regional Energy Access pipeline currently under development, and transferring certain natural gas properties in Louisiana to us.

The outbreak of COVID-19 severely impacted global economic activity and caused significant volatility and negative pressure in financial markets.

We continue to monitor the COVID-19 pandemic and have taken steps intended to protect the safety of our customers, employees, and communities, and to support the continued delivery of safe and reliable service to our customers and the communities we serve.

Our financial condition, results of operations, and liquidity have not been materially impacted by effects of COVID-19.

Company Outlook

Our strategy is to provide large-scale energy infrastructure designed to maximize the opportunities created by the vast supply of natural gas and natural gas products that exists in the United States.

Our strategy is to provide a large-scale, reliable, and clean energy infrastructure designed to maximize the opportunities created by the vast supply of natural gas and natural gas products that exists in the United States.

We accomplish this by connecting the growing demand for cleaner fuels and feedstocks with our major positions in the premier natural gas and natural gas products supply basins.

We continue to maintain a strong commitment to safety, environmental stewardship, operational excellence, and customer satisfaction.

We believe that accomplishing these goals will position us to deliver safe and reliable service to our customers and an attractive return to our shareholders.

Our business plan for 2021 includes a continued focus on earnings and cash flow growth, while continuing to improve leverage metrics and control operating costs.

The credit profiles of certain of our producer customers continue to be challenged, including some that have filed for bankruptcy protection.

However, we note that the physical nature of services we provide supports the success of these customers.

In many cases, we have long-term acreage dedications with strong historical contractual conveyances that create real estate interests in unproduced gas.

Our gathering lines in many cases are physically connected to the customers’ wellheads and pads, and there may not be alternative gathering lines nearby.

The construction of gathering systems is capital intensive and it would be costly for others to replicate, especially considering the depletion to date of the associated reserves.

As a result, we play a critical role in getting customers’ production from the wellhead to a marketable condition and location.

This tends to reduce collectability risk as our services enable producers to generate operating cash flows.

In 2021, our operating results are expected to benefit from growth in our Northeast G&P gathering and processing volumes.

We also anticipate increases from Transco expansion projects and higher Gulf of Mexico results primarily due to lower anticipated hurricane impacts.

These increases will be partially offset by a decrease in West results, including a reduction in NGL transportation volumes on OPPL and certain fee reductions in the Haynesville area in exchange for upstream value in natural gas properties.

We also expect a modest increase in expenses, including higher operating taxes.

We continue to maintain a strong commitment to safety,

environmental stewardship including seeking opportunities for renewable energy ventures, operational excellence, and customer satisfaction.

We believe that accomplishing these goals will position us to deliver safe, reliable, clean energy services to our customers and an attractive return to our shareholders.

Our business plan for 2022 includes a continued focus on earnings and cash flow growth.

In 2022, our operating results are expected to benefit from growth in our Ohio Valley Midstream, Cardinal, Susquehanna, and Haynesville areas.

We also anticipate increases resulting from recently completed Transco expansion projects and development of our upstream oil and gas properties.

These increases are partially offset by the absence of favorable results captured during Winter Storm Uri in 2021 by our commodity marketing business and lower expected results in the Bradford Supply Hub primarily due to lower gathering rates resulting from annual cost of service contract redetermination.

We seek to maintain a strong financial position and liquidity, as well as manage a diversified portfolio of safe, clean, and reliable energy infrastructure assets that continue to serve key growth markets and supply basins in the United States.

Our growth capital and investment expenditures in 2022 are expected to be in a range from $1.25 billion to $1.35 billion.

Growth capital spending in 2021 primarily includes Transco expansions, all of which are fully contracted with firm transportation agreements, and projects supporting the Northeast G&P business and opportunities in the Haynesville area.

Growth capital spending in 2022 primarily includes Transco expansions, all of which are fully contracted with firm transportation agreements, projects supporting the Northeast G&P business, opportunities in the Haynesville area, and an expansion in the Western Gulf area.

We also expect to invest capital in the development of our upstream oil and gas properties.

In addition to growth capital and investment expenditures, we also remain committed to projects that maintain our assets for safe and reliable operations, as well as projects that meet legal, regulatory, and/or contractual commitments.

Potential risks and obstacles that could impact the execution of our plan include:

• Continued negative impacts of COVID-19 driving a global recession, which could result in further downturns in financial markets and commodity prices, as well as impact demand for natural gas and related products;

• Opposition to, and legal regulations affecting, our infrastructure projects, including the risk of delay or denial in permits and approvals needed for our projects;

• Counterparty credit and performance risk, including unexpected developments in customer bankruptcy proceedings;

• Continued negative impacts of COVID-19 driving a global recession, which could result in downturns in financial markets and commodity prices, as well as impact demand for natural gas and related products;

• Opposition to, and regulations affecting, our infrastructure projects, including the risk of delay or denial in permits and approvals needed for our projects;

• Counterparty credit and performance risk;

• Unexpected significant increases in capital expenditures or delays in capital project execution;

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• Lower than anticipated demand for natural gas and natural gas products which could result in lower than expected volumes, energy commodity prices, and margins;

• General economic, financial markets, or further industry downturns, including increased interest rates;

• General economic, financial markets, or industry downturns, including increased inflation and interest rates;

• Physical damages to facilities, including damage to offshore facilities by weather-related events;

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Risk Factors in this report.

We seek to maintain a strong financial position and liquidity, as well as manage a diversified portfolio of energy infrastructure assets that continue to serve key growth markets and supply basins in the United States.

Expansion Projects

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Transmission & Gulf of Mexico

Northeast Supply Enhancement

In May 2019, we received approval from the FERC to expand Transco’s existing natural gas transmission system to provide incremental firm transportation capacity from Station 195 in Pennsylvania to the Rockaway Delivery Lateral transfer point in New York.

However, approvals required for the project from the New York State Department of Environmental Conservation and the New Jersey Department of Environmental Protection were denied in May 2020.

We have not refiled our applications for those approvals.

Considering that the customer precedent agreements and FERC certificate for the project remain in effect, we had previously concluded that the probability of completing the project was sufficient to not require impairment.

However, recent developments in the political and regulatory environments have caused us to slightly lower that assessed probability such that the capitalized project costs now require impairment.

See further discussion in Critical Accounting Estimates.

We placed 125 Mdth/d of capacity under the project into service in the fourth quarter of 2020, and we plan to place the remainder of the project into service as early as the fourth quarter of 2021, assuming timely receipt of all necessary regulatory approvals.

Regional Energy Access

In March 2021, we filed an application with the FERC for the project to expand Transco’s existing natural gas transmission system to provide incremental firm transportation capacity from receipt points in northeastern Pennsylvania to multiple delivery points in Pennsylvania, New Jersey, and Maryland.

We plan to place the project into service as early as the fourth quarter of 2024, assuming timely receipt of all necessary regulatory approvals.

The project is expected to increase capacity by 829 Mdth/d.

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Pension and Postretirement Obligations

We have employee benefit plans that include pension and other postretirement benefits.

Net periodic benefit cost and obligations for these plans are impacted by various estimates and assumptions.

These estimates and assumptions include the expected long-term rates of return on plan assets, discount rates, cash balance interest crediting rate, and employee demographics, including retirement age and mortality.

We have pension and other postretirement benefit plans that require the use of assumptions and estimates to determine the benefit obligations and costs.

These estimates and assumptions involve significant judgement and actual results will likely be different than anticipated.

Estimates and assumptions utilized include the expected long-term rates of return on plan assets, discount rates, cash balance interest crediting rate, and employee demographics, including retirement age and mortality.

These assumptions are reviewed annually and adjustments are made as needed.

The assumptions utilized to compute cost and the benefit obligations are shown in Note 10 – Employee Benefit Plans of Notes to Consolidated Financial Statements.

The assumptions utilized to compute the benefit obligations and costs are shown in Note 8 – Employee Benefit Plans of Notes to Consolidated Financial Statements.

The following table presents the estimated increase (decrease) in net periodic benefit cost and obligations resulting from a one-percentage-point change in the specific assumption.

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Discount rate

(4) (1) (22) 27

Expected long-term rate of return on plan assets

Our expected long-term rates of return on plan assets, as determined at the beginning of each fiscal year, are based on the average rate of return expected on the funds invested in the plans.

