Portions of the Registrant’s Definitive Proxy Statement for the Registrant’s Annual Meeting of Stockholders to be held on April 28, 2020, are incorporated into Part III, as specifically set forth in Part III.

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•	Fee-based: We are paid a fee based on the volume of natural gas processed, generally measured in the Btu heating value. A portion of our fee-based processing revenue includes a share of the margins on the NGLs produced. For the year ended December 31, 2019, 80 percent of our NGL production volumes were under fee-based contracts.

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Noncash commodity-based: We also process gas under two types of commodity-based contracts, keep-whole and percent-of-liquids, where we receive consideration for our services in the form of NGLs. For a keep-whole arrangement we replace the Btu content of the retained NGLs with natural gas purchases, also known as shrink replacement gas. For a percent-of-liquids arrangement, we deliver an agreed-upon percentage of the extracted NGLs and retain the remainder. Retained NGLs are referred to as our equity NGL production. For the year ended December 31, 2019, 20 percent of our NGL production volumes were under noncash commodity-based contracts.

•	Obstacles to our expansion efforts, including delays or denials of necessary permits and opposition to hydrocarbon-based energy development;

•	Producer drilling activities impacting natural gas supplies supporting our gathering and processing volumes;

•	Retaining and attracting customers by continuing to provide reliable services;

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•	Revenue growth associated with additional infrastructure either completed or currently under construction;

•	Prices impacting our commodity-based activities;

•	Disciplined growth in our service areas.

•

Transmission & Gulf of Mexico is comprised of our interstate natural gas pipelines, Transco and Northwest Pipeline, as well as natural gas gathering, processing, and treating assets 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, and various petrochemical and feedstock pipelines in the Gulf Coast region, 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, 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 58 percent equity-method investment in Caiman II, and Appalachia Midstream Services, LLC, which owns equity-method investments with an approximate average 66 percent interest in multiple gas gathering systems in the Marcellus Shale (Appalachia Midstream Investments).

•

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, and a 15 percent equity-method investment in Brazos Permian II.

•	Other includes minor business activities that are not operating segments, as well as corporate operations.

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(1)	Includes 100 percent of the statistics associated with operated equity-method investments.

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(1)	Statistics reflect 100 percent of the assets from our 51 percent interest in Gulfstar One.

(2)	Includes 100 percent of the statistics associated with operated equity-method investments.

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(1)	Includes 100 percent of the volumes associated with operated equity-method investments.

(2)	Annual average Mbbls/d.

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(1)	Statistics reflect 100 percent of the assets from our 65 percent ownership in our Northeast JV and 66 percent ownership of Cardinal gathering system.

(2)	Includes 100 percent of the statistics associated with operated equity-method investments.

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(1)	Includes volumes associated with Susquehanna Supply Hub, the Northeast JV, and Utica Supply Hub, all of which are consolidated.

(2)	Includes 100 percent of the volumes associated with operated equity-method investments, including the Laurel Mountain Midstream partnership; and the Bradford Supply Hub and a portion of the Marcellus South Supply Hub within Appalachia Midstream Investments. Volumes handled by Blue Racer Midstream, LLC (Blue Racer), (gathering and processing), which we do not operate, are not included.

(3)	Annual average Mbbls/d.

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(1)	Includes 100 percent of the statistics associated with an operated equity-method investment.

(2)	Includes our 60 percent ownership of a gathering system in the Ryan Gulch area with 140 miles of pipeline and 0.2 Bcf/d of inlet capacity, and our 67 percent ownership of a gathering system at Allen Point with 8 miles of pipeline and 0.1 Bcf/d of inlet capacity. We operate both systems. We own and operate 100 percent of the balance of the Piceance gathering assets.

(1)	Includes 100 percent of the statistics associated with operated equity-method investments.

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(1)	Includes 100 percent of the volumes associated with operated equity-method investments, including RMM and Jackalope. Jackalope was a consolidated entity in 2017 and first- and second-quarter 2018, an equity-method investment during third- and fourth-quarter 2018 as well as first-quarter 2019, and sold effective with second-quarter 2019.

(2)	Annual average Mbbls/d.

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•	Costs of providing service, including depreciation expense;

•	Allowed rate of return, including the equity component of the capital structure and related income taxes;

•	Contract and volume throughput assumptions.

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•	Leakage from gathering systems, underground gas storage caverns, pipelines, processing or treating facilities, transportation facilities, and storage tanks;

•	Damage to facilities resulting from accidents during normal operations;

•	Damages to onshore and offshore equipment and facilities resulting from storm events or natural disasters;

•	Blowouts, cratering, and explosions.

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•	Levels of dividends to Williams stockholders;

•	Future credit ratings of Williams and its affiliates;

•	Amounts and nature of future capital expenditures;

•	Expansion and growth of our business and operations;

•	Expected in-service dates for capital projects;

•	Financial condition and liquidity;

•	Business strategy;

•	Cash flow from operations or results of operations;

•	Seasonality of certain business components;

•	Natural gas and natural gas liquids prices, supply, and demand;

•	Demand for our services.

•	Availability of supplies, market demand, and volatility of prices;

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•	Development and rate of adoption of alternative energy sources;

•	The impact of existing and future laws and regulations, the regulatory environment, environmental liabilities, and litigation, as well as our ability to obtain necessary permits and approvals, and achieve favorable rate proceeding outcomes;

•	Our exposure to the credit risk of our customers and counterparties;

•	Our ability to acquire new businesses and assets and successfully integrate those operations and assets into existing businesses as well as successfully expand our facilities, and to consummate asset sales on acceptable terms;

•	Whether we are able to successfully identify, evaluate, and timely execute our capital projects and investment opportunities;

•	The strength and financial resources of our competitors and the effects of competition;

•	The amount of cash distributions from and capital requirements of our investments and joint ventures in which we participate;

•	Whether we will be able to effectively execute our financing plan;

•	Increasing scrutiny and changing expectations from stakeholders with respect to our environmental, social and governance practices;

•	The physical and financial risks associated with climate change;

•	The impact of operational and developmental hazards and unforeseen interruptions;

•	Risks associated with weather and natural phenomena, including climate conditions and physical damage to our facilities;

•	Acts of terrorism, cybersecurity incidents, and related disruptions;

•	Our costs and funding obligations for defined benefit pension plans and other postretirement benefit plans;

•	Changes in maintenance and construction costs, as well as our ability to obtain sufficient construction related inputs including skilled labor;

•	Inflation, interest rates, and general economic conditions (including future disruptions and volatility in the global credit markets and the impact of these events on customers and suppliers);

•	Risks related to financing, including restrictions stemming from debt agreements, future changes in credit ratings as determined by nationally recognized credit rating agencies, and the availability and cost of capital;

•	Changes in the current geopolitical situation;

•	Whether we are able to pay current and expected levels of dividends;

•	Additional risks described in our filings with the Securities and Exchange Commission.

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•	Worldwide and domestic supplies of and demand for natural gas, NGLs, oil, and related commodities;

•	Turmoil in the Middle East and other producing regions;

•	The activities of the Organization of Petroleum Exporting Countries;

•	The level of consumer demand;

•	The price and availability of other types of fuels or feedstocks;

•	The availability of pipeline capacity;

•	Supply disruptions, including plant outages and transportation disruptions;

•	The price and quantity of foreign imports and domestic exports of natural gas and oil;

•	Domestic and foreign governmental regulations and taxes;

•	The credit of participants in the markets where products are bought and sold.

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•	Changing circumstances and deviations in variables could negatively impact our investment analysis, including our projections of revenues, earnings, and cash flow relating to potential investment targets, resulting in outcomes which are materially different than anticipated;

•	We could be required to contribute additional capital to support acquired businesses or assets;

•	We may assume liabilities that were not disclosed to us, that exceed our estimates and for which contractual protections are either unavailable or prove inadequate;

•	Acquisitions could disrupt our ongoing business, distract management, divert financial and operational resources from existing operations and make it difficult to maintain our current business standards, controls, and procedures;

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•	Acquisitions and capital projects may require substantial new capital, including proceeds from the issuance of debt or equity, and we may not be able to access capital markets or obtain acceptable terms.

•	We cannot control the amount of cash reserves determined to be necessary to operate the business, which reduces cash available for distributions;

•	We cannot control the amount of capital expenditures that we are required to fund and we are dependent on third parties to fund their required share of capital expenditures;

•	We may be subject to restrictions or limitations on our ability to sell or transfer our interests in the jointly owned assets;

•	We may be forced to offer rights of participation to other joint venture participants in the area of mutual interest;

•	We have limited ability to influence or control certain day to day activities affecting the operations;

•	We may have additional obligations, such as required capital contributions, that are important to the success of the operations.

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•	The level of existing and new competition in our businesses or from alternative sources, such as electricity, renewable resources, coal, fuel oils, or nuclear energy;

•

Natural gas and NGL prices, demand, availability, and margins in our markets. Higher prices for energy commodities related to our businesses could result in a decline in the demand for those commodities and, therefore, in customer contracts or throughput on our pipeline systems. Also, lower energy commodity prices could negatively impact our ability to maintain or achieve favorable contractual terms, including pricing, and could also result in a decline in the production of energy commodities resulting in reduced customer contracts, supply contracts, and throughput on our pipeline systems;

•	General economic, financial markets, and industry conditions;

•	The effects of regulation on us, our customers, and our contracting practices;

•	Our ability to understand our customers’ expectations, efficiently and reliably deliver high quality services and effectively manage customer relationships. The results of these efforts will impact our reputation and positioning in the market.

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•	Aging infrastructure and mechanical problems;

•	Damages to pipelines and pipeline blockages or other pipeline interruptions;

•	Uncontrolled releases of natural gas (including sour gas), NGLs, crude oil, or other products;

•	Collapse or failure of storage caverns;

•	Operator error;

•	Damage caused by third-party activity, such as operation of construction equipment;

•	Pollution and other environmental risks;

•	Fires, explosions, craterings, and blowouts;

•	Security risks, including cybersecurity;

•	Operating in a marine environment.

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•	The amount of cash that our subsidiaries distribute to us;

•	The amount of cash we generate from our operations, our working capital needs, our level of capital expenditures, and our ability to borrow;

•	The restrictions contained in our indentures and credit facility and our debt service requirements;

•	The cost of acquisitions, if any.

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•	Make it more difficult for us to satisfy our obligations with respect to our indebtedness, which could in turn result in an event of default on such indebtedness;

•	Impair our ability to obtain additional financing in the future for working capital, capital expenditures, acquisitions, general corporate purposes, or other purposes;

•	Diminish our ability to withstand a continued or future downturn in our business or the economy generally;

•	Require us to dedicate a substantial portion of our cash flow from operations to debt service payments, thereby reducing the availability of cash for working capital, capital expenditures, acquisitions, the payments of dividends, general corporate purposes, or other purposes;

•	Limit our flexibility in planning for, or reacting to, changes in our business and the industry in which we operate, including limiting our ability to expand or pursue our business activities and preventing us from engaging in certain transactions that might otherwise be considered beneficial to us.

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•	Transportation and sale for resale of natural gas in interstate commerce;

•	Rates, operating terms, types of services, and conditions of service;

•	Certification and construction of new interstate pipelines and storage facilities;

•	Acquisition, extension, disposition, or abandonment of existing interstate pipelines and storage facilities;

•	Accounts and records;

•	Depreciation and amortization policies;

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•	Relationships with affiliated companies who are involved in marketing functions of the natural gas business;

•	Market manipulation in connection with interstate sales, purchases, or transportation of natural gas.

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(1)	Income (loss) from continuing operations:

•	For 2019 includes $464 million of impairments of certain assets, including a $354 million impairment of Constitution’s capitalized project costs, and $186 million impairments of certain equity-method investments, partially offset by a $122 million gain on the sale of our Jackalope equity-method investment;

•	For 2018 includes a $1.849 billion impairment of certain assets located in the Barnett Shale region, partially offset by a $591 million gain on the sale of our Four Corners area assets, a $141 million gain on the deconsolidation of certain Permian assets, and a $101 million gain from the sale of our Gulf Coast pipeline system assets;

•	For 2017 includes a $1.923 billion benefit for income taxes resulting from Tax Reform rate change and a $1.095 billion pre-tax gain on the sale of our Geismar Interest, partially offset by $1.248 billion of pre-tax impairments of certain assets and $776 million of pre-tax regulatory charges resulting from Tax Reform;

•	For 2016 includes an $873 million impairment of certain assets and a $430 million impairment of certain equity-method investments;

•	For 2015 includes a $1.4 billion impairment of certain equity-method investments and a $1.1 billion impairment of goodwill.

(2)	Income (loss) from continuing operations attributable to the Williams Companies, Inc. available to common stockholders:

•	For 2019 includes benefit of $209 million reflecting the noncontrolling interests’ share of the impairment of Constitution’s capitalized project costs.

(3)	Stockholders’ equity at December 31:

•	For 2019 includes a decrease related to a sale of a partial interest in our Northeast JV business;

•	For 2018 includes an increase reflecting our issuance of common stock associated with our merger with WPZ in August 2018;

•	For 2017 includes increases reflecting our issuance of common stock as part of our Financial Repositioning and a significant increase in our ownership of WPZ.

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•

Atlantic-Gulf is comprised of our interstate natural gas pipeline, Transco, and 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, as well as a 50 percent equity-method investment in Gulfstream, a 60 percent equity-method investment in Discovery, and a 41 percent equity-method investment in Constitution as of December 31, 2019.

•

Northeast G&P is comprised of our midstream gathering, processing, and fractionation businesses in the Marcellus Shale region primarily in Pennsylvania, 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 58 percent equity-method investment in Caiman II, and Appalachia Midstream Services, LLC, which owns equity-method investments with an approximate average 66 percent interest in multiple gas gathering systems in the Marcellus Shale (Appalachia Midstream Investments).

•

West is comprised of our interstate natural gas pipeline, Northwest Pipeline, and 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, Delaware, 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, and a 15 percent equity-method investment in Brazos Permian II. West also included our former natural gas gathering and processing assets in the Four Corners area of New Mexico and Colorado, which were sold during the fourth quarter of 2018 (see Note 3 – Acquisitions and Divestitures of Notes to Consolidated Financial Statements), and our former 50 percent interest in Jackalope (an equity-method investment following deconsolidation as of June 30, 2018), which was sold in April 2019,

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Other includes minor business activities that are not operating segments, as well as corporate operations. Other also includes our previously owned operations, including an 88.5 percent undivided interest in an olefins production facility in Geismar, Louisiana, which was sold in July 2017 (see Note 3 – Acquisitions and Divestitures of Notes to Consolidated Financial Statements), and a refinery grade propylene splitter in the Gulf region, which was sold in June 2017.