We determine our long-term expected rates of return on plan assets using our expectations of capital market results, which include an analysis of historical results as well as forward-looking projections.

These capital market expectations are based on a period of at least 10 years and take into account our investment strategy and mix of assets.

We develop our expectations using input from our third-party independent investment consultant.

The forward-looking capital market projections start with current conditions of interest rates, equity pricing, economic growth, and inflation and those are overlaid with forward looking projections of normal inflation, growth, and interest rates to determine expected returns.

The capital market return projections for specific asset classes in the investment portfolio are then applied to the relative weightings of the asset classes in the investment portfolio.

The resulting rates are an estimate of future results and, thus, likely to be different than actual results.

Our expected long-term rates of return on plan assets, as determined at the beginning of each fiscal year, are based on historical returns, forward-looking capital market expectations of at least 10 years from our third-party independent investment advisor, as well as the investment strategy and relative weightings of the asset classes within the investment portfolio.

Our expected long-term rate of return on plan assets used for our pension plans was 3.69 percent in 2021.

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The expected rates of return on plan assets are long-term in nature and are not significantly impacted by short-term market performance.

Changes to our asset allocation also impact the expected rates of return.

The discount rates are used to measure the benefit obligations of our pension and other postretirement benefit plans.

The objective of the discount rates is to determine the amount, if invested at the December 31 measurement date in a portfolio of high-quality debt securities, that will provide the necessary cash flows when benefit payments are due.

Increases in the discount rates decrease the obligation and, generally, decrease the related cost.

The discount rates for our pension and other postretirement benefit plans are determined separately based on an approach specific to our plans and their respective expected benefit cash flows as described in Note 1 – General, Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies and Note 10 – Employee Benefit Plans of Notes to Consolidated Financial Statements.

Our discount rate assumptions are impacted by changes in general economic and market conditions that affect interest rates on long-term, high-quality debt securities as well as by the duration of our plans’ liabilities.

The discount rates for our pension and other postretirement benefit plans are determined separately based on an approach specific to our plans, which considers a yield curve of high-quality corporate bonds and the duration of the expected benefit cash flows of each plan.

The cash balance interest crediting rate assumption represents the average long-term rate by which the pension plans’ cash balance accounts are expected to grow.

Interest on the cash balance accounts is based on the 30-year U.S.

Treasury securities rate and is credited to the accounts quarterly.

An increase in this rate causes the pension obligation and cost to increase.

Equity-Method Investments

We monitor our equity-method investments for any indications that the carrying value may have experienced an other-than-temporary decline in value.

In the first quarter of 2020, we observed a significant decline in the publicly traded price of our common stock (NYSE:

WMB) as well as other industry peers and increases in equity yields within the midstream and overall energy industry, which served to increase our estimates of discount rates and weighted-average cost of capital.

These changes were attributed to the swift, world-wide economic declines associated with actions to address the spread of COVID-19, coupled with the energy industry impact of significantly reduced energy commodity prices, which were further impacted by crude oil price declines associated with geopolitical actions during the quarter.

These significant macroeconomic changes served as indications that the carrying amount of certain of our equity-method investments may have experienced an other-than temporary decline in fair value, determined in accordance with Accounting Standards Codification (ASC) Topic 323, “Investments - Equity Method and Joint Ventures.”

As a result, we estimated the fair value of these equity-method investments in accordance with ASC Topic 820, “Fair Value Measurement,” as of the March 31, 2020, measurement date .

In assessing the fair value, we were required to consider recent publicly available indications of value, which included lower observed publicly traded EBITDA market multiples as compared with recent history, and significantly higher industry weighted-average discount rates.

As a result, we determined that there were other-than-temporary declines in the fair value of certain of our equity-method investments, resulting in recognized impairments during the first quarter of 2020 totaling $938 million.

(See Note 18 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk of Notes to Consolidated Financial Statements.) This included impairments of certain of our equity-method investments in our Northeast G&P segment totaling $405 million, primarily associated with operations in wet-gas areas where producer drilling activities are influenced by NGL prices, which historically trend with crude oil prices.

This total was primarily comprised of impairments of our investment in Caiman II and predominantly wet-gas gathering systems that are part of Appalachia Midstream Investments.

We also recognized an impairment of $97 million related to Discovery within the Transmission & Gulf of Mexico segment.

We estimated the fair value of these investments as of the March 31, 2020, measurement date utilizing income and market approaches, which were impacted by assumptions reflecting the significant recent market declines previously discussed, such as higher discount rates, ranging from 9.7 percent to 13.5 percent, and lower EBITDA multiples ranging from 5.0x to 6.2x.

We also considered any debt held at the investee level, and its impact to fair value.

At that time we estimated that a one percentage point increase or decrease in the discount rates used would increase these recognized impairments by approximately $197 million or decrease the level of these recognized impairments by approximately $121 million and a 0.5x increase or decrease in the EBITDA multiples assumed would decrease or increase the level of impairments recognized by approximately $48 million.

During the first quarter of 2020 we also recognized $436 million of impairments within our West segment related to our investments in RMM and Brazos Permian II, measured using an income approach.

Both investees operate in primarily crude oil-driven basins where our gathering volumes are driven by crude oil drilling.

Our expectation of continued lower crude oil prices and related expectation of significant reductions in current and future producer activities in these areas led to reduced estimates of expected future cash flows.

Our fair value estimates also reflected increases in the discount rates to approximately 17 percent for these investments.

We also considered any debt held at the investee level, and its impact to fair value.

At that time we estimated that a one percentage point increase in the discount rate would increase these recognized impairments by approximately $32 million, while a one percentage point decrease would decrease these impairments by approximately $43 million.

During the fourth quarter of 2020, RMM renegotiated service contracts with a significant customer in connection with the customer’s Chapter 11 bankruptcy proceedings.

The renegotiated contracts result in lower service rates, and lower projected future cash flows.

As a result, we recognized an additional $108 million impairment of our investment in RMM, measured using an income approach.

Our estimate of fair value reflects a discount rate of 18 percent.

We estimate that a one percentage point increase in the discount rate would increase the recognized impairment by approximately $24 million, while a one percentage point decrease would decrease these impairments by approximately $26 million.

Judgments and assumptions are inherent in our estimates of future cash flows, discount rates, and market measures utilized.

The use of alternate judgments and assumptions could result in a different calculation of fair value, which could ultimately result in the recognition of a different impairment charge in the consolidated financial statements, potentially including impairments for investments that were evaluated but for which no impairments were recognized.

Property, Plant, and Equipment and Other Identifiable Intangible Assets

As a result of the previously described significant macroeconomic changes during the first quarter of 2020, we also evaluated certain of our property, plant, and equipment and other identifiable intangible assets for indicators of impairment as of March 31, 2020.

In our assessments, we considered the impact of the then current market conditions on certain of our assets and did not identify any indicators that the carrying amounts of those assets may not be recoverable.

The use of alternate judgments or changes in future conditions could result in a different conclusion regarding the occurrence and measurement of impairments affecting the consolidated financial statements.

We also evaluated $212 million of capitalized project development costs for the Northeast Supply Enhancement project for impairment as of December 31, 2020.

As previously discussed, approvals required for the project from the New York State Department of Environmental Conservation and the New Jersey Department of Environmental Protection have been denied and we have not refiled at this time.

Beginning in May 2020, we discontinued capitalization of costs related to this project.

However, recent developments in the political and regulatory environments have caused us to slightly lower that assessed probability such that the capitalized project costs now require impairment.

The estimated fair value of the materials within capitalized project costs was determined to be $42 million and considered other internal uses and estimated salvage values.

The remaining capitalized costs were determined to have no fair value.

As a result, we recognized an impairment charge of $170 million within our Transmission & Gulf of Mexico segment during the fourth quarter of 2020.

Our assumption regarding the probability of completing the project is subjective and required management to exercise significant judgment.

The use of an alternate judgment could have resulted in a different conclusion regarding the need to evaluate the project for impairment.

Treasury securities rate.