•	A $1.451 billion decrease in Impairment of certain assets;

•

A $431 million increase in Service revenues primarily associated with Transco expansion projects, the consolidation of UEOM beginning March 2019, and growth in Northeast G&P volumes, partially offset by lower revenues from our Barnett Shale operations primarily associated with the reduced recognition of deferred revenue and the end of a contractual MVC period, as well as the absence of revenues from operations sold or deconsolidated during 2018;

•	A $484 million decrease to Net income (loss) attributable to noncontrolling interests primarily due to the WPZ Merger in the third quarter of 2018, as well as the noncontrolling interests’ share of the 2019 Constitution impairment.

•	A $694 million decrease in the Gain on sale of certain assets and businesses primarily related to the sale of the Four Corners area business in the fourth quarter of 2018;

•	A $266 million decrease in Other investing income (loss) – net primarily due to the absence of 2018 gains on deconsolidations and 2019 impairments of equity-method investments, partially offset by a 2019 gain on the sale of our interest in Jackalope;

•	$138 million of lower commodity margins;

•	$74 million of higher net interest expense;

•	$58 million lower allowance for equity funds used during construction (AFUDC);

•	A $197 million increase in provision for income taxes driven by higher pre-tax income, partially offset by the absence of a 2018 charge to establish a valuation allowance on deferred tax assets that may not be realized following the WPZ merger.

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•	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;

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

•	Unexpected changes in customer drilling and production activities, which could negatively impact gathering and processing volumes;

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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;

•	Physical damages to facilities, including damage to offshore facilities by named windstorms;

•	Other risks set forth under Part I, Item 1A. Risk Factors in this report.

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

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•	A $90 million decrease in commodity marketing sales driven by a $149 million decrease in crude oil sales as this activity is now presented on a net basis within Product costs in conjunction with the adoption of ASC 606, partially offset by a $59 million increase in NGL marketing sales primarily reflecting 20 percent higher non-ethane prices;

•	A $14 million decrease in sales associated with the production of our equity NGLs, as further described below as part of our commodity margins;

•	A $57 million increase in system management gas sales. System management gas sales are offset in Product costs and therefore have little impact to Modified EBITDA.

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•	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.

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•	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.

•	A $65 million increase in gathering fee revenues at Susquehanna Supply Hub due to 13 percent higher gathering volumes reflecting increased customer production;

•	A $24 million increase at Ohio River Supply Hub reflecting higher gathering volumes due to increased customer production;

•	An $11 million increase in Utica gathering fee revenues reflecting higher rates and volumes.

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•	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;

•	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.

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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;

•	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.

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A $64 million decrease primarily associated with implementing the new revenue guidance under ASC 606 including a $118 million decrease related to lower amortization of deferred revenue associated with the up-front cash payments received in conjunction with the fourth quarter 2016 Barnett Shale and Mid-Continent contract restructurings, partially offset by a $54 million increase related to other deferred revenue amortization primarily in the Permian basin;

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•	A $42 million decrease associated with the sale of our Four Corners area assets in October 2018;

•	A $30 million decrease at Northwest Pipeline primarily due to the reduction of its rates as a result of a rate case settlement that became effective January 1, 2018;

•	A $29 million decrease following the Jackalope deconsolidation in second-quarter 2018;

•	A $15 million decrease driven by lower gathering volumes primarily in the Eagle Ford Shale, Barnett Shale, and Mid-Continent regions, partially offset by higher volumes in the Niobrara (prior to the Jackalope deconsolidation), Piceance, and Permian regions;

•	A $21 million increase associated with higher gathering and processing rates in the Piceance region driven by higher NGL prices as well as higher average gathering and processing rates across most other areas, partially offset by lower contract rates primarily in the Haynesville Shale region.

•	A $373 million increase in marketing sales primarily due to increases in realized NGL prices including a 14 percent increase in average non-ethane per-unit sales prices and a 25 percent increase in ethane prices, in addition to a 15 percent increase in ethane volumes (more than offset by higher Product costs);

•	A $47 million increase in sales associated with the production of our equity NGLs, as further described below as part of our commodity margins;

•	An $18 million increase in system management gas sales due to a change in presentation in accordance with ASC 606, which are more than offset in Product costs and, therefore, have little impact on Modified EBITDA.

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•	The absence of the $66 million impairment of certain idle pipelines in the second quarter of 2018 (see Note 18 – Fair Value Measurements and Guarantees 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 (see Note 7 – Other Income and Expenses of Notes to Consolidated Financial Statements).

•	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;

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•	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 $1.095 billion gain on the sale of our Geismar Interest in 2017 (see Note 3 – Acquisitions and Divestitures of Notes to Consolidated Financial Statements);

•	The absence of $54 million of Modified EBITDA associated with the results of our former Geismar Olefins and RGP Splitter plants subsequent to their sale in July 2017;

•	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), as previously mentioned;

•	A $34 million decrease due to the absence of a net gain on early retirement of debt in 2017 and a loss on early retirement of debt in 2018 (see Note 7 – Other Income and Expenses of Notes to Consolidated Financial Statements);

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

•	$20 million in costs in 2018 associated with the WPZ Merger, as previously mentioned;

•	The absence of a $12 million gain on the sale of the Refinery Grade Propylene Splitter in 2017 (see Note 7 – Other Income and Expenses of Notes to Consolidated Financial Statements).

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The absence of a $68 million impairment for a certain NGL pipeline asset in the third quarter of 2017 and a$23 million impairment of an olefins pipeline project in the Gulf Coast region in the second quarter of 2017, partially offset by a $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);

•	A $62 million favorable change for lower charges to reduce regulatory assets related to deferred taxes on AFUDC resulting from Tax Reform (see Note 7 – Other Income and Expenses of Notes to Consolidated Financial Statements);

•	$40 million of lower costs, driven by the absence of expenses associated with severance and related costs, Financial Repositioning, and strategic alternative costs;

•	A $37 million increase associated with the benefit of establishing a regulatory asset associated with an increase in Transco’s estimated deferred state income tax rate following the WPZ Merger, as previously mentioned;

•	A $30 million favorable change in the settlement charge expense related to the program to pay out certain deferred vested pension benefits of employees associated with former operations (see Note 10 – Employee Benefit Plans of Notes to Consolidated Financial Statements);

•	A $20 million gain on the sale of certain assets and operations located in the Gulf Coast area, as previously mentioned.

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(1)

In managing our available liquidity, we do not expect a maximum outstanding amount in excess of the capacity of our credit facility inclusive of any outstanding amounts under our commercial paper program. We had no commercial paper outstanding as of December 31, 2019. The highest amount outstanding under our commercial paper program and credit facility during 2019 was $1.226 billion. At December 31, 2019, we were in compliance with the financial covenants associated with our credit facility. See Note 15 – Debt and Banking Arrangements of Notes to Consolidated Financial Statements for additional information on our credit facility and commercial paper program.

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(1)	Includes any borrowings outstanding under credit facilities, but does not include any related variable-rate interest payments.

(2)	Includes:

•	Approximately $206 million in open property, plant, and equipment purchase orders;

•	An estimated $589 million long-term mixed NGLs purchase obligation with index-based pricing terms that is reflected in this table at December 31, 2019 prices;

•	An estimated $193 million long-term ethane purchase obligation with index-based pricing terms that primarily supplies third parties at their plants and is reflected in this table at a value calculated using December 31, 2019 prices. Any excess purchased volumes may be sold at comparable market prices;

•	An estimated $163 million long-term ethane purchase obligation with index-based pricing terms that primarily supplies a third party for consumption at their plant and is reflected in this table at a value calculated using December 31, 2019 prices. Any excess purchased volumes may be sold at comparable market prices;

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An estimated $149 million long-term ethane purchase obligation with index-based pricing terms that is reflected in this table at December 31, 2019 prices. This obligation is part of an overall exchange agreement whereby volumes we transport on OPPL are sold at a third-party fractionator near Conway, Kansas, and we are subsequently obligated to purchase ethane volumes at Mont Belvieu. The purchased ethane volumes may be utilized or sold at comparable prices in the Mont Belvieu market;

•	An estimated $129 million long-term mixed NGLs purchase obligation with index-based pricing terms that is reflected in this table at December 31, 2019 prices.

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(3)

Does not include estimated contributions to our pension and other postretirement benefit plans. We made contributions to our pension and other postretirement benefit plans of $68 million in 2019 and $93 million in 2018. In 2020, we expect to contribute approximately $19 million to these plans (see Note 10 – Employee Benefit Plans of Notes to Consolidated Financial Statements). Tax-qualified pension plans are required to meet minimum contribution requirements. In the past, we have contributed amounts to our tax-qualified pension plans in excess of the minimum required contribution. These excess amounts can be used to offset future minimum contribution requirements. During 2019, we contributed $60 million to our tax-qualified pension plans. In addition to these contributions, a portion of the excess contributions was used to meet the minimum contribution requirements. During 2020, we expect to contribute approximately $10 million to our tax-qualified pension plans and use excess amounts to satisfy minimum contribution requirements, if needed. Additionally, estimated future minimum funding requirements may vary significantly from historical requirements if actual results differ significantly from estimated results for assumptions such as returns on plan assets, interest rates, retirement rates, mortality, and other significant assumptions or by changes to current legislation and regulations.

(4)	We have not included income tax liabilities in the table above. See Note 8 – Provision (Benefit) for Income Taxes of Notes to Consolidated Financial Statements for a discussion of income taxes, including our contingent tax liability reserves.

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(1)	Includes unamortized discount / premium and debt issuance costs.

(2)	The weighted-average interest rate for our $160 million credit facility borrowing at December 31, 2018, was 3.77 percent.

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*	Accumulated Other Comprehensive Income (Loss)

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Note 1 – General, Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies

General

Unless the context clearly indicates otherwise, references in this report to “Williams,” “we,” “our,” “us,” or like terms refer to The Williams Companies, Inc. and its subsidiaries. Unless the context clearly indicates otherwise, references to “Williams,” “we,” “our,” and “us” include the operations in which we own interests accounted for as equity-method investments that are not consolidated in our financial statements. When we refer to our equity investees by name, we are referring exclusively to their businesses and operations.

WPZ Merger

On August 10, 2018, we completed our merger with Williams Partners L.P. (WPZ), our previously consolidated master limited partnership, pursuant to which we acquired all of the approximately 256 million publicly held outstanding common units of WPZ in exchange for 382 million shares of our common stock (WPZ Merger). Williams continued as the surviving entity. The WPZ Merger was accounted for as a noncash equity transaction resulting in increases to Common stock of $382 million, Capital in excess of par value of $6.112 billion, and Regulatory assets, deferred charges, and other of $33 million and decreases to Accumulated other comprehensive income (loss) (AOCI) of $3 million, Noncontrolling interests in consolidated subsidiaries of $4.629 billion, and Deferred income tax liabilities of $1.829 billion in the Consolidated Balance Sheet. Prior to the completion of the WPZ Merger and pursuant to its distribution reinvestment program, WPZ had issued common units to the public in 2018 and 2017 associated with reinvested distributions of $46 million and $61 million, respectively.

Financial Repositioning

In January 2017, we entered into agreements with WPZ, wherein we permanently waived the general partner’s incentive distribution rights and converted our 2 percent general partner interest in WPZ to a noneconomic interest in exchange for 289 million newly issued WPZ common units. Pursuant to this agreement, we also purchased approximately 277 thousand WPZ common units for $10 million. Additionally, we purchased approximately 59 million common units of WPZ at a price of $36.08586 per unit in a private placement transaction, funded with proceeds from our equity offering (see Note 16 – Stockholders’ Equity). According to the terms of this agreement, concurrent with WPZ’s quarterly distributions in February 2017 and May 2017, we paid additional consideration totaling $56 million to WPZ for these units.

Description of Business

We are a Delaware corporation whose common stock is listed and traded on the New York Stock Exchange. Our operations are located in the United States and are presented within the following reportable segments: Atlantic-Gulf, Northeast G&P, and West, consistent with the manner in which our chief operating decision maker evaluates performance and allocates resources. All remaining business activities as well as corporate activities are included in Other.

Atlantic-Gulf is comprised of our interstate natural gas pipeline, Transcontinental Gas Pipe Line Company, LLC (Transco), and 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 LLC (Gulfstar One) (a consolidated variable interest entity, or VIE), which is a proprietary floating production system, as well as a 50 percent equity-method investment in Gulfstream Natural Gas System, L.L.C. (Gulfstream), a 60 percent equity-method investment in Discovery Producer Services LLC (Discovery), and, at December 31, 2019, a 41 percent equity-method investment in Constitution Pipeline Company, LLC (Constitution) (see Note 4 – Variable Interest Entities).

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 66 percent interest in Cardinal Gas Services, L.L.C. (Cardinal) (a consolidated VIE) which operates in Ohio, a 69 percent equity-method investment in Laurel Mountain Midstream, LLC (Laurel Mountain), a 58 percent equity-method

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investment in Caiman Energy II, LLC (Caiman II), and Appalachia Midstream Services, LLC, which owns equity-method investments with an approximate average 66 percent interest in multiple gas gathering systems in the Marcellus Shale (Appalachia Midstream Investments). Northeast G&P includes a 65 percent interest in Ohio Valley Midstream LLC (Northeast JV) (a consolidated VIE) which operates in West Virginia, Ohio, and Pennsylvania. The Northeast JV includes our Ohio Valley assets and Utica East Ohio Midstream LLC (UEOM), a former equity-method investment in which we acquired the remaining ownership interest in March 2019 (see Note 3 – Acquisitions and Divestitures).

West is comprised of our interstate natural gas pipeline, Northwest Pipeline LLC (Northwest Pipeline), and 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, Delaware, and Permian basins. This segment also includes our natural gas liquid (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 Overland Pass Pipeline Company LLC (OPPL), a 50 percent equity-method investment in Rocky Mountain Midstream Holdings LLC (RMM), and a 15 percent equity-method investment in Brazos Permian II, LLC (Brazos Permian II). West also included our former natural gas gathering and processing assets in the Four Corners area of New Mexico and Colorado, which were sold during the fourth quarter of 2018 (see Note 3 – Acquisitions and Divestitures), our former 50 percent interest in Jackalope Gas Gathering Services, L.L.C. (Jackalope) (an equity-method investment following deconsolidation as of June 30, 2018), which was sold in April 2019, and our previously owned 50 percent equity-method investment in the Delaware basin gas gathering system (DBJV) (see Note 6 – Investing Activities).