Results of Operations

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4,536 +2,865 +171 % 1,671 -392 -19 % 2,063

Net gain (loss) on commodity derivatives (148) -143 NM (5) -7 NM 2

Total revenues

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Impairment of goodwill — +187 +100 % 187 -187 NM —

Gain on sale of certain assets and businesses

— +2 +100 % 2 -694 NM (692)

Other (income) expense – net

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Equity earnings (losses) 608 +280 +85 % 328 -47 -13 % 375

Impairment of equity-method investments (1,046) -860 NM (186) -154 NM (32)

Impairment of equity-method investments — +1,046 +100 % (1,046) -860 NM (186)

Other investing income (loss) – net 7 -1 -13 % 8 -99 -93 % 107

Interest expense (1,179) -7 -1 % (1,172) +14 +1 % (1,186)

Other income (expense) – net (43) -76 NM 33 -59 -64 % 92

Other income (expense) – net 6 +49 NM (43) -76 NM 33

Income (loss) from continuing operations before income taxes

2,073 277 1,064

Provision (benefit) for income taxes 79 +256 +76 % 335 -197 -143 % 138

Provision (benefit) for income taxes 511 -432 NM 79 +256 +76 % 335

Income (loss) from continuing operations 1,562 198 729

Income (loss) from discontinued operations — +15 +100 % (15) -15 NM —

Income (loss) from discontinued operations — — — % — +15 +100 % (15)

Net income (loss)

1,562 198 714

Net income (loss) attributable to noncontrolling interests

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NM = A percentage calculation is not meaningful due to a change in signs, a zero-value denominator, or a percentage change greater than 200.

Service revenues increased primarily due to higher transportation fee revenues associated with expansion projects placed in service at Transco in 2020 and 2021, higher revenue associated with reimbursable electricity expenses, and higher processing and fractionation revenues in our Northeast G&P segment.

This increase was partially offset by lower volume deficiency fee revenues, lower gathering volumes, and lower deferred revenue amortization in our West segment.

Service revenues – commodity consideration increased primarily due to higher NGL prices.

These revenues represent consideration we receive in the form of commodities as full or partial payment for processing services provided.

Most of these NGL volumes are sold during the month processed and therefore are offset within Product costs below.

Product sales increased primarily due to higher prices and volumes associated with our natural gas and NGL marketing activities, as well as the inclusion of our recently acquired upstream operations.

This increase also includes higher prices related to our equity NGL sales activities.

These increases were partially offset by negative product marketing sales from Sequent (which does not reflect Sequent’s commodity derivative net realized gains discussed below).

As we are acting as agent for our Sequent natural gas marketing customers, our natural gas marketing product sales are presented net of the related product costs of those activities.

Net gain (loss) on commodity derivatives includes realized and unrealized gains and losses from derivative instruments.

The unfavorable change primarily reflects net unrealized losses in our Sequent segment, and net realized losses related to derivative contracts in our West and Other segments.

Net realized gains at our Sequent segment partially offset these impacts.

Product costs increased primarily due to higher prices and volumes associated with our natural gas and NGL marketing activities, as well as higher NGL prices associated with volumes acquired as commodity consideration related to our equity NGL production activities.

Processing commodity expenses increased primarily due to higher prices for natural gas purchases associated with our equity NGL production activities, partially offset by lower volumes.

The net sum of Service revenues – commodity consideration , Product sales , Product costs, Processing commodity expenses, and net realized gains and losses on commodity derivatives related to sales of product comprise our commodity margins.

However, Product sales at our Other segment reflect sales related to our oil and gas producing properties and are excluded from our commodity margins.

Operating and maintenance expenses increased primarily due to the inclusion of our recently acquired upstream operations and higher employee-related expenses, which reflect the absence of a 2020 favorable impact of a change in an employee benefit policy (see Note 5 – Other Income and Expenses of Notes to Consolidated Financial Statements) and increased incentive compensation costs associated with improved company performance, as well as higher reimbursable electricity expenses.

Depreciation and amortization expenses increased primarily due to the inclusion of our recently acquired upstream operations, reduced estimated useful lives for certain facilities in our West segment decommissioned during 2021, new assets placed in-service at Transco, and the amortization of intangible assets resulting from the Sequent Acquisition.

Selling, general, and administrative expenses increased primarily due to higher employee-related expenses, which reflect increased incentive compensation costs associated with improved company performance, Sequent employee-related costs, and the absence of a 2020 favorable impact of a change in an employee benefit policy (see Note 5 – Other Income and Expenses of Notes to Consolidated Financial Statements), partially offset by lower expenses for various corporate costs.

Impairment of certain assets reflects the 2020 impairment of our Northeast Supply Enhancement development project and certain gathering assets in the Marcellus Shale region (see Note 17 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk of Notes to Consolidated Financial Statements).

Impairment of goodwill reflects the goodwill impairment charge at the Northeast reporting unit in 2020 (see Note 17 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk of Notes to Consolidated Financial Statements).

Equity earnings (losses) changed favorably primarily due to the absence of the 2020 impairment of goodwill at RMM, increases at Appalachia Midstream Investments, Laurel Mountain, Blue Racer, Aux Sable, and Discovery, partially offset by a decrease at OPPL.

Impairment of equity-method investments reflects the absence of 2020 impairments to various equity-method investments (see Note 17 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk of Notes to Consolidated Financial Statements).

The favorable change in Other income (expense) – net below Operating income (loss) reflects the absence of a 2020 charge for a legal settlement associated with former olefins operations and the absence of 2020 write-offs of certain regulatory assets related to cancelled projects, partially offset by the unfavorable impact of a 2021 accrual for a loss contingency.

Provision (benefit) for income taxes changed unfavorably primarily due to higher pre-tax income.

See Note 6 – Provision (Benefit) for Income Taxes of Notes to Consolidated Financial Statements for a discussion of the effective tax rate compared to the federal statutory rate for both periods.

The unfavorable change in Net income (loss) attributable to noncontrolling interests is primarily due to the absence of our partner’s share of the 2020 goodwill impairment at the Northeast reporting unit.

Service revenues decreased primarily due to lower volumes in our West segment, lower deferred revenue amortization at Gulfstar One, the expiration of an MVC agreement in the Barnett Shale region, and temporary shut-ins at certain offshore Gulf of Mexico operations.

This decrease was partially offset by higher Northeast G&P revenues driven by higher volumes and the March 2019 consolidation of UEOM (see Note 3 – Acquisitions and Divestitures of Notes to Consolidated Financial Statements), higher MVC revenue in our West segment, as well as higher transportation fee revenues at Transco and Northwest Pipeline associated with expansion projects placed in service in 2019 and 2020, increased volumes in the Eastern Gulf region, and higher deficiency fee revenue associated with lower volumes at OPPL.

This decrease was partially offset by higher Northeast G&P revenues driven by higher volumes and the March 2019 consolidation of UEOM (see Note 3 – Acquisitions of Notes to Consolidated Financial Statements), higher MVC revenue in our West segment, as well as higher transportation fee revenues at Transco and Northwest Pipeline associated with expansion projects placed in service in 2019 and 2020, increased volumes in the Eastern Gulf region, and higher deficiency fee revenue associated with lower volumes at OPPL.

Service revenues – commodity consideration decreased due to lower commodity prices, as well as lower equity NGL processing volumes due to less producer drilling activity.

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Equity earnings (losses) changed unfavorably primarily due to our share of 2020 impairments at equity-method investments (see Note 9 – Investing Activities of Notes to Consolidated Financial Statements), and lower volumes at OPPL and Discovery.

These decreases were partially offset by favorable amortization of basis differences related to impairments of several of our equity-method investments which were recognized in first quarter 2020, as well as higher volumes at Appalachia Midstream Investments, increased results at Blue Racer/Caiman II driven by higher volumes and a higher ownership interest, and the absence of 2019 losses at Brazos Permian II.

Impairment of equity-method investments includes impairments of various equity-method investments in 2020 and 2019 (see Note 18 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk of Notes to Consolidated Financial Statements).

These decreases were partially offset by favorable amortization of basis differences related to impairments of several of our equity-method investments which were recognized in first quarter 2020, as well as higher volumes at Appalachia Midstream Investments, increased results at Blue Racer driven by higher volumes and a higher ownership interest, and the absence of 2019 losses at Brazos Permian II.

Impairment of equity-method investments includes impairments to various equity-method investments in 2019 and 2020 (see Note 17 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk of Notes to Consolidated Financial Statements).