Other includes minor business activities that are not operating segments, as well as corporate operations. Other also includes our previously owned operations, including an 88.5 percent undivided interest in an olefins production facility in Geismar, Louisiana (Geismar Interest), which was sold in July 2017 (see Note 3 – Acquisitions and Divestitures), and a refinery grade propylene splitter in the Gulf region, which was sold in June 2017.

Basis of Presentation

Discontinued operations

Unless indicated otherwise, the information in the Notes to Consolidated Financial Statements relates to our continuing operations.

Significant risks and uncertainties

We believe that the carrying value of certain of our property, plant, and equipment and other identifiable intangible assets, notably certain acquired assets accounted for as business combinations between 2012 and 2014, may be in excess of current fair value. However, the carrying value of these assets, in our judgment, continues to be recoverable based on our evaluation of undiscounted future cash flows. It is reasonably possible that future strategic decisions, including transactions such as monetizing non-core assets or contributing assets to new ventures with third parties, as well as unfavorable changes in expected producer activities could impact our assumptions and ultimately result in impairments of these assets. Such transactions or developments may also indicate that certain of our equity-method investments have experienced other-than-temporary declines in value, which could result in impairment, or that the fair value of the reporting unit for our goodwill is less than its carrying amount, which would result in impairment.

Summary of Significant Accounting Policies

Principles of consolidation

The consolidated financial statements include the accounts of all entities that we control and our proportionate interest in the accounts of certain ventures in which we own an undivided interest. Our judgment is required to evaluate whether we control an entity. Key areas of that evaluation include:

•	Determining whether an entity is a VIE;

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•	Determining whether we are the primary beneficiary of a VIE, including evaluating which activities of the VIE most significantly impact its economic performance and the degree of power that we and our related parties have over those activities through our variable interests;

•	Identifying events that require reconsideration of whether an entity is a VIE and continuously evaluating whether we are a VIE’s primary beneficiary;

•	Evaluating whether other owners in entities that are not VIEs are able to effectively participate in significant decisions that would be expected to be made in the ordinary course of business such that we do not have the power to control such entities.

We apply the equity method of accounting to investments over which we exercise significant influence but do not control. Distributions received from equity-method investees are presented in the Consolidated Statement of Cash Flows according to the nature of the distributions approach, which classifies distributions received from equity-method investees as either returns on investment (cash inflows from operating activities) or returns of investment (cash inflows from investing activities) based on the nature of the activities of the equity-method investee that generated the distribution.

Equity-method investment basis differences

Differences between the cost of our equity-method investments and our underlying equity in the net assets of investees are accounted for as if the investees were consolidated subsidiaries. Equity earnings (losses) in the Consolidated Statement of Operations includes our allocable share of net income (loss) of investees adjusted for any depreciation and amortization, as applicable, associated with basis differences.

Use of estimates

The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the amounts reported in the consolidated financial statements and accompanying notes. Actual results could differ from those estimates.

Significant estimates and assumptions include:

•	Impairment assessments of investments, property, plant, and equipment, goodwill, and other identifiable intangible assets;

•	Litigation-related contingencies;

•	Environmental remediation obligations;

•	Depreciation and/or amortization of long-lived assets;

•	Depreciation and/or amortization of equity-method investment basis differences;

•	Asset retirement obligations (AROs);

•	Pension and postretirement valuation variables;

•	Measurement of regulatory liabilities;

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•	Measurement of deferred income tax assets and liabilities, including assumptions related to the realization of deferred income tax assets;

•	Revenue recognition, including estimates utilized in recognition of deferred revenue;

•	Purchase price accounting.

These estimates are discussed further throughout these notes.

Regulatory accounting

Transco and Northwest Pipeline are regulated by the Federal Energy Regulatory Commission (FERC). Their rates, which are established by the FERC, are designed to recover the costs of providing the regulated services, and their competitive environment makes it probable that such rates can be charged and collected. Therefore, we have determined that it is appropriate under Accounting Standards Codification (ASC) Topic 980, “Regulated Operations,” (ASC 980) to account for and report regulatory assets and liabilities related to these operations consistent with the economic effect of the way in which their rates are established. Accounting for these operations that are regulated can differ from the accounting requirements for nonregulated operations. For example, for regulated operations, allowance for funds used during construction (AFUDC) represents the estimated cost of debt and equity funds applicable to utility plant in the process of construction and is capitalized as a cost of property, plant, and equipment because it constitutes an actual cost of construction under established regulatory practices; nonregulated operations are only allowed to capitalize the cost of debt funds related to construction activities, while a component for equity is prohibited. The components of our regulatory assets and liabilities relate to the effects of deferred taxes on equity funds used during construction, asset retirement obligations, fuel cost differentials, levelized incremental depreciation, negative salvage, pension and other postretirement benefits, and rate allowances for deferred income taxes at a historically higher federal income tax rate.

In December 2017, the Tax Cuts and Jobs Act (Tax Reform) was enacted, which, among other things, reduced the federal corporate income tax rate from 35 percent to 21 percent (see Note 8 – Provision (Benefit) for Income Taxes). In accordance with ASC 980-740-25-2, Transco and Northwest Pipeline have recognized regulatory liabilities to reflect the probable return to customers through future rates of the future decrease in income taxes payable associated with Tax Reform. These liabilities represent an obligation to return amounts directly to our customers. While a majority of our customers have entered into tariff rates based on our cost-of-service proceedings and related rate base therein, certain other contracts with customers reflect contractually-based rates that are designed to recover the cost of providing those services, including an allowance for income taxes, with no expected future rate adjustment for the term of those contracts. This relative mix of contracts for services was considered in determining the probable amount to be returned to customers through future rates. The regulatory liabilities were recorded in December 2017 through regulatory charges to operating income totaling $674 million. Adjustments recorded in 2018 decreased this amount by $17 million. For Transco, the timing and actual amount of the return to the customers is stated in its formal stipulation and agreement that has been filed, subject to FERC approval (See Note 19 – Contingent Liabilities and Commitments).

Certain of our equity-method investees recorded similar regulatory liabilities, for which our Equity earnings (losses) in the Consolidated Statement of Operations for 2017 were reduced by $11 million related to our proportionate share of the associated regulatory charges.

Our regulatory assets associated with the effects of deferred taxes on equity funds used during construction were also impacted by Tax Reform and were reduced by $102 million in December 2017 through a charge to Other income (expense) – net below Operating income (loss) in the Consolidated Statement of Operations (see Note 7 – Other Income and Expenses). This amount, along with the previously described charges for establishing the regulatory liabilities resulting from Tax Reform, is reported within Regulatory charges resulting from Tax Reform within the Consolidated Statement of Cash Flows.

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Our current and noncurrent regulatory asset and liability balances for the years ended December 31, 2019 and 2018 are as follows:

	December 31,
	2019				2018
	(Millions)
Current assets reported within Other current assets and deferred charges	$	72			$	103
Noncurrent assets reported within Regulatory assets, deferred charges, and other	466				495
Total regulated assets	$	538			$	598
Current liabilities reported within Accrued liabilities	$	60			$	5
Noncurrent liabilities reported within Regulatory liabilities, deferred income, and other	1,277				1,321
Total regulated liabilities	$	1,337			$	1,326

Cash and cash equivalents

Cash and cash equivalents in the Consolidated Balance Sheet consist of highly liquid investments with original maturities of three months or less when acquired.

Accounts receivable

Accounts receivable are carried on a gross basis, with no discounting, less an allowance for doubtful accounts. We estimate the allowance for doubtful accounts based on existing economic conditions, the financial condition of our customers, and the amount and age of past due accounts. We do not offer extended payment terms and typically receive payment within one month. We consider receivables past due if full payment is not received by the contractual due date. Interest income related to past due accounts receivable is generally recognized at the time full payment is received or collectability is assured. Past due accounts are generally written off against the allowance for doubtful accounts only after all collection attempts have been exhausted.

Inventories

Inventories in the Consolidated Balance Sheet primarily consist of NGLs, natural gas in underground storage, and materials and supplies and are stated at the lower of cost or net realizable value. The cost of inventories is primarily determined using the average-cost method.

Property, plant, and equipment

Property, plant, and equipment is initially recorded at cost. We base the carrying value of these assets on estimates, assumptions, and judgments relative to capitalized costs, useful lives, and salvage values.

As regulated entities, Northwest Pipeline and Transco provide for depreciation using the straight-line method at FERC-prescribed rates. Depreciation for nonregulated entities is provided primarily on the straight-line method over estimated useful lives, except for certain offshore facilities that apply an accelerated depreciation method.

Gains or losses from the ordinary sale or retirement of property, plant, and equipment for regulated pipelines are credited or charged to accumulated depreciation. Other gains or losses are recorded in Other (income) expense – net included in Operating income (loss) in the Consolidated Statement of Operations.

Ordinary maintenance and repair costs are generally expensed as incurred. Costs of major renewals and replacements are capitalized as property, plant, and equipment.

We record a liability and increase the basis in the underlying asset for the present value of each expected future ARO at the time the liability is initially incurred, typically when the asset is acquired or constructed. As regulated

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entities, Northwest Pipeline and Transco offset the depreciation of the underlying asset that is attributable to capitalized ARO cost to a regulatory asset as we expect to recover these amounts in future rates. We measure changes in the liability due to passage of time by applying an interest rate to the liability balance. This amount is recognized as an increase in the carrying amount of the liability and as a corresponding accretion expense included in Operating and maintenance expenses in the Consolidated Statement of Operations, except for regulated entities, for which the liability is offset by a regulatory asset. The regulatory asset is amortized commensurate with our collection of those costs in rates.

Measurements of AROs include, as a component of future expected costs, an estimate of the price that a third party would demand, and could expect to receive, for bearing the uncertainties inherent in the obligations, sometimes referred to as a market-risk premium.

Goodwill

Goodwill included within Intangible assets – net of accumulated amortization in the Consolidated Balance Sheet represents the excess of the consideration, plus the fair value of any noncontrolling interest or any previously held equity interest, over the fair value of the net assets acquired. It is not subject to amortization but is evaluated annually as of October 1 for impairment or more frequently if impairment indicators are present that would indicate it is more likely than not that the fair value of the reporting unit is less than its carrying amount. As part of the evaluation, we compare our estimate of the fair value of the reporting unit with its carrying value, including goodwill. If the carrying value of the reporting unit exceeds its fair value, an impairment charge is recorded for the difference (not to exceed the carrying value of goodwill). Judgments and assumptions are inherent in our management’s estimates of fair value.

Other intangible assets

Our identifiable intangible assets included within Intangible assets – net of accumulated amortization in the Consolidated Balance Sheet are primarily related to gas gathering, processing, and fractionation contractual customer relationships. Our intangible assets are amortized on a straight-line basis over the period in which these assets contribute to our cash flows. We evaluate these assets for changes in the expected remaining useful lives and would reflect any changes prospectively through amortization over the revised remaining useful life.

Impairment of property, plant, and equipment, other identifiable intangible assets, and investments

We evaluate our property, plant, and equipment and other identifiable intangible assets for impairment when events or changes in circumstances indicate, in our judgment, that the carrying value of such assets may not be recoverable. When an indicator of impairment has occurred, we compare our estimate of undiscounted future cash flows attributable to the assets to the carrying value of the assets to determine whether an impairment has occurred and we may apply a probability-weighted approach to consider the likelihood of different cash flow assumptions and possible outcomes including selling in the near term or holding for the remaining estimated useful life. If an impairment of the carrying value has occurred, we determine the amount of the impairment recognized in the financial statements by estimating the fair value of the assets and recording a loss for the amount that the carrying value exceeds the estimated fair value. This evaluation is performed at the lowest level for which separately identifiable cash flows exist.

For assets identified to be disposed of in the future and considered held for sale, we compare the carrying value to the estimated fair value less the cost to sell to determine if recognition of an impairment is required. Until the assets are disposed of, the estimated fair value, which includes estimated cash flows from operations until the assumed date of sale, is recalculated when related events or circumstances change.

We evaluate our investments for impairment when events or changes in circumstances indicate, in our judgment, that the carrying value of such investments may have experienced an other-than-temporary decline in value. When evidence of loss in value has occurred, we compare our estimate of fair value of the investment to the carrying value of the investment to determine whether an impairment has occurred. If the estimated fair value is less than the carrying value and we consider the decline in value to be other-than-temporary, the excess of the carrying value over the fair value is recognized in the consolidated financial statements as an impairment charge.

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Judgments and assumptions are inherent in our estimate of undiscounted future cash flows and an asset’s or investment’s fair value. Additionally, judgment is used to determine the probability of sale with respect to assets considered for disposal.

Contingent liabilities

We record liabilities for estimated loss contingencies, including environmental matters, when we assess that a loss is probable, and the amount of the loss can be reasonably estimated. These liabilities are calculated based upon our assumptions and estimates with respect to the likelihood or amount of loss and upon advice of legal counsel, engineers, or other third parties regarding the probable outcomes of the matters. These calculations are made without consideration of any potential recovery from third parties. We recognize insurance recoveries or reimbursements from others when realizable. Revisions to these liabilities are generally reflected in income when new or different facts or information become known or circumstances change that affect the previous assumptions or estimates.

Cash flows from revolving credit facilities and commercial paper program

Proceeds and payments related to borrowings under our credit facilities are reflected in the financing activities in the Consolidated Statement of Cash Flows on a gross basis. Proceeds and payments related to borrowings under our commercial paper program are reflected in the financing activities in the Consolidated Statement of Cash Flows on a net basis, as the outstanding notes generally have maturity dates less than three months from the date of issuance. (See Note 15 – Debt and Banking Arrangements.)

Treasury stock

Treasury stock purchases are accounted for under the cost method whereby the entire cost of the acquired stock is recorded as Treasury stock, at cost in the Consolidated Balance Sheet. Gains and losses on the subsequent reissuance of shares are credited or charged to Capital in excess of par value in the Consolidated Balance Sheet using the average-cost method.

Derivative instruments and hedging activities

We may utilize derivatives to manage a portion of our commodity price risk. These instruments consist primarily of swaps, futures, and forward contracts involving short- and long-term purchases and sales of energy commodities. We report the fair value of derivatives, except those for which the normal purchases and normal sales exception has been elected, in Other current assets and deferred charges; Regulatory assets, deferred charges, and other; Accrued liabilities; or Regulatory liabilities, deferred income, and other in the Consolidated Balance Sheet. We determine the current and noncurrent classification based on the timing of expected future cash flows of individual trades. We report these amounts on a gross basis. Additionally, we report cash collateral receivables and payables with our counterparties on a gross basis. (See Note 18 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk.)

The accounting for the changes in fair value of a commodity derivative can be summarized as follows:

Derivative Treatment		Accounting Method
Normal purchases and normal sales exception		Accrual accounting
Designated in a qualifying hedging relationship		Hedge accounting
All other derivatives		Mark-to-market accounting

We may elect the normal purchases and normal sales exception for certain short- and long-term purchases and sales of physical energy commodities. Under accrual accounting, any change in the fair value of these derivatives is not reflected on the balance sheet after the initial election of the exception.

We may also designate a hedging relationship for certain commodity derivatives. For a derivative to qualify for designation in a hedging relationship, it must meet specific criteria and we must maintain appropriate documentation.

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We establish hedging relationships pursuant to our risk management policies. We evaluate the hedging relationships at the inception of the hedge and on an ongoing basis to determine whether the hedging relationship is, and is expected to remain, highly effective in achieving offsetting changes in fair value or cash flows attributable to the underlying risk being hedged. We also regularly assess whether the hedged forecasted transaction is probable of occurring. If a derivative ceases to be or is no longer expected to be highly effective, or if we believe the likelihood of occurrence of the hedged forecasted transaction is no longer probable, hedge accounting is discontinued prospectively, and future changes in the fair value of the derivative are recognized currently in Product sales or Product costs in the Consolidated Statement of Operations.

For commodity derivatives designated as a cash flow hedge, the change in fair value of the derivative is reported in AOCI in the Consolidated Balance Sheet and reclassified into earnings in the period in which the hedged item affects earnings. Gains or losses deferred in AOCI associated with terminated derivatives, derivatives that cease to be highly effective hedges, derivatives for which the forecasted transaction is reasonably possible but no longer probable of occurring, and cash flow hedges that have been otherwise discontinued remain in AOCI until the hedged item affects earnings. If it becomes probable that the forecasted transaction designated as the hedged item in a cash flow hedge will not occur, any gain or loss deferred in AOCI is recognized in Product sales or Product costs in the Consolidated Statement of Operations at that time. The change in likelihood of a forecasted transaction is a judgmental decision that includes qualitative assessments made by us.

For commodity derivatives that are not designated in a hedging relationship, and for which we have not elected the normal purchases and normal sales exception, we report changes in fair value currently in Product sales or Product costs in the Consolidated Statement of Operations.

Certain gains and losses on derivative instruments included in the Consolidated Statement of Operations are netted together to a single net gain or loss, while other gains and losses are reported on a gross basis. Gains and losses recorded on a net basis include unrealized gains and losses on all derivatives that are not designated as hedges and for which we have not elected the normal purchases and normal sales exception.

Realized gains and losses on derivatives that require physical delivery, as well as natural gas derivatives for NGL processing activities and which are not held for trading purposes nor were entered into as a pre-contemplated buy/sell arrangement, are recorded on a gross basis.

Revenue recognition (subsequent to the adoption of ASC 606 effective January 1, 2018)

Customers in our gas pipeline businesses are comprised of public utilities, municipalities, gas marketers and producers, intrastate pipelines, direct industrial users, and electrical generators. Customers in our midstream businesses are comprised of oil and natural gas producer counterparties. Customers for our product sales are comprised of public utilities, gas marketers, and direct industrial users.

Service revenue contracts from our gas pipeline and midstream businesses contain a series of distinct services, with the majority of our contracts having a single performance obligation that is satisfied over time as the customer simultaneously receives and consumes the benefits provided by our performance. Most of our product sales contracts have a single performance obligation with revenue recognized at a point in time when the products have been sold and delivered to the customer.

Certain customers reimburse us for costs we incur associated with construction of property, plant, and equipment utilized in our operations. For our rate-regulated gas pipeline businesses that apply ASC 980, we follow FERC guidelines with respect to reimbursement of construction costs. FERC tariffs only allow for cost reimbursement and are non-negotiable in nature; thus, in our judgment, the construction activities do not represent an ongoing major and central operation of our gas pipeline businesses and are not within the scope of ASC Topic 606, “Revenue from Contracts with Customers” (ASC 606). Accordingly, cost reimbursements are treated as a reduction to the cost of the constructed asset. For our midstream businesses, reimbursement and service contracts with customers are viewed together as providing the same commercial objective, as we have the ability to negotiate the mix of consideration between reimbursements

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and amounts billed over time. Accordingly, we generally recognize reimbursements of construction costs from customers on a gross basis as a contract liability separate from the associated costs included within property, plant, and equipment. The contract liability is recognized into service revenues as the underlying performance obligations are satisfied.

Service Revenues

Gas pipeline businesses: Revenues from our regulated interstate natural gas pipeline businesses, which are subject to regulation by certain state and federal authorities, including the FERC, include both firm and interruptible transportation and storage contracts. Firm transportation and storage agreements provide for a fixed reservation charge based on the pipeline or storage capacity reserved, and a commodity charge based on the volume of natural gas delivered/stored, each at rates specified in our FERC tariffs or based on negotiated contractual rates, with contract terms that are generally long-term in nature. Most of our long-term contracts contain an evergreen provision, which allows the contracts to be extended for periods primarily up to one year in length an indefinite number of times following the specified contract term and until terminated generally by either us or the customer. Interruptible transportation and storage agreements provide for a volumetric charge based on actual commodity transportation or storage utilized in the period in which those services are provided, and the contracts are generally limited to one-month periods or less. Our performance obligations related to our interstate natural gas pipeline businesses include the following:

•	Firm transportation or storage under firm transportation and storage contracts—an integrated package of services typically constituting a single performance obligation, which includes standing ready to provide such services and receiving, transporting or storing (as applicable), and redelivering commodities;

•	Interruptible transportation and storage under interruptible transportation and storage contracts—an integrated package of services typically constituting a single performance obligation once scheduled, which includes receiving, transporting or storing (as applicable), and redelivering commodities.

In situations where, in our judgment, we consider the integrated package of services as a single performance obligation, which represents a majority of our interstate natural gas pipeline contracts with customers, we do not consider there to be multiple performance obligations because the nature of the overall promise in the contract is to stand ready (with regard to firm transportation and storage contracts), receive, transport or store, and redeliver natural gas to the customer; therefore, revenue is recognized over time upon satisfaction of our daily stand ready performance obligation.

We recognize revenues for reservation charges over the performance obligation period, which is the contract term, regardless of the volume of natural gas that is transported or stored. Revenues for commodity charges from both firm and interruptible transportation services and storage services are recognized when natural gas is delivered at the agreed upon delivery point or when natural gas is injected or withdrawn from the storage facility because they specifically relate to our efforts to provide these distinct services. Generally, reservation charges and commodity charges in our interstate natural gas pipeline businesses are recognized as revenue in the same period they are invoiced to our customers. As a result of the ratemaking process, certain amounts collected by us may be subject to refund upon the issuance of final orders by the FERC in pending rate proceedings. We use judgment to record estimates of rate refund liabilities considering our and other third-party regulatory proceedings, advice of counsel, and other risks.

Midstream businesses: Revenues from our non-regulated gathering, processing, transportation, and storage midstream businesses include contracts for natural gas gathering, processing, treating, compression, transportation, and other related services with contract terms that are generally long-term in nature and may extend up to the production life of the associated reservoir. Additionally, our midstream businesses generate revenues from fees charged for storing customers’ natural gas and NGLs, generally under prepaid contracted storage capacity contracts. In situations where, in our judgment, we provide an integrated package of services combined into a single performance obligation, which represents a majority of this class of contracts with customers, we do not consider there to be multiple performance obligations because the nature of the overall promise in the contract is to provide

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gathering, processing, transportation, storage, and related services resulting in the delivery, or redelivery in the context of storage services, of pipeline-quality natural gas and NGLs to the customer. As such, revenue is recognized at the daily completion of the integrated package of services as the integrated package represents a single performance obligation. Additionally, certain contracts in our midstream businesses contain fixed or upfront payment terms that result in the deferral of revenues until such services have been performed or such capacity has been made available.

We also earn revenues from offshore crude oil and natural gas gathering and transportation and offshore production handling. These services represent an integrated package of services and are considered a single distinct performance obligation for which we recognize revenues as the services are provided to the customer.

We generally earn a contractually stated fee per unit for the volume of product transported, gathered, processed, or stored. The rate is generally fixed; however, certain contracts contain variable rates that are subject to change based on commodity prices, levels of throughput, or an annual adjustment based on a formulaic cost of service calculation. In addition, we have contracts with contractually stated fees that decline over the contract term, such as declines based on the passage of time periods or achievement of cumulative throughput amounts. For all of our contracts, we allocate the transaction price to each performance obligation based on the judgmentally determined relative standalone selling price. The excess of consideration received over revenue recognized results in the deferral of those amounts until future periods based on a units of production or straight-line methodology as these methods appropriately match the consumption of services provided to the customer. The units of production methodology requires the use of production estimates that are uncertain and the use of judgment when developing estimates of future production volumes, thus impacting the rate of revenue recognition. Production estimates are monitored as circumstances and events warrant. Certain of our gas gathering and processing agreements have minimum volume commitments (MVC). If a customer under such an agreement fails to meet its MVC for a specified period (thus not exercising all the contractual rights to gathering and processing services within the specified period, herein referred to as “breakage”), it is obligated to pay a contractually determined fee based upon the shortfall between the actual gathered or processed volumes and the MVC for the period contained in the contract. When we conclude, based on management’s judgment, it is probable that the customer will not exercise all or a portion of its remaining rights, we recognize revenue associated with such breakage amount in proportion to the pattern of exercised rights within the respective MVC period.

Under keep-whole and percent-of-liquids processing contracts, we receive commodity consideration in the form of NGLs and take title to the NGLs at the tailgate of the plant. We recognize such commodity consideration as service revenue based on the market value of the NGLs retained at the time the processing is provided. The current market value, as opposed to the market value at the contract inception date, is used due to a combination of factors, including the fact that the volume, mix, and market price of NGL consideration to be received is unknown at the time of contract execution and is not specified in our contracts with customers. Additionally, product sales revenue (discussed below) is recognized upon the sale of the NGLs to a third party based on the sales price at the time of sale. As a result, revenue is recognized in the Consolidated Statement of Operations both at the time the processing service is provided in Service revenues – commodity consideration and at the time the NGLs retained as part of the processing service are sold in Product sales. The recognition of revenue related to commodity consideration has the impact of increasing the book value of NGL inventory, resulting in higher cost of goods sold at the time of sale. Given that most inventory is sold in the same period that it is generated, the impact of these transactions is expected to have little impact to operating income.

Product Sales

In the course of providing transportation services to customers of our gas pipeline businesses and gathering and processing services to customers of our midstream businesses, we may receive different quantities of natural gas from customers than the quantities delivered on behalf of those customers. The resulting imbalances are primarily settled through the purchase or sale of natural gas with each customer under terms provided for in our FERC tariffs or gathering and processing agreements, respectively. Revenue is recognized from the sale of natural gas upon settlement of imbalances.

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In certain instances, we purchase NGLs, crude oil, and natural gas from our oil and natural gas producer customers. In addition, we retain NGLs as consideration in certain processing arrangements, as discussed above in the Service Revenues - Midstream businesses section. We recognize revenue from the sale of these commodities when the products have been sold and delivered. Our product sales contracts are primarily short-term contracts based on prevailing market rates at the time of the transaction.

Contract Assets

Our contract assets primarily consist of revenue recognized under contracts containing MVC features whereby management has concluded it is probable there will be a short-fall payment at the end of the current MVC period, which typically follows the calendar year, and that a significant reversal of revenue recognized currently for the future MVC payment will not occur. As a result, our contract assets related to our future MVC payments are generally expected to be collected within the next 12 months and are included within Other current assets and deferred charges in our Consolidated Balance Sheet until such time as the MVC short-fall payments are invoiced to the customer.

Contract Liabilities

Our contract liabilities consist of advance payments primarily from midstream business customers which include construction reimbursements, prepayments, and other billings for which future services are to be provided under the contract. These amounts are deferred until recognized in revenue when the associated performance obligation has been satisfied, which is primarily based on a units of production methodology over the remaining contractual service periods, and are classified as current or noncurrent according to when such amounts are expected to be recognized. Current and noncurrent contract liabilities are included within Accrued liabilities and Regulatory liabilities, deferred income, and other, respectively, in our Consolidated Balance Sheet.

Contracts requiring advance payments and the recognition of contract liabilities are evaluated to determine whether the advance payments provide us with a significant financing benefit. This determination is based on the combined effect of the expected length of time between when we transfer the promised good or service to the customer, when the customer pays for those goods or services, and the prevailing interest rates. We have assessed our contracts for significant financing components and determined, in our judgment, that one group of contracts entered into in contemplation of one another for certain capital reimbursements contains a significant financing component. As a result, we recognize noncash interest expense based on the effective interest method and revenue (noncash) is recognized when the underlying asset is placed into service utilizing a units of production or straight-line methodology over the life of the corresponding customer contract.

Revenue recognition (prior to the adoption of ASC 606)

Revenues

As a result of the ratemaking process, certain revenues collected by us may be subject to refunds upon the issuance of final orders by the FERC in pending rate proceedings. We record estimates of rate refund liabilities considering our and other third-party regulatory proceedings, advice of counsel, and other risks.

Service revenues

Revenues from our interstate natural gas pipeline businesses include services pursuant to long-term firm transportation and storage agreements. These agreements provide for a reservation charge based on the volume of contracted capacity and a commodity charge based on the volume of gas delivered, both at rates specified in our FERC tariffs. We recognize revenues for reservation charges ratably over the contract period regardless of the volume of natural gas that is transported or stored. Revenues for commodity charges, from both firm and interruptible transportation services and storage injection and withdrawal services, are recognized when natural gas is delivered at the agreed upon delivery point or when natural gas is injected or withdrawn from the storage facility.

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Certain revenues from our midstream operations include those derived from natural gas gathering, processing, treating, and compression services and are performed under volumetric-based fee contracts. These revenues are recorded when services have been performed.