The unfavorable change in Other investing income (loss) – net is primarily due to the absence of a 2019 gain on the sale of our equity-method investment in Jackalope, partially offset by the absence of a 2019 loss on the deconsolidation of Constitution (see Note 9 – Investing Activities of Notes to Consolidated Financial Statements).

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The unfavorable change in Net income (loss) attributable to noncontrolling interests is primarily due to the absence of the 2019 impairment of our Constitution development project and the impact from the formation of the Northeast JV in June 2019, partially offset by the first-quarter 2020 goodwill impairment charge at the Northeast reporting unit, and lower Gulfstar One results.

Service revenues increased primarily due to higher transportation fee revenues at Transco associated with expansion projects placed in service in 2018 and 2019, as well as the impact of the consolidation of UEOM, higher Northeast volumes at the Susquehanna Supply Hub and Ohio Valley Midstream regions, and higher gathering rates and volumes at the Utica Shale region.

These increases are partially offset by the absence of revenues associated with asset divestitures and deconsolidations during 2018, including our former Four Corners area operations (see Note 3 – Acquisitions and Divestitures of Notes to Consolidated Financial Statements), as well as lower revenue in the Barnett Shale associated with the end of a contractual MVC period and lower revenue at Gulfstar One primarily associated with producer operational issues.

Service revenues – commodity consideration decreased due to lower NGL prices and lower volumes primarily due to the absence of our former Four Corners area operations.

These revenues represent consideration we receive in the form of commodities as full or partial payment for processing services provided.

Most of these NGL volumes are sold within the month processed and therefore are offset in Product costs below.

Product sales decreased primarily due to lower NGL and natural gas prices associated with our marketing and equity NGL sales activities, lower volumes from our equity NGL sales primarily reflecting the absence of our former Four Corners area operations, and lower system management gas sales, partially offset by higher marketing volumes.

Marketing sales and system management gas sales are substantially offset in Product costs .

Product costs decreased primarily due to lower NGL and natural gas prices associated with our marketing and equity NGL production activities.

This decrease also includes lower volumes acquired as commodity consideration for NGL processing services reflecting the absence of our former Four Corners area operations and lower system management gas purchases, partially offset by higher volumes for marketing activities.

Processing commodity expenses decreased primarily due to lower production of equity NGLs primarily related to ethane rejection and the absence of our former Four Corners area operations, and lower prices for natural gas purchases associated with our NGL production .

Operating and maintenance expenses decreased primarily due to the absence of our former Four Corners area operations and lower contracted services at Transco primarily due to the timing of required engine overhauls and integrity testing.

These decreases are partially offset by the impact of the consolidation of UEOM and by a $32 million charge for severance and related costs primarily associated with a voluntary separation program (VSP) in 2019.

Depreciation and amortization expenses decreased primarily due to the 2018 impairment of certain assets in the Barnett Shale region, which serves to reduce depreciation prospectively, and the absence of assets disposed including our former Four Corners area operations, partially offset by new assets placed in service and by the impact of the consolidation of UEOM.

Selling, general, and administrative expenses decreased primarily due to the absences of a charitable contribution of preferred stock to the Williams Foundation, Inc.

(see Note 16 – Stockholders' Equity of Notes to Consolidated Financial Statements) and fees associated with the WPZ Merger, partially offset by a $25 million charge for severance and related costs primarily associated with our 2019 VSP, and transaction expenses associated with the acquisition of UEOM and the formation of the Northeast JV.

Impairment of certain assets includes 2019 impairments of our Constitution development project, certain Eagle Ford Shale gathering assets, and certain idle gathering assets.

Asset impairments in 2018 included certain assets in the Barnett Shale region and certain idle pipelines (see Note 18 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk of Notes to Consolidated Financial Statements).

Gain on sale of certain assets and businesses includes gains recognized on the sales of our Four Corners area and our Gulf Coast pipeline systems in 2018 (see Note 3 – Acquisitions and Divestitures of Notes to Consolidated Financial Statements).

The favorable change in Other (income) expense – net within Operating income (loss) includes net favorable changes to charges and credits to regulatory assets and liabilities, partially offset by the absence of a 2018 gain on asset retirement.

The unfavorable change in Equity earnings (losses) is primarily due to 2019 losses from our Brazos Permian II investment acquired in December 2018 of $14 million, the impact of the consolidation of UEOM during the first quarter of 2019 which reduced equity earnings by $9 million, and a $7 million unfavorable impact related to the April 2019 sale of our Jackalope investment.

Additionally, equity earnings at Aux Sable decreased $9 million related to lower rates reflecting lower NGL prices.

These decreases are partially offset by improved results at our Appalachia Midstream Investments of $20 million.

The unfavorable change in Impairment of equity-method investments includes 2019 noncash impairments, partially offset by the absence of a 2018 impairment of UEOM (see Note 18 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk of Notes to Consolidated Financial Statements).

The unfavorable change in Other investing income (loss) – net includes the absence of 2018 gains on the deconsolidations of our Delaware basin assets and Jackalope, and a 2019 loss on the deconsolidation of Constitution.

These were partially offset by a 2019 gain on the disposition of Jackalope (see Note 7 – Investing Activities of Notes to Consolidated Financial Statements).

Interest expense increased primarily due to an increase in financing obligations associated with Transco’s Atlantic Sunrise project and lower Interest capitalized related to construction projects that have been placed into service.

The unfavorable change in Other income (expense) – net below Operating income (loss) is primarily due to a decrease in equity AFUDC associated with reduced capital expenditures on projects (see Note 6 – Other Income and

Expenses of Notes to Consolidated Financial Statements), partially offset by the absence of 2018 unfavorable settlement charges from our pension early payout program.

Provision (benefit) for income taxes changed unfavorably primarily due to higher pre-tax income attributable to The Williams Companies, Inc, partially offset by the absence of a charge to establish $105 million valuation allowance, recorded in 2018, on certain deferred tax assets that may not be realized following the WPZ merger.

See Note 8 – Provision (Benefit) for Income Taxes of Notes to Consolidated Financial Statements for a discussion of the effective tax rate compared to the federal statutory rate for both periods.

The favorable change in Net income (loss) attributable to noncontrolling interests is primarily due to our third- quarter 2018 acquisition of the publicly held interests in WPZ associated with the WPZ Merger, the impairment of Constitution project costs, and lower results at Gulfstar One.

Year-Over-Year Operating Results – Segments

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Impairment of certain assets (2) (170) (354)

Gain on sale of certain assets and businesses — — 81

Proportional Modified EBITDA of equity-method investments 183 166 177

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Commodity margins $ 35 $ 12 $ 25

Transmission & Gulf of Mexico Modified EBITDA increased primarily due to favorable changes to Impairment of certain assets, and Service revenues, partially offset by higher Other segment costs and expenses.

Service revenues increased primarily due to:

• A $135 million increase in Transco’s and Northwest Pipeline’s natural gas transportation and storage revenues primarily associated with expansion projects placed in service in 2020 and 2021, higher reimbursable electric power costs and a cash out surcharge, which are offset by similar changes in electricity and cash out charges, reflected in Other segment costs and expenses ;

• A $21 million increase from the Norphlet pipeline associated primarily with higher deferred revenue amortization and higher volumes;

• An $18 million increase at Perdido primarily driven by higher volumes due to the absence of temporary shut-ins in 2020 related to scheduled maintenance and fewer Western Gulf of Mexico weather-related events;

partially offset by

• A $25 million decrease at Gulfstar One for the Tubular Bells field primarily associated with lower deferred revenue amortization from lower contractually determined maximum daily quantities;

• A $17 million decrease due to lower volumes at Gulfstar One in the Gunflint field due to ongoing producer operational issues, partially offset by the lower temporary shut-ins related to pricing in 2020.

The net sum of Service revenues – commodity consideration , Product sales , Product costs, Processing commodity expenses, comprise our Commodity margins .

Commodity margins associated with our equity NGLs increased $21 million primarily driven by favorable NGL sales prices.

Other segment costs and expenses increased primarily due to higher incentive and benefit employee-related costs as previously discussed;

higher operating costs, including higher reimbursable electric power costs;

and a cash out surcharge reserve, which are offset by similar changes in electricity and cash out reimbursements, reflected in Service revenues;

and higher operating taxes, partially offset by a favorable change associated with the deferral of asset retirement obligation-related depreciation at Transco.