Certain of our gas gathering and processing agreements have MVCs. If a customer under such an agreement fails to meet its MVC for a specified period, generally measured on an annual basis, it is obligated to pay a contractually determined fee based upon the shortfall between actual production volumes and the MVC for that period. The revenue associated with MVCs is recognized in the period that the actual shortfall is determined and is no longer subject to future reduction or offset, which is generally at the end of the annual period or fourth quarter.

Crude oil gathering and transportation revenues and offshore production handling fees are recognized when the services have been performed. Certain offshore production handling contracts contain fixed payment terms that result in the deferral of revenues until such services have been performed or such capacity has been made available.

Storage revenues from our midstream operations associated with prepaid contracted storage capacity contracts are recognized on a straight-line basis over the life of the contract as services are provided.

Product sales

In the course of providing transportation services to customers of our interstate natural gas pipeline businesses, we may receive different quantities of gas from shippers than the quantities delivered on behalf of those shippers. The resulting imbalances are primarily settled through the purchase and sale of gas with our customers under terms provided for in our FERC tariffs. Revenue is recognized from the sale of gas upon settlement of the transportation and exchange imbalances.

We market NGLs, crude oil, and natural gas that we purchase from our producer customers as part of the overall service provided to producers. Revenues from marketing activities are recognized when the products have been sold and delivered.

Under our keep-whole and percent-of-liquids processing contracts, we retain the rights to all or a portion of the NGLs extracted from the producers’ natural gas stream and recognize revenues when the extracted NGLs are sold and delivered.

Our former domestic olefins business produced olefins from purchased or produced feedstock and we recognized revenues when the olefins were sold and delivered.

Leases (subsequent to the adoption of ASU 2016-02 effective January 1, 2019)

We recognize a lease liability with an offsetting right-of-use asset in our Consolidated Balance Sheet for operating leases based on the present value of the future lease payments. We have elected to combine lease and nonlease components for all classes of leased assets in our calculation of the lease liability and the offsetting right-of-use asset.

Our lease agreements require both fixed and variable periodic payments, with initial terms typically ranging from one year to 15 years, but a certain land lease has a term of 108 years. Payment provisions in certain of our lease agreements contain escalation factors which may be based on stated rates or a change in a published index at a future time. The amount by which a lease escalates based on the change in a published index, which is not known at lease commencement, is considered a variable payment and is not included in the present value of the future lease payments, which only includes those that are stated or can be calculated based on the lease agreement at lease commencement. In addition to the noncancellable periods, many of our lease agreements provide for one or more extensions of the lease agreement for periods ranging from one year in length to an indefinite number of times following the specified contract term. Other lease agreements provide for extension terms that allow us to utilize the identified leased asset for an indefinite period of time so long as the asset continues to be utilized in our operations. In consideration of these renewal features, we assess the term of the lease agreements, which includes using judgment in the determination of which

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renewal periods and termination provisions, when at our sole election, will be reasonably certain of being exercised. Periods after the initial term or extension terms that allow for either party to the lease to cancel the lease are not considered in the assessment of the lease term. Additionally, we have elected to exclude leases with an original term of one year or less, including renewal periods, from the calculation of the lease liability and the offsetting right-of-use asset.

We use judgment in determining the discount rate upon which the present value of the future lease payments is determined. This rate is based on a collateralized interest rate corresponding to the term of the lease agreement using company, industry, and market information available.

When permitted under our lease agreements, we may sublease certain unused office space for fixed periods that could extend up to the length of the original lease agreement.

Interest capitalized

We capitalize interest during construction on major projects with construction periods of at least 3 months and a total project cost in excess of $1 million. Interest is capitalized on borrowed funds and, where regulation by the FERC exists, on internally generated funds (equity AFUDC). The latter is included in Other income (expense) – net below Operating income (loss) in the Consolidated Statement of Operations. The rates used by regulated companies are calculated in accordance with FERC rules. Rates used by nonregulated companies are based on our average interest rate on debt.

Employee stock-based awards

We recognize compensation expense on employee stock-based awards on a straight-line basis; forfeitures are recognized when they occur. (See Note 17 – Equity-Based Compensation.)

Pension and other postretirement benefits

The funded status of each of the pension and other postretirement benefit plans is recognized separately in the Consolidated Balance Sheet as either an asset or liability. The funded status is the difference between the fair value of plan assets and the plan’s benefit obligation. The plans’ benefit obligations and net periodic benefit costs (credits) are actuarially determined and impacted by various assumptions and estimates. (See Note 10 – Employee Benefit Plans.)

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

The expected long-term rates of return on plan assets are determined by combining a review of the historical returns within the portfolio, the investment strategy included in the plans’ investment policy statement, and capital market projections for the asset classes in which the portfolio is invested, as well as the weighting of each asset class.

Unrecognized actuarial gains and losses and unrecognized prior service costs and credits are deferred and recorded in AOCI or, for Transco and Northwest Pipeline, as a regulatory asset or liability, until amortized as a component of net periodic benefit cost (credit). Unrecognized actuarial gains and losses in excess of 10 percent of the greater of the benefit obligation or the market-related value of plan assets are amortized over the participants’ average remaining future years of service, which is approximately 13 years for our pension plans and approximately 7 years for our other postretirement benefit plan.

The expected return on plan assets component of net periodic benefit cost (credit) is calculated using the market-related value of plan assets. For our pension plans, the market-related value of plan assets is equal to the fair value of plan assets adjusted to reflect the amortization of gains or losses associated with the difference between the expected and actual return on plan assets over a 5-year period. Additionally, the market-related value of assets may be no more than 110 percent or less than 90 percent of the fair value of plan assets at the beginning of the year. The market-related

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value of plan assets for our other postretirement benefit plan is equal to the unadjusted fair value of plan assets at the beginning of the year.

Income taxes

We include the operations of our domestic corporate subsidiaries and income from our subsidiary partnerships in our consolidated federal income tax return and also file tax returns in various foreign and state jurisdictions as required. Deferred income taxes are computed using the liability method and are provided on all temporary differences between the financial basis and the tax basis of our assets and liabilities. Our judgment and income tax assumptions are used to determine the levels, if any, of valuation allowances associated with deferred tax assets.

Earnings (loss) per common share

Basic earnings (loss) per common share in the Consolidated Statement of Operations is based on the sum of the weighted-average number of common shares outstanding and vested restricted stock units. Diluted earnings (loss) per common share in the Consolidated Statement of Operations includes any dilutive effect of stock options, nonvested restricted stock units, and convertible debt, unless otherwise noted. Diluted earnings (loss) per common share are calculated using the treasury-stock method.

Accounting standards issued and adopted

In February 2016, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) 2016-02 “Leases (Topic 842)” (ASU 2016-02). ASU 2016-02 establishes a comprehensive new lease accounting model. ASU 2016-02 modifies the definition of a lease, requires a dual approach to lease classification similar to prior lease accounting, and causes lessees to recognize operating leases on the balance sheet as a lease liability measured as the present value of the future lease payments with a corresponding right-of-use asset, with an exception for leases with a term of one year or less. Additional disclosures are required regarding the amount, timing, and uncertainty of cash flows arising from leases. In January 2018, the FASB issued ASU 2018-01 “Leases (Topic 842): Land Easement Practical Expedient for Transition to Topic 842” (ASU 2018-01). Per ASU 2018-01, land easements and rights-of-way are required to be assessed under ASU 2016-02 to determine whether the arrangements are or contain a lease. ASU 2018-01 permits an entity to elect a transition practical expedient to not apply ASU 2016-02 to land easements that exist or expired before the effective date of ASU 2016-02 and that were not previously assessed under the previous lease guidance in ASC Topic 840 “Leases.”

In July 2018, the FASB issued ASU 2018-11 “Leases (Topic 842): Targeted Improvements” (ASU 2018-11). Prior to ASU 2018-11, a modified retrospective transition was required for financing or operating leases existing at or entered into after the beginning of the earliest comparative period presented in the financial statements. ASU 2018-11 allows entities an additional transition method to the existing requirements whereby an entity could adopt the provisions of ASU 2016-02 by recognizing a cumulative-effect adjustment to the opening balance of retained earnings in the period of adoption without adjustment to the financial statements for periods prior to adoption. ASU 2018-11 also allows a practical expedient that permits lessors to not separate nonlease components from the associated lease component if certain conditions are present. ASU 2016-02 is effective for interim and annual periods beginning after December 15, 2018. We prospectively adopted ASU 2016-02 effective January 1, 2019, and did not adjust prior periods as permitted by ASU 2018-11 (see Note 11 – Leases).

We completed our review of contracts to identify leases based on the modified definition of a lease and implemented changes to our internal controls to support management in the accounting for and disclosure of leasing activities upon adoption of ASU 2016-02. We implemented a financial lease accounting system to assist management in the accounting for leases upon adoption. The most significant changes to our financial statements as a result of adopting ASU 2016-02 relate to the recognition of a $225 million lease liability and offsetting right-of-use asset in our Consolidated Balance Sheet for operating leases. We also evaluated ASU 2016-02’s available practical expedients on adoption and have generally elected to adopt the practical expedients, which includes the practical expedient to not separate lease and nonlease components by both lessees and lessors by class of underlying assets and the land easements practical expedient.

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Accounting standards issued but not yet adopted

In June 2016, the FASB issued ASU 2016-13 “Financial Instruments - Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments” (ASU 2016-13). ASU 2016-13 changes the impairment model for most financial assets and certain other instruments. For trade and other receivables, held-to-maturity debt securities, loans, and other instruments, entities will be required to use a new forward-looking “expected loss” model that generally will result in the earlier recognition of allowances for losses. The guidance also requires increased disclosures. ASU 2016-13 is effective for us for interim and annual periods beginning after December 15, 2019. We are adopting ASU 2016-13 effective January 1, 2020. We anticipate that ASU 2016-13 will primarily apply to our trade receivables. While we do not expect a significant financial impact, we have analyzed our historical credit loss experience, and considered current conditions and reasonable forecasts, in developing our expected credit loss rate, and continue to develop and implement processes, procedures, and internal controls in order to make the necessary credit loss assessments and required disclosures upon adoption.

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Note 2 – Revenue Recognition

Revenue by Category

The following table presents our revenue disaggregated by major service line:

	Transco				Northwest Pipeline				Atlantic- Gulf Midstream				Northeast Midstream				West Midstream				Other				Eliminations				Total
	(Millions)
2019
Revenues from contracts with customers:
Service revenues:
Non-regulated gathering, processing, transportation, and storage:
Monetary consideration	$	—			$	—			$	479			$	1,171			$	1,309			$	—			$	(75	)		$	2,884
Commodity consideration	—				—				41				12				150				—				—				203
Regulated interstate natural gas transportation and storage	2,336				450				—				—				—				—				(6		)		2,780
Other	11				—				26				147				42				—				(16		)		210
Total service revenues	2,347				450				546				1,330				1,501				—				(97		)		6,077
Product Sales:
NGL and natural gas	106				—				185				150				1,795				—				(173		)		2,063
Total revenues from contracts with customers	2,453				450				731				1,480				3,296				—				(270		)		8,140
Other revenues (1)	1				—				8				20				14				30				(12		)		61
Total revenues	$	2,454			$	450			$	739			$	1,500			$	3,310			$	30			$	(282	)		$	8,201
2018
Revenues from contracts with customers:
Service revenues:
Non-regulated gathering, processing, transportation, and storage:
Monetary consideration	$	—			$	—			$	541			$	861			$	1,590			$	2			$	(73	)		$	2,921
Commodity consideration	—				—				59				20				321				—				—				400
Regulated interstate natural gas transportation and storage	1,921				443				—				—				—				—				(2		)		2,362
Other	2				—				17				94				46				—				(15		)		144
Total service revenues	1,923				443				617				975				1,957				2				(90		)		5,827
Product Sales:
NGL and natural gas	127				—				307				287				2,421				—				(382		)		2,760
Other	—				—				—				—				21				—				(4		)		17
Total product sales	127				—				307				287				2,442				—				(386		)		2,777
Total revenues from contracts with customers	2,050				443				924				1,262				4,399				2				(476		)		8,604
Other revenues (1)	11				—				18				21				12				32				(12		)		82
Total revenues	$	2,061			$	443			$	942			$	1,283			$	4,411			$	34			$	(488	)		$	8,686

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(1)

Revenues not within the scope of ASC 606, “Revenue from Contracts with Customers,” consist of leasing revenues associated with our headquarters building and management fees that we receive for certain services we provide to operated equity-method investments, which are reported in Service revenues in our Consolidated Statement of Operations, and amounts associated with our derivative contracts, which are reported in Product sales in our Consolidated Statement of Operations.

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Contract Assets

The following table presents a reconciliation of our contract assets:

	Year Ended December 31,
	2019				2018
	(Millions)
Balance at beginning of period	$	4			$	4
Revenue recognized in excess of amounts invoiced	62				66
Minimum volume commitments invoiced	(58		)		(66		)
Balance at end of period	$	8			$	4

Contract Liabilities

The following table presents a reconciliation of our contract liabilities:

	Year Ended December 31,
	2019				2018
	(Millions)
Balance at beginning of period	$	1,397			$	1,596
Payments received and deferred	157				314
Significant financing component	13				16
Deconsolidation of Jackalope interest (Note 6)	—				(52		)
Deconsolidation of certain Permian assets (Note 6)	—				(26		)
Recognized in revenue	(352		)		(451		)
Balance at end of period	$	1,215			$	1,397

Remaining Performance Obligations

Remaining performance obligations primarily include reservation charges on contracted capacity for our gas pipeline firm transportation contracts with customers, storage capacity contracts, long-term contracts containing minimum volume commitments associated with our midstream businesses, and fixed payments associated with offshore production handling. For our interstate natural gas pipeline businesses, remaining performance obligations reflect the rates for such services in our current FERC tariffs for the life of the related contracts; however, these rates may change based on future tariffs approved by the FERC and the amount and timing of these changes are not currently known.

Our remaining performance obligations exclude variable consideration, including contracts with variable consideration for which we have elected the practical expedient for consideration recognized in revenue as billed. Certain of our contracts contain evergreen and other renewal provisions for periods beyond the initial term of the contract. The remaining performance obligation amounts as of December 31, 2019, do not consider potential future performance obligations for which the renewal has not been exercised and excludes contracts with customers for which the underlying facilities have not received FERC authorization to be placed into service. Consideration received prior to December 31, 2019, that will be recognized in future periods is also excluded from our remaining performance obligations and is instead reflected in contract liabilities.