Impairment of certain assets reflects the absence of the impairment of our Northeast Supply Enhancement development project in 2020 (see Note 17 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk of Notes to Consolidated Financial Statements).

Proportional Modified EBITDA of equity-method investments increased at Discovery driven by higher NGL sales prices and higher volumes due to the absence of prior year scheduled maintenance.

Transmission & Gulf of Mexico Modified EBITDA increased primarily due to lower Impairment of certain assets and favorable changes to Other segment costs and expenses, partially offset by decreased Service revenues .

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• A $24 million increase associated with volumes from Norphlet placed in service in June 2019.

The net sum of Service revenues – commodity consideration, Product sales, Product costs, and Processing commodity expenses comprise our commodity margins.

Our commodity margins associated with our equity NGLs decreased $11 million driven by lower commodity prices and volumes.

Additionally, the decrease in Product sales includes a $47 million decrease in commodity marketing sales due to lower NGL prices and volumes and $27 million lower system management gas sales.

Marketing sales and system management gas sales are substantially offset in Product costs and therefore have little impact to Modified EBITDA.

Other segment costs and expenses decreased primarily due to lower employee-related expenses, including the absence of 2019 severance and related costs and the associated reduced costs in 2020, as well as the favorable impact of a change in an employee benefit policy (see Note 6 – Other Income and Expenses of Notes to Consolidated Financial Statements), lower maintenance costs primarily due to a decrease in contracted services related to general maintenance and other testing at Transco, the absence of a 2019 charge for reversal of costs capitalized in previous periods and net favorable changes to charges and credits associated with a regulatory asset related to Transco’s asset retirement obligations, partially offset by lower equity AFUDC and higher operating taxes.

Commodity margins associated with our equity NGLs decreased $11 million driven by lower commodity prices and volumes.

Other segment costs and expenses decreased primarily due to lower employee-related expenses, including the absence of 2019 severance and related costs and the associated reduced costs in 2020, as well as the favorable impact of a 2020 change in an employee benefit policy (see Note 5 – Other Income and Expenses of Notes to Consolidated Financial Statements), lower maintenance costs primarily due to a decrease in contracted services related to general maintenance and other testing at Transco, the absence of a 2019 charge for reversal of costs capitalized in previous periods.

The 2020 period also benefited from net favorable changes to charges and credits associated with a regulatory asset related to Transco’s asset retirement obligations, partially offset by lower equity AFUDC and higher operating taxes.

Impairment of certain assets includes the absence of the impairment of our Constitution development project in 2019, partially offset by the impairment of our Northeast Supply Enhancement development project in 2020 (see Note 17 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk of Notes to Consolidated Financial Statements).

Proportional Modified EBITDA of equity-method investments decreased at Discovery driven by lower volumes due to scheduled maintenance and temporary shut-ins related to Gulf of Mexico weather-related events and pricing.

Transmission & Gulf of Mexico Modified EBITDA decreased primarily due to the impairment of Constitution, the absence of a 2018 Gain on sale of certain assets and businesses , and higher Other segment costs and expenses , partially offset by increased Service revenues related to expansion projects placed into service during 2018 and 2019.

Service revenues increased primarily due to a $403 million increase in Transco’s natural gas transportation revenues primarily driven by a $358 million increase related to expansion projects placed in service in 2018 and 2019, as well as higher revenue associated with Transco’s general rate case settlement and increased amounts for reimbursable power and storage expenses.

Partially offsetting these increases were lower fee revenues of $62 million primarily due to producer operational issues and lower deferred revenue amortization at Gulfstar One, as well as the sale of certain Gulf Coast pipeline assets in fourth-quarter 2018.

The net sum of Service revenues – commodity consideration, Product sales, Product costs, and Processing commodity expenses comprise our commodity margins.

Our commodity margins associated with our equity NGLs decreased $16 million, consisting of a $26 million decrease associated with unfavorable net realized NGL sales prices, partially offset by a $10 million increase associated with higher sales volumes.

The higher NGL volumes were primarily related to the absence of 2018 downtime to modify the Mobile Bay processing plant for the Norphlet project.

Additionally, the decrease in Product sales includes a $93 million decrease in commodity marketing sales due to lower NGL prices and volumes and a $39 million decrease in system management gas sales.

Marketing sales

and system management gas sales are substantially offset in Product costs and therefore have little impact to Modified EBITDA.

Other segment costs and expenses increased primarily due a $56 million unfavorable change in Transco’s equity AFUDC due to lower construction activity, a $39 million charge in 2019 for severance and related costs primarily associated with our 2019 VSP, a $21 million increase in reimbursable power and storage expenses, $16 million of expense in 2019 related to the reversal of expenditures previously capitalized, and the absence of a $12 million 2018 gain on asset retirements.

These unfavorable changes were partially offset by $77 million of net favorable changes to charges and credits associated with regulatory assets and liabilities, which were significantly driven by the previously mentioned settlement in Transco’s general rate case, a $46 million decrease in Transco’s contracted services compared to 2018 mainly due to the timing of required engine overhauls and integrity testing, and the absence of a 2018 unfavorable charge of $12 million for a regulatory liability associated with a decrease in Northwest Pipeline’s estimated deferred state income tax rate following the WPZ Merger.

Impairment of certain assets includes the 2019 impairment of our Constitution development project (see Note 18 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk of Notes to Consolidated Financial Statements).

Gain on sale of certain assets and businesses reflects an $81 million gain from the sale of our Gulf Coast pipeline system assets in fourth-quarter 2018 (see Note 3 – Acquisitions and Divestitures of Notes to Consolidated Financial Statements).

Northeast G&P

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Commodity margins $ 5 $ 4 $ 2

Northeast G&P Modified EBITDA increased primarily due to increased Proportional Modified EBITDA of equity-method investments and higher Service revenues , partially offset by increased Other segment costs and expenses .

Service revenues increased primarily due to:

• A $27 million increase in revenues associated with reimbursable electricity expenses, which is offset by similar changes in electricity charges, reflected in Other segment costs and expenses;

• A $23 million increase in revenues at the Northeast JV primarily related to higher processing and fractionation volumes, partially offset by lower gathering volumes;

• A $6 million increase in revenues at Susquehanna Supply Hub primarily related to higher gathering rates, partially offset by lower gathering volumes.

Other segment costs and expenses increased primarily due to higher maintenance and operating expenses, including higher electricity charges, as well as higher incentive and benefit employee-related costs as previously discussed.

Impairment of certain assets reflects a $12 million impairment of certain gathering assets in the Marcellus Shale region in 2020 (see Note 17 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk of Notes to Consolidated Financial Statements).

Proportional Modified EBITDA of equity-method investments increased at Appalachia Midstream Investments primarily driven by higher volumes as well as the absence of our $26 million share of an impairment of certain assets in 2020 that were subsequently sold.

Additionally, there was an increase at Blue Racer primarily due to the favorable impact of increased ownership as well as the absence of our $10 million share of an impairment of certain assets in 2020.

There was also an increase at Laurel Mountain due to higher commodity-based gathering rates as well as the absence of our $11 million share of an impairment of certain assets in 2020 that were subsequently sold and higher MVC revenue, partially offset by lower volumes, and an increase at Aux Sable.

Northeast G&P Modified EBITDA increased primarily due to higher Service revenues, lower Other segment costs and expenses, and increased Proportional Modified EBITDA of equity-method investments , in addition to the favorable impact of acquiring the additional interest in UEOM, which is a consolidated entity after the remaining ownership interest was purchased in March 2019.

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• A $13 million increase in revenues associated with reimbursable electricity expenses, which is offset by similar changes in electricity charges, reflected in Other segment costs and expenses.

Product sales decreased primarily due to lower NGL volumes and prices within our marketing activities, and lower system management gas sales.

Marketing sales and system management gas sales are offset by similar changes in marketing purchases and system management gas purchases, reflected above as Product costs , and therefore have little impact to Modified EBITDA .

Other segment costs and expenses decreased due to lower employee-related expenses, including the absence of 2019 severance and related costs and the associated reduced costs in 2020, as well as the favorable impact of a 2020 change in an employee benefit policy (see Note 5 – Other Income and Expenses of Notes to Consolidated Financial Statements), and lower maintenance and operating expenses primarily due to timing and scope of activities.