The following table presents the amount of the contract liabilities balance expected to be recognized as revenue when performance obligations are satisfied and the transaction price allocated to the remaining performance obligations under certain contracts as of December 31, 2019.

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	Contract Liabilities				Remaining Performance Obligations
	(Millions)
2020	$	160			$	3,418
2021	121				3,241
2022	113				3,117
2023	101				2,524
2024	91				2,339
Thereafter	629				18,815
Total	$	1,215			$	33,454

Note 3 – Acquisitions and Divestitures

UEOM

As of December 31, 2018, we owned a 62 percent interest in UEOM which we accounted for as an equity-method investment. On March 18, 2019, we signed and closed the acquisition of the remaining 38 percent interest in UEOM. Total consideration paid, including post-closing adjustments, was $741 million in cash funded through credit facility borrowings and cash on hand. As a result of acquiring this additional interest, we obtained control of and now consolidate UEOM.

UEOM is involved primarily in the processing and fractionation of natural gas and natural gas liquids in the Utica Shale play in eastern Ohio. The purpose of the acquisition was to enhance our position in the region. We expect synergies through common ownership of UEOM and our Ohio Valley midstream systems to create a more efficient platform for capital spending in the region, resulting in reduced operating and maintenance expenses and creating enhanced capabilities and benefits for producers in the area.

The acquisition of UEOM was accounted for as a business combination, which requires, among other things, that identifiable assets acquired and liabilities assumed be recognized at their acquisition date fair values. In March 2019, based on the transaction price for our purchase of the remaining interest in UEOM as finalized just prior to the acquisition, we recognized a $74 million noncash impairment loss related to our existing 62 percent interest (see Note 18 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk). Thus, there was no gain or loss on remeasuring our existing equity-method investment to fair value due to the impairment recognized just prior to closing the acquisition of the additional interest.

The valuation techniques used to measure the acquisition date fair value of the UEOM acquisition consisted of the market approach for our previous equity-method investment in UEOM and the income approach (excess earnings method) for valuation of intangible assets and depreciated replacement costs for property, plant, and equipment.

The following table presents the allocation of the acquisition date fair value of the major classes of the assets acquired, which are presented in the Northeast G&P segment, and liabilities assumed at March 18, 2019. The net assets acquired reflect the sum of the consideration transferred and the noncash elimination of the fair value of our existing equity-method investment upon our acquisition of the additional interest. The fair value of accounts receivable acquired, presented in current assets in the table, equals contractual amounts receivable. After the March 31, 2019 financial statements were issued, we received an updated valuation report from a third-party valuation firm. Significant changes from the preliminary allocation disclosed in the first quarter to the final allocation, which were recorded in the second quarter of 2019, reflect an increase of $169 million in goodwill, and decreases of $106 million in property, plant, and equipment and $61 million in other intangible assets.

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	(Millions)
Current assets, including $13 million cash acquired	$	55
Property, plant, and equipment	1,387
Other intangible assets	328
Total identifiable assets acquired	1,770
Current liabilities	7
Total liabilities assumed	7
Net identifiable assets acquired	1,763
Goodwill	188
Net assets acquired	$	1,951

The goodwill recognized in the acquisition relates primarily to enhancing and diversifying our basin positions and is reported within the Northeast G&P segment. Substantially all of the goodwill is expected to be deductible for tax purposes. Goodwill is included within Intangible assets – net of accumulated amortization in the Consolidated Balance Sheet and represents the excess of the consideration, plus the fair value of any previously held equity interest, over the fair value of the net assets acquired.

Other intangible assets recognized in the acquisition are related to contractual customer relationships from gas gathering, processing, and fractionation agreements with our customers. The basis for determining the value of these intangible assets is estimated future net cash flows to be derived from acquired contractual customer relationships discounted using a risk-adjusted discount rate. These intangible assets are being amortized on a straight-line basis over a period of 20 years which represents the term over which the contractual customer relationships are expected to contribute to our cash flows. Approximately 49 percent of the expected future revenues from these contractual customer relationships are impacted by our ability and intent to renew or renegotiate existing customer contracts. We expense costs incurred to renew or extend the terms of our gas gathering, processing, and fractionation contracts with customers. Based on the estimated future revenues during the current contract periods (as estimated at the time of the acquisition), the weighted-average period prior to the next renewal or extension of the existing contractual customer relationships was approximately 10 years.

The following unaudited pro forma Revenues and Net income (loss) attributable to The Williams Companies, Inc. for the years ended December 31, 2019 and 2018, respectively, are presented as if the UEOM acquisition had been completed on January 1, 2018. These pro forma amounts are not necessarily indicative of what the actual results would have been if the acquisition had in fact occurred on the date or for the periods indicated, nor do they purport to project Revenues or Net income (loss) attributable to The Williams Companies, Inc. for any future periods or as of any date. These amounts do not give effect to any potential cost savings, operating synergies, or revenue enhancements to result from the transaction or the potential costs to achieve these cost savings, operating synergies, and revenue enhancements.

	Year Ended December 31,
	2019				2018
	(Millions)
Revenues	$	8,233			$	8,836
Net income (loss) attributable to The Williams Companies, Inc.	928				(128		)

Adjustments to pro forma Net income (loss) attributable to The Williams Companies, Inc. include the removal of the previously described $74 million impairment loss recognized in March 2019 just prior to the acquisition.

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During the period from the acquisition date of March 18, 2019 to December 31, 2019, UEOM contributed Revenues of $179 million and Net income (loss) attributable to The Williams Companies, Inc. of $53 million.

Costs related to this acquisition are $4 million and are reported within our Northeast G&P segment and included in Selling, general, and administrative expenses in our Consolidated Statement of Operations.

Northeast JV

Concurrent with the UEOM acquisition, we executed an agreement whereby we contributed our consolidated interests in UEOM and our Ohio Valley midstream business to a newly formed partnership. In June 2019, our partner invested approximately $1.33 billion for a 35 percent ownership interest, and we retained 65 percent ownership of, as well as operate and consolidate, the Northeast JV business. The change in ownership due to this transaction increased Noncontrolling interests in consolidated subsidiaries by $567 million, and decreased Capital in excess of par value by $426 million and Deferred income tax liabilities by $141 million in the Consolidated Balance Sheet. Costs related to this transaction are $6 million and are reported within our Northeast G&P segment and included in Selling, general, and administrative expenses in our Consolidated Statement of Operations.

Sale of Gulf Coast Pipeline Systems

In November 2018, we completed the sale of certain assets and operations located in the Gulf Coast area for $177 million in cash. As a result of this sale, we recorded a gain of approximately $101 million in the fourth quarter of 2018, consisting of $81 million in our Atlantic-Gulf segment and $20 million in Other.

Previous impairments made to a portion of these assets and operations include $66 million related to certain idle pipelines in the second quarter of 2018, as well as $68 million and $23 million related to an NGL pipeline near the Houston Ship Channel region and project development costs associated with an olefins pipeline project, respectively, in 2017. These impairments are reflected in Impairment of certain assets in the Consolidated Statement of Operations. (See Note 18 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk.) The results of operations for this disposal group, excluding the impairments and gains noted, were not significant for the reporting periods.

Sale of Four Corners Assets

In October 2018, we completed the sale of our natural gas gathering and processing assets in the Four Corners area of New Mexico and Colorado for total consideration of $1.125 billion. As a result of this sale, we recorded a gain of approximately $591 million within the West segment in the fourth quarter of 2018.

The following table presents the results of operations for the Four Corners area, excluding the gain noted above:

	Year Ended December 31,
	2018				2017
	(Millions)
Income (loss) before income taxes of Four Corners area	$	52			$	47
Income (loss) before income taxes of Four Corners area attributable to The Williams Companies, Inc.	43				35

Sale of Geismar Interest

In July 2017, we completed the sale of Williams Olefins, L.L.C., a wholly owned subsidiary which owned our Geismar Interest, for total consideration of $2.084 billion in cash. We received a final working capital adjustment of $12 million in October 2017. Upon closing of the sale, we entered into a long-term supply and transportation agreement with the purchaser to provide feedstock to the plant via its Bayou Ethane pipeline system. As a result of this sale, we recorded a gain of $1.095 billion in the third quarter of 2017 in our Other segment.

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The following table presents the results of operations for the Geismar Interest, excluding the gain noted above:

	Year Ended December 31,
	2017
	(Millions)
Income (loss) before income taxes of the Geismar Interest	$	26
Income (loss) before income taxes of the Geismar Interest attributable to The Williams Companies, Inc.	19

Note 4 – Variable Interest Entities

Consolidated VIEs

As of December 31, 2019, we consolidate the following VIEs:

Gulfstar One

We own a 51 percent interest in Gulfstar One, a subsidiary that, due to certain risk-sharing provisions in its customer contracts, is a VIE. Gulfstar One includes a proprietary floating-production system, Gulfstar FPS, and associated pipelines which provide production handling and gathering services in the eastern deepwater Gulf of Mexico. We are the primary beneficiary because we have the power to direct the activities that most significantly impact Gulfstar One’s economic performance.

Cardinal

We own a 66 percent interest in Cardinal, a subsidiary that provides gathering services for the Utica Shale region and is a VIE due to certain risks shared with customers. We are the primary beneficiary because we have the power to direct the activities that most significantly impact Cardinal’s economic performance. Future expansion activity is expected to be funded with capital contributions from us and the other equity partner on a proportional basis.

Northeast JV

As a result of the June 2019 sale of a 35 percent interest in the Northeast JV (Note 3 – Acquisitions and Divestitures), we now own a 65 percent interest in the Northeast JV, a subsidiary that is a VIE due to certain of our voting rights being disproportionate to our obligation to absorb losses and substantially all of the Northeast JV’s activities being performed on our behalf. We are the primary beneficiary because we have the power to direct the activities that most significantly impact the Northeast JV’s economic performance. The Northeast JV provides midstream services for producers in the Marcellus Shale and Utica Shale regions. Future expansion activity is expected to be funded with capital contributions from us and the other equity partner on a proportional basis.

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The following table presents amounts included in our Consolidated Balance Sheet that are only for the use or obligation of our consolidated VIEs:

	December 31,
	2019				2018
	(Millions)
Assets (liabilities):
Cash and cash equivalents	$	102			$	33
Trade accounts and other receivables – net	167				62
Other current assets and deferred charges	5				2
Property, plant, and equipment – net	5,745				2,363
Intangible assets – net of accumulated amortization	2,669				1,177
Regulatory assets, deferred charges, and other	13				—
Accounts payable	(58		)		(15		)
Accrued liabilities	(66		)		(115		)
Regulatory liabilities, deferred income, and other	(283		)		(264		)

Nonconsolidated VIEs

Jackalope

At December 31, 2018, we owned a 50 percent interest in Jackalope, which provides gathering and processing services for the Powder River basin and was a VIE due to certain risks shared with customers. In April 2019, we sold our interest in Jackalope for $485 million in cash (see Note 6 – Investing Activities).

Brazos Permian II

We own a 15 percent interest in Brazos Permian II (see Note 6 – Investing Activities), which provides gathering and processing services in the Delaware basin and is a VIE due primarily to our limited participating rights as the minority equity holder.  At December 31, 2019, the carrying value of our investment in Brazos Permian II was $194 million. Our maximum exposure to loss is limited to the carrying value of our investment.

Constitution

As of December 31, 2019, we own a 41 percent interest in Constitution, a subsidiary which proposed a pipeline project extending from Susquehanna County, Pennsylvania, to the Iroquois Gas Transmission and the Tennessee Gas Pipeline systems in New York. Constitution was considered a VIE due to shipper fixed-payment commitments under its long-term firm transportation contracts, and we were the primary beneficiary because we had the power to direct the activities that most significantly impacted Constitution’s economic performance during its construction phase. Thus, prior to December 31, 2019, we consolidated Constitution.

Although Constitution received a certificate of public convenience and necessity from the FERC to construct and operate the proposed pipeline and obtained, among other approvals, a waiver of the water quality certification under Section 401 of the Clean Water Act for the New York portion of the project, the members of Constitution, following extensive evaluation and discussion, recently determined that the underlying risk-adjusted return for this greenfield pipeline project has diminished in such a way that further development is no longer supported. Accordingly, we recognized a $354 million impairment of the consolidated capitalized project costs in the fourth quarter of 2019, which considered our estimate of the fair value of the disposal group under various probability-weighted disposal alternatives. (See Note 18 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk.) Our partners’ $209 million share of this impairment is reflected within Net income (loss) attributable to noncontrolling interests in the Consolidated Statement of Operations.

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Constitution is still considered a VIE due to insufficient equity at risk, but we are no longer the primary beneficiary. As a result, we deconsolidated Constitution as of December 31, 2019, recognizing a loss on deconsolidation of $27 million in the fourth quarter of 2019, which is included in Other investing income (loss) - net in the Consolidated Statement of Operations.

Note 5 – Related Party Transactions

Transactions with Equity-Method Investees

We have purchases from our equity-method investees included in Product costs in the Consolidated Statement of Operations of $304 million, $236 million, and $226 million for the years ended 2019, 2018, and 2017, respectively. We have $36 million and $18 million included in Accounts payable in the Consolidated Balance Sheet with our equity-method investees at December 31, 2019 and 2018, respectively.

We have operating agreements with certain equity-method investees. These operating agreements typically provide for reimbursement or payment to us for certain direct operational payroll and employee benefit costs, materials, supplies, and other charges and also for management services. The total charges to equity-method investees for these fees are $103 million, $75 million, and $67 million for the years ended 2019, 2018, and 2017, respectively.

Note 6 – Investing Activities

Other investing income (loss) – net

The following table presents certain items reflected in Other investing income (loss) – net in the Consolidated Statement of Operations:

	Year Ended December 31,
	2019				2018				2017
	(Millions)
Impairment of equity-method investments (Note 18)	$	(186	)		$	(32	)		$	—
Gain (loss) on deconsolidation of businesses	(29		)		203				—
Gain on disposition of equity-method investments	122				—				269
Other	14				16				13
Other investing income (loss) – net	$	(79	)		$	187			$	282

Brazos Permian II Equity-Method Investment

During the fourth quarter of 2018, we contributed the majority of our existing Delaware basin assets and $27 million in cash in exchange for a 15 percent interest in the Brazos Permian II, which consists of gas and crude oil gathering pipelines, natural gas processing, and oil storage facilities. We recorded a deconsolidation gain of $141 million reflected in Other investing income (loss) – net in the Consolidated Statement of Operations reflecting the excess of the fair value of our acquired interest over the carrying value of the assets contributed. We estimated the fair value of our interest to be $192 million primarily using a market approach (a Level 3 measurement within the fair value hierarchy). This approach involved the observation of recent transaction multiples in the Permian basin, including recent acquisitions consummated during 2018. Our interest in Brazos Permian II is considered an equity-method investment due to the fact that we are able to exert significant influence over its operating and financial policies.