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These decreases were partially offset by higher reimbursable electricity expenses, increased expenses associated with the consolidation of UEOM, and the absence of a favorable customer settlement in 2019.

Impairment of certain assets includes a $12 million impairment of certain gathering assets in the Marcellus Shale region in 2020 and a $10 million write-down of other certain assets that were no longer in use or were surplus in nature in 2019 (see Note 18 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk of Notes to Consolidated Financial Statements).

Impairment of certain assets reflects a $12 million impairment of certain gathering assets in the Marcellus Shale region in 2020 and a $10 million write-down of other certain assets that were no longer in use or were surplus in nature in 2019 (see Note 17 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk of Notes to Consolidated Financial Statements).

Proportional Modified EBITDA of equity-method investments increased at Appalachia Midstream Investments driven by higher volumes, partially offset by a $26 million decrease for our share of an impairment of certain assets.

Additionally, there was an increase at Blue Racer/Caiman II primarily due to higher volumes and the favorable impact of increased ownership, partially offset by a $10 million decrease for our share of an impairment of certain assets.

Additionally, there was an increase at Blue Racer primarily due to higher volumes and the favorable impact of increased ownership, partially offset by a $10 million decrease for our share of an impairment of certain assets.

These increases were partially offset by a $16 million decrease as a result of the consolidation of UEOM in 2019, as previously discussed, as well as a decrease at Laurel Mountain primarily due to $11 million for our share of an impairment of certain assets that were subsequently sold, partially offset by higher volumes, and a decrease at Aux Sable.

Northeast G&P Modified EBITDA increased primarily due to higher Service revenues due to increased gathering volumes, as well as the $38 million favorable impact of acquiring the additional interest in UEOM, partially offset by 2019 impairments.

Service revenues increased primarily due to:

• A $158 million increase associated with the consolidation of UEOM, as previously discussed;

• A $102 million increase associated with higher gathering revenues at Susquehanna Supply Hub reflecting 18 percent higher gathering volumes due to increased production from customers and higher rates;

• A $49 million increase at Ohio Valley Midstream primarily due to higher gathering, processing, and transportation volumes;

• A $36 million increase in gathering revenues in the Utica Shale region due to higher rates and volumes from new wells;

• A $14 million increase in compression revenues for services charged to an affiliate driven by higher volumes.

Product sales decreased primarily due to lower non-ethane volumes and prices within our marketing activities.

The changes in marketing revenues are offset by similar changes in marketing purchases, reflected above as Product costs .

Other segment costs and expenses increased primarily due to:

• A $53 million increase associated with the consolidation of UEOM;

• A $10 million increase related to transaction expenses associated with the acquisition of UEOM and the formation of the Northeast JV;

• A $7 million charge in 2019 for severance and related costs primarily associated with our VSP.

Impairment of certain assets increased due to a $10 million write-down of other certain assets that are no longer in use or are surplus in nature in 2019 (see Note 18 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk of Notes to Consolidated Financial Statements).

Proportional Modified EBITDA of equity-method investments decreased $59 million as a result of the consolidation of UEOM and $10 million due to unfavorable rates reflecting lower NGL prices at Aux Sable.

This decrease was partially offset by a $29 million increase at Appalachia Midstream Investments, reflecting higher volumes due to increased customer production.

Year Ended December 31,

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Product sales 4,330 1,567 1,795

Net gain (loss) on commodity derivatives (85) (5) 2

Segment revenues 5,645 2,943 3,311

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Impairment of certain assets — — (100)

Gain on sale of certain assets and businesses — (2) 591

Proportional Modified EBITDA of equity-method investments 105 110 115

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Commodity margins $ 255 $ 85 $ 91

Net unrealized gain (loss) from derivative instruments — — 3

West Modified EBITDA increased primarily due to higher Commodity margins, partially offset by lower Service revenues .

Service revenues decreased primarily due to:

• A $63 million decrease associated with lower volumes, primarily due to production declines in the Eagle Ford Shale region which impact is substantially offset by recognition of higher MVC revenue (see below);

• A $29 million decrease due to the absence of a temporary volume deficiency fee from a customer in 2020;

• A $22 million decrease driven by lower deferred revenue amortization, primary in the Barnett Shale region;

partially offset by

• A $37 million increase associated with higher MVC revenue primarily in the Eagle Ford Shale region, partially offset by lower MVC revenue in the Wamsutter region;

• A $17 million increase in revenues associated primarily with reimbursable compressor power and fuel purchases due to higher prices related to the impact of severe winter weather, which are offset by similar changes in Other segment costs and expenses;

• A $10 million increase associated with higher net realized gathering and processing rates, primarily in the Barnett Shale and Piceance regions due to higher commodity pricing, along with escalated gathering rates in the Eagle Ford Shale region, partially offset by a decrease in gathering rates in the Haynesville Shale region due to a customer contract change.

The net sum of Service revenues – commodity consideration, Product sales, Product costs, Processing commodity expenses, and net realized gains and losses on commodity derivatives related to sales of product comprise our Commodity margins.

We further segregate our Commodity margins into product margins associated with our equity NGLs and marketing margins.

Marketing margins increased by $145 million primarily due to favorable changes in net realized natural gas and NGL prices, including the impact of severe winter weather in the first quarter of 2021.

Product margins from our equity NGLs increased by $13 million, primarily due to favorable

net realized commodity price changes, partially offset by lower sales volumes.

Margins on other sales of products increased $12 million primarily due to higher commodity prices.

Other segment costs and expenses decreased primarily due to gains on asset sales in 2021, lower leased compressor expenses, favorable changes in system gains and losses, lower legal and consulting expenses, and favorable settlements, partially offset by higher reimbursable compressor power and fuel purchases which are offset in Service revenues and higher incentive and benefit employee-related expenses as previously discussed.

Proportional Modified EBITDA of equity-method investments decreased primarily due to lower volumes at OPPL, partially offset by higher volumes and commodity prices at Brazos Permian II.

West Modified EBITDA increased primarily due to the absence of Impairment of certain assets and lower Other segment costs and expenses, partially offset by lower Service revenues .

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• A $29 million increase associated with a temporary volume deficiency fee associated with reduced volumes from a shipper on OPPL;

• A $26 million increase in the Wamsutter region associated with higher MVC revenue.

The net sum of Service revenues – commodity consideration, Product sales, Product costs, and Processing commodity expenses comprise our commodity margins, which we further segregate into product margins associated with our equity NGLs and marketing margins.

• A $26 million increase in the Wamsutter region associated with higher MVC revenues.

Product margins from our equity NGLs decreased $29 million primarily due to:

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• A $21 million increase related to a decline in natural gas purchases associated with equity NGL production due to lower natural gas prices and lower equity non-ethane production volumes.

Additionally, marketing margins increased by $23 million primarily due to favorable changes in net commodity prices.

Additionally, marketing margins increased by $26 million primarily due to higher net realized NGL and natural gas prices.

The decrease in Product sales includes a $168 million decrease in marketing sales, which is due to lower sales prices, partially offset by higher marketing sales volumes.

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These decreases are substantially offset in Product costs.

Other segment costs and expenses decreased primarily due to lower employee-related expenses driven by the absence of 2019 severance and related costs and the associated reduced costs in 2020, and the favorable impact of a change in an employee benefit policy (see Note 6 – Other Income and Expenses of Notes to Consolidated Financial Statements), as well as lower operating costs due to fewer leased compressors and lower maintenance costs primarily due to timing and scope of activities.

2020 change in an employee benefit policy (see Note 5 – Other Income and Expenses of Notes to Consolidated Financial Statements), as well as lower operating costs due to fewer leased compressors and lower maintenance costs primarily due to timing and scope of activities.

These favorable changes are partially offset by the absence of $12 million in favorable settlements in 2019.

Impairment of certain assets decreased primarily due to the absence of a $79 million impairment of certain Eagle Ford Shale gathering assets and a $12 million impairment of certain idle gathering assets in 2019 (see Note 18 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk of Notes to Consolidated Financial Statements).

Impairment of certain assets reflects a $79 million impairment of certain Eagle Ford Shale gathering assets and a $12 million impairment of certain idle gathering assets in 2019 (see Note 17 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk of Notes to Consolidated Financial Statements).

Proportional Modified EBITDA of equity-method investments decreased primarily due to lower volumes at OPPL and the absence of the Jackalope equity-method investment sold in April 2019, partially offset by growth at the RMM, Brazos Permian II, and Targa Train 7 equity-method investments.