RMM Equity-Method Investment

During the third quarter of 2018, our joint venture, RMM, purchased a natural gas and oil gathering and natural gas processing business in Colorado’s Denver-Julesburg basin. Our initial economic ownership was 40 percent, but increased to 50 percent at December 31, 2018, based on additional capital contributions made after the initial purchase.

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Jackalope Deconsolidation

During the second quarter of 2018, we deconsolidated our 50 percent interest in Jackalope (see Note 4 – Variable Interest Entities). We recorded our interest in Jackalope as an equity-method investment at its estimated fair value, resulting in a deconsolidation gain of $62 million reflected in Other investing income (loss) – net in the Consolidated Statement of Operations. We estimated the fair value of our interest to be $310 million using an income approach based on expected future cash flows and an appropriate discount rate (a Level 3 measurement within the fair value hierarchy). The determination of expected future cash flows involved significant assumptions regarding gathering and processing volumes and related capital spending. A 10.9 percent discount rate was utilized and reflected our estimate of the cost of capital as impacted by market conditions and risks associated with the underlying business. The deconsolidated carrying value of the net assets of Jackalope included $47 million of goodwill.

Sale of Jackalope

In April 2019, we sold our 50 percent equity-method interest in Jackalope for $485 million in cash, resulting in a gain on the disposition of $122 million, reflected in Other investing income (loss) – net in the Consolidated Statement of Operations.

Constitution Deconsolidation

We deconsolidated our interest in Constitution as of December 31, 2019, recognizing a loss on deconsolidation of $27 million. See Note 4 – Variable Interest Entities for further discussion.

Acquisition of Additional Interests in Appalachia Midstream Investments

During the first quarter of 2017, we exchanged all of our 50 percent interest in DBJV for an increased interest in two natural gas gathering systems that are part of the Appalachia Midstream Investments and $155 million in cash. This transaction was recorded based on our estimate of the fair value of the interests received as we have more insight to this value as we operate the underlying assets. Following this exchange, we have an approximate average 66 percent interest in the Appalachia Midstream Investments. We continue to account for this investment under the equity method of accounting due to the significant participatory rights of our partners such that we do not exercise control. We also sold all of our interest in Ranch Westex JV LLC (Ranch Westex) for $45 million. These transactions resulted in a total gain of $269 million reflected in Other investing income (loss) – net in the Consolidated Statement of Operations.

The fair value of the increased interests in the Appalachia Midstream Investments received as consideration was estimated to be $1.1 billion using an income approach based on expected cash flows and an appropriate discount rate (a Level 3 measurement within the fair value hierarchy). The determination of estimated future cash flows involved significant assumptions regarding gathering volumes, rates, and related capital spending. A 9.5 percent discount rate was utilized and reflected our estimate of the cost of capital as impacted by market conditions and risks associated with the underlying business.

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Equity-Method Investments

	Ownership Interest at December 31, 2019		December 31,
			2019				2018
			(Millions)
Appalachia Midstream Investments	(1)		$	3,236			$	3,218
RMM	50%		881				776
Discovery	60%		472				507
Caiman II	58%		428				412
OPPL	50%		403				415
Laurel Mountain	69%		249				314
Gulfstream	50%		217				225
Brazos Permian II	15%		194				191
UEOM	(2)		—				1,293
Jackalope	(3)		—				343
Other	Various		155				127
			$	6,235			$	7,821

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(1)	Includes equity-method investments in multiple gathering systems in the Marcellus Shale with an approximate average 66 percent interest.

(2)	At December 31, 2018, we owned a 62 percent interest in UEOM. On March 18, 2019, we acquired the remaining 38 percent interest. As a result of acquiring this additional interest, we obtained control of and now consolidate UEOM.

(3)	At December 31, 2018, we owned a 50 percent interest in Jackalope. In April 2019, we sold our interest in Jackalope.

We have differences between the carrying value of our equity-method investments and the underlying equity in the net assets of the investees of $1 billion at December 31, 2019 and $1.8 billion at December 31, 2018. These differences primarily relate to our investments in Appalachia Midstream Investments (and UEOM at December 31, 2018), resulting from property, plant, and equipment, as well as customer-based intangible assets and goodwill.

Purchases of and contributions to equity-method investments

We generally fund our portion of significant expansion or development projects of these investees through additional capital contributions. These transactions increased the carrying value of our investments and included:

	Year Ended December 31,
	2019				2018				2017
	(Millions)
RMM	$	145			$	795			$	—
Appalachia Midstream Investments	140				246				70
Laurel Mountain	36				16				—
Caiman II	28				—				24
Jackalope	24				42				—
Brazos Permian II	18				27				—
Discovery	—				5				1
DBJV	—				—				32
Other	62				1				5
	$	453			$	1,132			$	132

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Dividends and distributions

The organizational documents of entities in which we have an equity-method investment generally require distribution of available cash to members on at least a quarterly basis. These transactions reduced the carrying value of our investments and included:

	Year Ended December 31,
	2019				2018				2017
	(Millions)
Appalachia Midstream Investments	$	293			$	297			$	270
Gulfstream	86				93				92
OPPL	77				73				68
Caiman II	42				46				49
Discovery	41				45				127
RMM	38				—				—
Laurel Mountain	30				23				32
UEOM	13				70				80
DBJV	—				—				39
Other	37				46				27
	$	657			$	693			$	784

Summarized Financial Position and Results of Operations of All Equity-Method Investments

	December 31,
	2019				2018
	(Millions)
Assets (liabilities):
Current assets	$	581			$	834
Noncurrent assets	11,966				13,199
Current liabilities	(341		)		(605		)
Noncurrent liabilities	(2,532		)		(2,491		)

	Year Ended December 31,
	2019				2018				2017
	(Millions)
Gross revenue	$	2,490			$	2,411			$	1,961
Operating income	685				804				871
Net income	598				795				806

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Note 7 – Other Income and Expenses

The following tables present by segment, certain other items included in our Consolidated Statement of Operations:

	Year Ended December 31,
	2019				2018				2017
	(Millions)
Other (income) expense – net within Costs and expenses
Atlantic-Gulf
Amortization of regulatory assets associated with asset retirement obligations	$	21			$	33			$	33
Net accrual (amortization) of regulatory liability related to overcollection of certain employee expenses	(17		)		22				22
Project development costs related to Constitution (see Note 4)	3				4				16
Amortization of regulatory liability associated with Tax Reform	(26		)		—				—
Gains on asset retirements	—				(12		)		—
West
Regulatory charge per approved rates related to Tax Reform	24				24				—
Charge for regulatory liability associated with the decrease in Northwest Pipeline’s estimated deferred state income tax rates following WPZ Merger	—				12				—
Gains on contract settlements and terminations	—				—				(15		)
Other
Change to (benefit of) regulatory asset associated with Transco’s estimated deferred state income tax rate following WPZ Merger	12				(37		)		—
Gain on sale of refinery grade propylene splitter	—				—				(12		)

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	Year Ended December 31,
	2019				2018				2017
	(Millions)
Other income (expense) – net below Operating income (loss)
Atlantic-Gulf
Allowance for equity funds used during construction	$	29			$	87			$	70
Settlement charge from pension early payout program	—				(7		)		(15		)
Regulatory adjustments resulting from Tax Reform	—				—				(33		)
Northeast G&P
Settlement charge from pension early payout program	—				(4		)		(7		)
West
Settlement charge from pension early payout program	—				(6		)		(13		)
Regulatory adjustments resulting from Tax Reform	—				—				(6		)
Other
Income associated with a regulatory asset related to deferred taxes on equity funds used during construction	9				35				52
Net gain (loss) associated with early retirement of debt	—				(7		)		27
Settlement charge from pension early payout program	—				(5		)		(35		)
Regulatory adjustments resulting from Tax Reform	—				(1		)		(63		)

Severance and other related costs included within Operating and maintenance expenses and Selling, general, and administrative expenses are as follows:

	Year Ended December 31,
	2019				2018				2017
	(Millions)
Atlantic-Gulf	$	32			$	—			$	—
Northeast G&P	7				—				—
West	17				—				—
Other	1				—				22

Selling, general, and administrative expenses for the year ended December 31, 2018, includes a $35 million charge associated with a charitable contribution of preferred stock to The Williams Companies Foundation, Inc. (a not-for-profit corporation) within the Other segment (see Note 16 – Stockholders' Equity) and $20 million for WPZ Merger related costs within the Other segment.

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Note 8 – Provision (Benefit) for Income Taxes

The Provision (benefit) for income taxes includes:

	Year Ended December 31,
	2019				2018				2017
	(Millions)
Current:
Federal	$	(41	)		$	(83	)		$	15
State	(5		)		1				23
Foreign	2				—				—
	(44		)		(82		)		38
Deferred:
Federal	280				183				(2,004		)
State	99				37				(8		)
	379				220				(2,012		)
Provision (benefit) for income taxes	$	335			$	138			$	(1,974	)

Reconciliations from the Provision (benefit) at statutory rate to recorded Provision (benefit) for income taxes are as follows:

	Year Ended December 31,
	2019				2018				2017
	(Millions)
Provision (benefit) at statutory rate	$	224			$	69			$	187
Increases (decreases) in taxes resulting from:
Impact of nontaxable noncontrolling interests	29				(73		)		(117		)
Federal Tax Reform rate change	—				—				(1,932		)
State income taxes (net of federal benefit)	74				(10		)		(17		)
State deferred income tax rate change	—				38				26
Foreign operations – net (including tax effect of Canadian Sale)	2				—				(127		)
Federal valuation allowance	3				105				—
Other – net	3				9				6
Provision (benefit) for income taxes	$	335			$	138			$	(1,974	)

Income (loss) from continuing operations before income taxes includes $6 million, $3 million, and $7 million of foreign loss in 2019, 2018, and 2017, respectively.

Foreign operations – net (including tax effect of Canadian Sale) in 2017 reflects the release of a valuation allowance associated with impairments and losses on the sale of our Canadian operations.

On December 22, 2017, Tax Reform was enacted. Most of the provisions of Tax Reform were effective after January 1, 2018. However, the deferred tax impact of reducing the U.S. corporate tax rate from 35 percent to 21 percent was recognized in the period of enactment. This remeasurement resulted in a reduction of our deferred tax liabilities of approximately $1.9 billion, with a corresponding net adjustment to Provision (benefit) for income taxes in 2017.

During the course of audits of our business by domestic and foreign tax authorities, we frequently face challenges regarding the amount of taxes due. These challenges include questions regarding the timing and amount of deductions and the allocation of income among various tax jurisdictions. In evaluating the liability associated with our various filing positions, we apply the two-step process of recognition and measurement. In association with this liability, we record an estimate of related interest and tax exposure as a component of our tax provision. The impact of this accrual is included within Other – net in our reconciliation of the Provision (benefit) at statutory rate to recorded Provision (benefit) for income taxes.

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Significant components of Deferred income tax liabilities and Deferred income tax assets are as follows:

	December 31,
	2019				2018
	(Millions)
Deferred income tax liabilities:
Property, plant and equipment	$	1,921			$	2,317
Investments	1,411				295
Other	82				30
Total deferred income tax liabilities	3,414				2,642
Deferred income tax assets:
Accrued liabilities	729				667
Minimum tax credit	29				71
Foreign tax credit	140				140
Federal loss carryovers	544				147
State losses and credits	362				319
Other	147				94
Total deferred income tax assets	1,951				1,438
Less valuation allowance	319				320
Net deferred income tax assets	1,632				1,118
Overall net deferred income tax liabilities	$	1,782			$	1,524

The valuation allowance at December 31, 2019 and 2018, serves to reduce the available deferred income tax assets to an amount that will, more likely than not, be realized. We considered all available positive and negative evidence, including projected future taxable income, which incorporates available tax planning strategies, and management’s estimate of future reversals of existing taxable temporary differences, and have determined that a portion of our deferred income tax assets related to the Foreign tax credit and State losses and credits may not be realized. The completion of the WPZ Merger (see Note 1 – General, Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies) was a taxable exchange to the WPZ unit holders, which resulted in an adjustment to the tax basis in the underlying assets deemed acquired. A reduction to the deferred tax liability of $1.829 billion related to the book-tax basis difference in this investment was recorded in 2018. Increased tax depreciation from the additional tax basis will reduce future taxable income, which serves to impact our expected realization of the Foreign tax credit. The amounts presented in the table above are, with respect to state items, before any federal benefit. The change from prior year for the State losses and credits reflects increases in losses and credits generated in the current and prior years less losses and/or credits utilized in the current year. We have loss and credit carryovers in multiple state taxing jurisdictions. Additionally, valuation allowances on state net operating losses decreased by $31 million in 2018 after the completion of the WPZ Merger. These attributes generally expire between 2019 and 2038 with some carryovers having indefinite carryforward periods. The remaining federal Minimum tax credit of $29 million will be refunded/utilized no later than 2021.

Federal loss carryovers include deferred tax assets of $5 million at the end of 2019 that are expected to be utilized by us prior to expiration between 2020 and 2023. Deferred tax assets on net operating loss carryovers of $539 million have no expiration date.

Cash refunds for income taxes (net of payments) were $86 million in 2019. Cash payments for income taxes (net of refunds) were $11 million, and $28 million in 2018 and 2017, respectively.

As of December 31, 2019, we had approximately $51 million of unrecognized tax benefits. If recognized, income tax expense would be reduced by $51 million for each of the years 2019 and 2018, including the effect of these changes on other tax attributes, with state income tax amounts included net of federal tax effect. A reconciliation of the beginning and ending amount of unrecognized tax benefits is as follows:

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	2019				2018
	(Millions)
Balance at beginning of period	$	51			$	50
Additions for tax positions of prior years	—				1
Balance at end of period	$	51			$	51

We recognize related interest and penalties as a component of Provision (benefit) for income taxes. Total interest and penalties recognized as part of income tax provision were expenses of $500 thousand and $800 thousand for 2019 and 2018, respectively. Approximately $3 million of interest and penalties primarily relating to uncertain tax positions have been accrued as of both December 31, 2019 and 2018.