West Modified EBITDA increased primarily due to lower Impairment of certain assets and lower Other segment costs and expenses, partially offset by a lower gain on sale of certain assets in 2019, lower Service revenues, and lower commodity margins.

Service revenues decreased primarily due to:

• A $218 million decrease associated with asset divestitures and deconsolidations during 2018 and 2019, including our former Four Corners area assets, certain Delaware basin assets that were contributed to our

Brazos Permian II equity-method investment, and our Jackalope assets which were deconsolidated in second-quarter 2018 and subsequently sold in second-quarter 2019;

• A $57 million decrease driven by lower deferred revenue amortization and MVC deficiency fee revenues in the Barnett Shale region primarily associated with the expiration of a certain MVC agreement;

• A $17 million decrease driven by lower gathering volumes primarily in the Mid-Continent, Barnett Shale, and Wamsutter regions, partially offset by higher gathering volumes primarily in the Haynesville Shale and Eagle Ford regions;

• A $15 million decrease associated with lower processing rates primarily driven by lower commodity pricing in the Piceance region;

• A $15 million decrease associated with lower gathering rates primarily in the Mid-Continent and Haynesville Shale regions;

partially offset by

• A $17 million increase related to other MVC deficiency fee revenues;

• A $13 million increase related to higher fractionation and storage fees;

• An $8 million increase associated with the resolution of a prior period performance obligation.

The net sum of Service revenues – commodity consideration, Product sales, Product costs, and Processing commodity expenses comprise our commodity margins.

Our commodity margins associated with our equity NGLs decreased by $127 million primarily due to:

• A $98 million decrease associated with lower sales volumes, consisting of $54 million related to the absence of our former Four Corners area assets and $44 million due to 12 percent lower non-ethane volumes and 33 percent lower ethane sales volumes primarily due to higher ethane rejection in 2019, natural declines, less producer drilling activity, and more severe weather conditions in first-quarter 2019;

• A $66 million decrease associated with lower sales prices primarily due to 29 percent and 48 percent lower average net realized per-unit non-ethane and ethane sales prices, respectively;

partially offset by

• A $37 million increase related to lower natural gas purchases associated with lower equity NGL production volumes and lower natural gas prices, including $9 million related to the absence of our former Four Corners area assets.

Additionally, the decrease in Product sales includes a $447 million decrease in marketing sales, which is due to lower sales prices, partially offset by higher sales volumes, and a $36 million decrease related to the sale of other products.

These decreases are substantially offset in Product costs.

Marketing margins increased by $27 million primarily due to favorable changes in prices.

Other segment costs and expenses decreased primarily due to a $127 million reduction associated with the absence of our former Four Corners area assets and from the Jackalope deconsolidation in second-quarter 2018, $12 million favorable settlements in 2019, as well as $7 million lower ad valorem taxes.

These decreases were partially offset by an unfavorable charge in 2019 for severance and related costs primarily associated with our VSP of $10 million.

Impairment of certain assets decreased primarily due to the absence of the $1.849 billion Barnett impairment in in 2018, partially offset by small impairment charges in 2019 (see Note 18 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk of Notes to Consolidated Financial Statements).

The decrease in Gain on sale of certain assets and businesses reflects the absence of the gain from the sale of our Four Corners area assets recorded in the fourth quarter of 2018 (see Note 3 – Acquisitions and Divestitures of Notes to the Consolidated Financial Statements).

Proportional Modified EBITDA of equity-method investments increased primarily due to the additions of the RMM and Brazos Permian II equity-method investments in the second half of 2018, partially offset by the sale of our Jackalope investment in second-quarter 2019.

We closed the Sequent Acquisition on July 1, 2021.

See the Sequent Acquisition section of Recent Developments above for additional information related to Sequent.

Year Ended December 31,

Product sales $ (43)

Net realized gain (loss) from derivative instruments 66

Net unrealized gain (loss) from derivative instruments (109)

Net gain (loss) on commodity derivatives (43)

Segment revenues (86)

Other segment costs and expenses (26)

Sequent Modified EBITDA $ (112)

Commodity margins $ 23

Sequent Modified EBITDA reflects Commodity margins more than offset by net unrealized losses from derivative instruments and segment costs and expenses.

The net sum of Product sales and net realized gains and losses on commodity derivatives related to sales of product comprise our Commodity margins .

Commodity margins include $35 million primarily related to favorable pricing spreads on Sequent’s transportation capacity reflecting losses on physical transaction settlements more than offset by net realized gains on derivatives.

The transportation related margin was partially offset by a $12 million unfavorable margin related to storage activity.

The unfavorable storage margin reflects gains on physical transaction settlements offset by an $18 million charge related to the partial recognition of a purchase accounting inventory fair value adjustment which increased the weighted-average cost of inventory and $13 million related to a lower of cost or net realizable value inventory adjustment.

The Net unrealized gain (loss) from derivative instruments relates to derivative contracts within the Sequent segment that are not designated as hedges for accounting purposes.

Other segment costs and expenses primarily include employee-related costs.

Year Ended December 31,

2021 2020 2019

Other Modified EBITDA $ 178 $ (15) $ 6

Other Modified EBITDA increased primarily due to:

• A $168 million increase due to our recently acquired upstream operations, including the favorable commodity price impact of severe winter weather in the first quarter of 2021;

• A $24 million increase due to the absence of a 2020 charge related to a legal settlement associated with our former olefins operations;

• A $15 million increase due to the absence of 2020 charges related to write-offs of certain regulatory assets associated with cancelled projects;

partially offset by

• A $10 million decrease associated with a 2021 charge related to a legal settlement.

Other Modified EBITDA decreased primarily due to:

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partially offset by

• The absence of a $12 million unfavorable adjustment to a regulatory asset associated with an increase in Transco’s estimated deferred state income tax rate following the WPZ Merger.

Other Modified EBITDA increased primarily due to:

• The absence of the $66 million impairment of certain idle pipelines in the second quarter of 2018 (see Note 18 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk of Notes to Consolidated Financial Statements);

• The absence of a $35 million charge in 2018 associated with a charitable contribution of preferred stock to The Williams Companies Foundation, Inc.

(a not-for-profit corporation) (see Note 16 – Stockholders' Equity of Notes to Consolidated Financial Statements);

• The absence of $20 million in costs in 2018 associated with the WPZ Merger (see Note 1 – General, Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies of Notes to Consolidated Financial Statements);

• An $8 million increase related to the absence of 2018 unfavorable Modified EBITDA associated with the results of certain of our former Gulf Coast area operations sold in 2018;

• The absence of a $7 million loss on early retirement of debt in 2018.

These increases were partially offset by:

• The absence of a $37 million benefit of establishing a regulatory asset associated with an increase in Transco’s estimated deferred state income tax rate following the WPZ Merger in 2018 and a subsequent unfavorable $12 million adjustment in the first quarter of 2019;

• A $26 million decrease in income associated with a regulatory asset related to deferred taxes on equity funds used during construction;

• The absence of a $20 million gain on the sale of certain assets and operations located in the Gulf Coast area in 2018 (see Note 3 – Acquisitions and Divestitures of Notes to Consolidated Financial Statements).

• The absence of a 2019 $12 million unfavorable adjustment to a regulatory asset associated with an increase in Transco’s estimated deferred state income tax rate following the merger transaction wherein we acquired all of the outstanding common units held by others of our former publicly traded master limited partnership.

Management’s Discussion and Analysis of Financial Condition and Liquidity

As previously discussed, we have continued to focus on earnings and cash flow growth, while continuing to improve leverage metrics and control operating costs.

During 2020, we retired approximately $2.1 billion of long-term debt and issued approximately $2.2 billion of new long-term debt.

In July 2020, we paid $284 million for rate refunds related to Transco’s increased rates collected since the new rates became effective in March 2019.

In 2020, we acquired substantially all of the remaining outstanding ownership interests in Caiman II for approximately $157 million, net of cash acquired.

We have continued to focus on earnings and cash flow growth, while continuing to improve leverage metrics and control operating costs.

During 2021, we issued approximately $2.15 billion of new long-term debt primarily to fund current or near-term retirements.

In the first half of 2021, we acquired various oil and gas properties in the Wamsutter field in Wyoming, funding the $165 million paid with cash on hand.

In July 2021, we acquired Sequent, funding the final purchase price of $159 million paid with cash on hand (see Note 3 – Acquisitions of Notes to Consolidated Financial Statements).

See also the section titled Sources (Uses) of Cash .

As previously discussed in Company Outlook, our growth capital and investment expenditures in 2021 are currently expected to be in a range from $1.0 billion to $1.2 billion.

Our growth capital and investment expenditures in 2022 are currently expected to be in a range from $1.25 billion to $1.35 billion.

We also expect to invest capital in the development of our upstream oil and gas properties.

We intend to fund substantially all of our planned 2022 capital spending with cash available after paying dividends.

We retain the flexibility to adjust planned levels of growth capital and investment expenditures in response to changes in economic conditions or business opportunities.

As of December 31, 2020, we have $893 million of long-term debt due within one year.

Our potential sources of liquidity available to address these maturities include proceeds from refinancing at attractive long-term rates or from our credit facility, as well as proceeds from asset monetizations.

We retain the flexibility to adjust planned levels of growth capital and investment expenditures in response to changes in economic conditions or business opportunities including the repurchase of our common stock as previously discussed in Recent Developments.

As of December 31, 2021, we have approximately $2.025 billion of long-term debt due within one year.

Our potential sources of liquidity available to address these maturities include cash on hand, proceeds from refinancing at attractive long-term rates or from our credit facility, as well as proceeds from asset monetizations.

In January 2022, we retired our $1.25 billion of 3.6 percent senior unsecured notes that were scheduled to mature in March 2022 with cash on hand.

Based on our forecasted levels of cash flow from operations and other sources of liquidity, we expect to have sufficient liquidity to manage our businesses in 2022.

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Distributions to noncontrolling interests

Share repurchase program

As of December 31, 2021, we have approximately $21.650 billion of long-term debt due after one year.

See Note 14 – Debt and Banking Arrangements of Notes to Consolidated Financial Statements for the aggregate maturities over the next five years.

See Note 13 – Debt and Banking Arrangements of Notes to Consolidated Financial Statements for the aggregate

maturities over the next five years.

Our potential sources of liquidity available to address these maturities include cash generated from operations, proceeds from refinancing at attractive long-term rates or from our credit facility, as well as proceeds from asset monetizations.

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We had no commercial paper outstanding as of December 31, 2021.

The highest amount outstanding under our commercial paper program and credit facility during 2020 was $1.7 billion.

The highest amount outstanding under our commercial paper program and credit facility during 2021 was $15 million.

At December 31, 2021, we were in compliance with the financial covenants associated with our credit facility.

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Registrations

To replace our recently expired shelf registration statement, we anticipate filing a new shelf registration statement as a well-known seasoned issuer.

In February 2021, we filed a shelf registration statement as a well-known seasoned issuer.

Distributions from Equity-Method Investees

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S&P Global Ratings Stable BBB

Moody’s Investors Service Positive Baa3

Moody’s Investors Service Stable Baa2

Fitch Ratings Stable BBB

In November 2020, Fitch Ratings upgraded our credit rating from BBB- to BBB.

In January 2021, Moody’s changed our Outlook from Stable to Positive.

These credit ratings are included for informational purposes and are not recommendations to buy, sell, or hold our securities, and each rating should be evaluated independently of any other rating.

No assurance can be given that the credit rating agencies will continue to assign us investment-grade ratings even if we meet or exceed their current

criteria for investment-grade ratios.

A downgrade of our credit ratings might increase our future cost of borrowing and would require us to provide additional collateral to third parties, negatively impacting our available liquidity.

No assurance can be given that the credit rating agencies will continue to assign us investment-grade ratings even if we meet or exceed their current criteria for investment-grade ratios.

A downgrade of our credit ratings might increase our future cost of borrowing

and, if ratings were to fall below investment-grade, could require us to provide additional collateral to third parties, negatively impacting our available liquidity.

Sources (Uses) of Cash

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Investing 1 — 485

Proceeds from sale of businesses, net of cash divested (see Note 3)

Investing — (2) 1,296

Uses of cash and cash equivalents:

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Operating activities

The factors that determine operating activities are largely the same as those that affect Net income (loss) , with the exception of noncash items such as Depreciation and amortization , Provision (benefit) for deferred income taxes , Equity (earnings) losses , Gain on disposition of equity-method investments , ( Gain) on sale of certain assets and businesses , ( Gain) loss on deconsolidation of businesses , Impairment of goodwill , Impairment of equity-method investments , and Impairment of certain assets.

The factors that determine operating activities are largely the same as those that affect Net income (loss) , with the exception of noncash items such as Depreciation and amortization , Provision (benefit) for deferred income taxes , Equity (earnings) losses , Gain on disposition of equity-method investments , ( Gain) loss on deconsolidation of businesses , Impairment of goodwill , Impairment of equity-method investments , Impairment of certain assets, and Net unrealized (gain) loss from derivative instruments.

Our Net cash provided (used) by operating activities in 2021 increased from 2020 primarily due to higher operating income (excluding noncash items as previously discussed), favorable changes in net operating working capital reflecting the absence in 2021 of the Transco rate refund payment made in 2020, and higher distributions from unconsolidated affiliates in 2021, partially offset by unfavorable changes in current and noncurrent derivative assets and liabilities.

Our Net cash provided (used) by operating activities in 2020 decreased from 2019 primarily due to the net unfavorable changes in net operating working capital in 2020, including the payment of Transco’s rate refunds in 2020 and the decrease in the income tax refund that was received in 2020 compared to that received in 2019, partially offset by higher operating income (excluding noncash items as previously discussed) in 2020.

Our Net cash provided (used) by operating activities in 2019 increased from 2018 primarily due to the net favorable changes in operating working capital in 2019, including the collection of Transco’s filed rates subject to refund and the receipt of an income tax refund, as well as higher operating income (excluding noncash items as previously discussed) in 2019, partially offset by the impact of decreased distributions from unconsolidated affiliates in 2019.

Environmental

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Therefore, the actual costs incurred will depend on the final amount, type, and extent of contamination discovered at these sites, the final cleanup standards mandated by the EPA or other governmental authorities, and other factors.

The EPA and various state regulatory agencies routinely promulgate and propose new rules and issue updated guidance to existing rules.

These rulemakings include, but are not limited to, rules for reciprocating internal combustion engine and combustion turbine maximum achievable control technology, air quality standards for one-hour nitrogen dioxide emissions, and volatile organic compound and methane new source performance standards impacting design and operation of storage vessels, pressure valves, and compressors.

The EPA previously issued its rule regarding National Ambient Air Quality Standards for ground-level ozone.

We are monitoring the rule's implementation as it will trigger additional federal and state regulatory actions that may impact our operations.

Implementation of the regulations is expected to result in impacts to our operations and increase the cost of additions to Property, plant, and equipment – net in the Consolidated Balance Sheet for both new and existing facilities in affected areas.

We are unable to reasonably estimate the cost of additions that may be required to meet the regulations at this time due to uncertainty created by various legal challenges to these regulations and the need for further specific regulatory guidance.

Our interstate natural gas pipelines consider prudently incurred environmental assessment and remediation costs and the costs associated with compliance with environmental standards to be recoverable through rates.

The EPA and various state regulatory agencies routinely propose and promulgate new rules and issue updated guidance to existing rules.

These rulemakings include, but are not limited to, rules for reciprocating internal combustion engine and combustion turbine maximum achievable control technology, reviews and updates to the National Ambient Air Quality Standards, and rules for new and existing source performance standards for volatile organic compounds and methane.

We continuously monitor these regulatory changes and how they may impact our operations.

Implementation of new or modified regulations may result in impacts to our operations and increase the cost of additions to Property, plant, and equipment – net in the Consolidated Balance Sheet for both new and existing facilities in affected areas;

however, due to regulatory uncertainty on final rule content and applicability timeframes, we are unable to reasonably estimate the cost these regulatory impacts at this time.

We consider prudently incurred environmental assessment and remediation costs and the costs associated with compliance with environmental standards to be recoverable through rates for our interstate natural gas pipelines.

To date, we have been permitted recovery of these environmental costs, and it is our intent to continue seeking recovery of such costs through future rate filings.

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