During the next 12 months, we do not expect ultimate resolution of any unrecognized tax benefit associated with domestic or international matters to have a material impact on our unrecognized tax benefit position.

Consolidated U.S. Federal income tax returns are open to Internal Revenue Service (IRS) examination for years after 2010, excluding 2015, for which the statute expired on August 31, 2019. As of December 31, 2019, examinations of tax returns for 2011 through 2013 are currently in process. We do not expect material changes in our financial position resulting from these examinations. The statute of limitations for most states expires one year after expiration of the IRS statute. Generally, tax returns for our previously owned Canadian entities are open to audit for tax years after 2012. Tax years 2013 and 2014 are currently under income tax examination, while tax year 2016 is under Goods and Services Tax (GST) examination. In September 2016, we sold the majority of our Canadian operations and, as part of the sale, indemnified the purchaser for any increases in Canadian tax due to an audit of any tax periods prior to the sale.

Note 9 – Earnings (Loss) Per Common Share from Continuing Operations

	Year Ended December 31,
	2019				2018				2017
	(Dollars in millions, except per-share amounts; shares in thousands)
Income (loss) from continuing operations available to common stockholders	$	862			$	(156	)		$	2,174
Basic weighted-average shares	1,212,037				973,626				826,177
Effect of dilutive securities:
Nonvested restricted stock units	1,811				—				1,704
Stock options	163				—				637
Diluted weighted-average shares (1)	1,214,011				973,626				828,518
Earnings (loss) per common share from continuing operations:
Basic	$	.71			$	(.16	)		$	2.63
Diluted	$	.71			$	(.16	)		$	2.62

________________

(1)	For the year ended December 31, 2018, 2.0 million weighted-average nonvested restricted stock units and 0.5 million weighted-average stock options have been excluded from the computation of diluted earnings (loss) per common share as their inclusion would be antidilutive due to our loss from continuing operations attributable to The Williams Companies, Inc.

Note 10 – Employee Benefit Plans

We have noncontributory defined benefit pension plans in which eligible employees participate. Currently, eligible employees earn benefits primarily based on a cash balance formula. At the time of retirement, participants may elect, to the extent they are eligible for the various options, to receive annuity payments, a lump-sum payment, or a combination of annuity and lump-sum payments. In addition to our pension plans, we currently provide subsidized retiree medical and life insurance benefits (other postretirement benefits) to certain eligible participants. Generally, employees hired after December 31, 1991, are not eligible for the subsidized retiree medical benefits, except for participants that were employees or retirees of Transco Energy Company on December 31, 1995. Subsidized retiree medical benefits for

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eligible participants age 65 and older are paid through contributions to health reimbursement accounts. Subsidized retiree medical benefits for eligible participants under age 65 are provided through a self-insured medical plan sponsored by us. The self-insured retiree medical plan provides for retiree contributions and contains other cost-sharing features such as deductibles, co-payments, and co-insurance. The accounting for this plan anticipates estimated future increases to our contribution levels to the health reimbursement accounts for participants age 65 and older, as well as future cost-sharing that is consistent with our expressed intent to increase the retiree contribution level generally in line with health care cost increases for participants under age 65.

In 2018, our defined benefit pension and our defined contribution plans were amended. Eligible employees hired or rehired on or after January 1, 2019, are not eligible to participate in the pension plan, but are eligible for an additional fixed annual contribution made by us to the defined contribution plan. Additionally, as of January 1, 2020, certain active eligible employees no longer receive future compensation credits under the defined benefit pension plan, but are eligible for an additional fixed annual contribution made by us to the defined contribution plan. Also as of January 1, 2020, certain active eligible employees continue to receive compensation credits under the defined benefit pension plans and these employees are not eligible to receive the fixed annual contribution under the defined contribution plan. As a result of this amendment, a curtailment gain and a prior service credit were recorded to Accumulated other comprehensive income (loss). These amounts were not significant and are reported in Net actuarial gain (loss) within the subsequent tables of changes in benefit obligations, amounts included in Accumulated other comprehensive income (loss), and other changes in plan assets and benefit obligations recognized in other comprehensive income (loss) before taxes.

In 2017, we initiated a program to pay out certain deferred vested pension benefits to reduce investment risk, cash funding volatility, and administrative costs. In December 2017 and August 2018, lump-sum payments were made, and annuity payments commenced in relation to this program. As a result of these lump-sum payments, as well as lump-sum benefit payments made throughout 2017 and 2018, settlement accounting was required. We recognized pre-tax, noncash settlement charges of $23 million in 2018 and $71 million in 2017, which are substantially reported in Other income (expense) – net below Operating income (loss) in the Consolidated Statement of Operations (see Note 7 – Other Income and Expenses). These amounts are included within the subsequent tables of net periodic benefit cost (credit) and other changes in plan assets and benefit obligations recognized in other comprehensive income (loss) before taxes.

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Funded Status

The following table presents the changes in benefit obligations and plan assets for pension benefits and other postretirement benefits for the years indicated:

	Pension Benefits								Other Postretirement Benefits
	2019				2018				2019				2018
	(Millions)
Change in benefit obligation:
Benefit obligation at beginning of year	$	1,187			$	1,319			$	186			$	206
Service cost	45				50				1				1
Interest cost	50				46				8				7
Plan participants’ contributions	—				—				2				2
Benefits paid	(111		)		(35		)		(12		)		(13		)
Net actuarial loss (gain)	69				(90		)		30				(17		)
Settlements	(3		)		(103		)		—				—
Net increase (decrease) in benefit obligation	50				(132		)		29				(20		)
Benefit obligation at end of year	1,237				1,187				215				186
Change in plan assets:
Fair value of plan assets at beginning of year	1,132				1,227				214				227
Actual return on plan assets	218				(45		)		38				(7		)
Employer contributions	63				88				5				5
Plan participants’ contributions	—				—				2				2
Benefits paid	(111		)		(35		)		(12		)		(13		)
Settlements	(3		)		(103		)		—				—
Net increase (decrease) in fair value of plan assets	167				(95		)		33				(13		)
Fair value of plan assets at end of year	1,299				1,132				247				214
Funded status — overfunded (underfunded)	$	62			$	(55	)		$	32			$	28
Accumulated benefit obligation	$	1,221			$	1,171

The overfunded (underfunded) status of our pension plans and other postretirement benefit plan presented in the previous table are recognized in the Consolidated Balance Sheet within the following accounts:

	December 31,
	2019				2018
	(Millions)
Overfunded (underfunded) pension plans:
Noncurrent assets	$	92			$	—
Current liabilities	(3		)		(2		)
Noncurrent liabilities	(27		)		(53		)
Overfunded (underfunded) other postretirement benefit plan:
Noncurrent assets	38				34
Current liabilities	(6		)		(6		)

The plan assets within our other postretirement benefit plan are intended to be used for the payment of benefits for certain groups of participants. The Current liabilities for the other postretirement benefit plan represent the current portion of benefits expected to be payable in the subsequent year for the groups of participants whose benefits are not expected to be paid from plan assets.

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The pension plans’ benefit obligation Net actuarial loss (gain) of $69 million in 2019 is primarily due to the impact of a decrease in the discount rates utilized to calculate the benefit obligation, partially offset by the impact of a decrease in the cash balance interest crediting rate assumption. The pension plans’ benefit obligation Net actuarial loss (gain) of $(90) million in 2018 is primarily due to the impact of an increase in the discount rates utilized to calculate the benefit obligation.

The 2019 benefit obligation Net actuarial loss (gain) of $30 million for our other postretirement benefit plan is primarily due a decrease in the discount rate used to calculate the benefit obligation and other assumption changes, partially offset by the impact of benefit payment experience and tax law changes. The 2018 benefit obligation Net actuarial loss (gain) of $(17) million for our other postretirement benefit plan is primarily due to an increase in the discount rate used to calculate the benefit obligation.

The following table summarizes information for pension plans with obligations in excess of plan assets.

	December 31,
	2019				2018
	(Millions)
Plans with a projected benefit obligation in excess of plan assets:
Projected benefit obligation	$	29			$	1,187
Fair value of plan assets	—				1,132
Plans with an accumulated benefit obligation in excess of plan assets:
Accumulated benefit obligation	26				367
Fair value of plan assets	—				326

Pre-tax amounts not yet recognized in Net periodic benefit cost (credit) at December 31 are as follows: 

	Pension Benefits								Other Postretirement Benefits
	2019				2018				2019				2018
	(Millions)
Amounts included in Accumulated other comprehensive income (loss):
Net actuarial loss	$	(243	)		$	(347	)		$	(21	)		$	(12	)
Amounts included in regulatory liabilities associated with Transco and Northwest Pipeline:
Net actuarial gain	N/A				N/A				$	11			$	4

In addition to the regulatory liabilities included in the previous table, differences in the amount of actuarially determined Net periodic benefit cost (credit) for our other postretirement benefit plan and the other postretirement benefit costs recovered in rates for Transco and Northwest Pipeline are deferred as a regulatory asset or liability. We have regulatory liabilities of $106 million at December 31, 2019 and $116 million at December 31, 2018, related to these deferrals. Additionally, Transco recognizes a regulatory liability for rate collections in excess of its amount funded to the tax-qualified pension plans. At December 31, 2019 and 2018, these regulatory liabilities were $43 million and $49 million, respectively. These pension and other postretirement plans amounts will be reflected in rates based on the rate structures of these gas pipelines.

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Net Periodic Benefit Cost (Credit)

Net periodic benefit cost (credit) for the years ended December 31 consist of the following:

	Pension Benefits												Other Postretirement  Benefits
	2019				2018				2017				2019				2018				2017
	(Millions)
Components of net periodic benefit cost (credit):
Service cost	$	45			$	50			$	50			$	1			$	1			$	1
Interest cost	50				46				59				8				7				8
Expected return on plan assets	(61		)		(63		)		(82		)		(10		)		(11		)		(11		)
Amortization of prior service credit	—				—				—				—				(2		)		(13		)
Amortization of net actuarial loss	15				23				27				—				—				—
Net actuarial loss from settlements	1				23				71				—				—				—
Reclassification to regulatory liability	—				—				—				1				2				3
Net periodic benefit cost (credit)	$	50			$	79			$	125			$	—			$	(3	)		$	(12	)

The components of Net periodic benefit cost (credit) other than the service cost component are included in Other income (expense) – net below Operating income (loss) in the Consolidated Statement of Operations.

Items Recognized in Other Comprehensive Income (Loss) and Regulatory Assets and Liabilities

Other changes in plan assets and benefit obligations recognized in Other comprehensive income (loss) before taxes for the years ended December 31 consist of the following:

	Pension Benefits												Other Postretirement  Benefits
	2019				2018				2017				2019				2018				2017
	(Millions)
Other changes in plan assets and benefit obligations recognized in Other comprehensive income (loss):
Net actuarial gain (loss)	$	88			$	(18	)		$	62			$	(9	)		$	9			$	(3	)
Amortization of prior service credit	—				—				—				—				—				(5		)
Amortization of net actuarial loss	15				23				27				—				—				—
Net actuarial loss from settlements	1				23				71				—				—				—
Other changes in plan assets and benefit obligations recognized in Other comprehensive income (loss)	$	104			$	28			$	160			$	(9	)		$	9			$	(8	)

Other changes in plan assets and benefit obligations for our other postretirement benefit plan associated with Transco and Northwest Pipeline are recognized in regulatory assets and liabilities. Amounts recognized in regulatory assets and liabilities for the years ended December 31 consist of the following:

		2019				2018				2017
		(Millions)
Other changes in plan assets and benefit obligations recognized in regulatory (assets) and liabilities:
Net actuarial gain (loss)		$	7			$	(10	)		$	6
Amortization of prior service credit		—				(2		)		(8		)

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Key Assumptions

The weighted-average assumptions utilized to determine benefit obligations as of December 31 are as follows: 

	Pension Benefits						Other Postretirement Benefits
	2019			2018			2019			2018
Discount rate	3.19	%		4.34	%		3.27	%		4.39	%
Rate of compensation increase	3.68			4.83			N/A			N/A
Cash balance interest crediting rate	3.50			4.25			N/A			N/A

The weighted-average assumptions utilized to determine Net periodic benefit cost (credit) for the years ended December 31 are as follows: 

	Pension Benefits									Other Postretirement  Benefits
	2019			2018			2017			2019			2018			2017
Discount rate	4.33	%		3.67	%		4.17	%		4.39	%		3.71	%		4.27	%
Expected long-term rate of return on plan assets	5.26			5.34			6.45			5.01			4.95			5.53
Rate of compensation increase	4.83			4.93			4.87			N/A			N/A			N/A
Cash balance interest crediting rate	4.25			4.25			4.25			N/A			N/A			N/A

The mortality assumptions used to determine the benefit obligations for our pension and other postretirement benefit plans reflect generational projection mortality tables.

Plan Assets

Plan assets for our pension and other postretirement benefit plans consist primarily of equity and fixed income securities including mutual funds and commingled investment funds invested in equity and fixed income securities. The plans’ investment policy provides for a strategy in accordance with the Employee Retirement Income Security Act (ERISA), which governs the investment of the assets in a diversified portfolio. The plans follow a policy of diversifying the investments across various asset classes and investment managers. Additionally, the investment returns on approximately 37 percent of the other postretirement benefit plan assets are subject to income tax; therefore, certain investments are managed in a tax efficient manner.

The investment policy for the pension plans includes a general target asset allocation at December 31, 2019, of 25 percent equity securities and 75 percent fixed income securities. The target allocation includes the investments in equity and fixed income mutual funds and commingled investment funds.

Equity securities may include U.S. equities and non-U.S. equities. Investment in Williams’ securities or an entity in which Williams has a majority ownership is prohibited except where these securities may be owned in a commingled investment fund in which the plans’ trusts invest. No more than 5 percent of the total stock portfolio valued at market may be invested in the common stock of any one corporation.

Fixed income securities may consist of U.S. as well as international instruments, including emerging markets. The fixed income strategies may invest in government, corporate, asset-backed securities, and mortgage-backed obligations. The weighted-average credit rating of the fixed income strategies must be at least “investment grade” including ratings by Moody’s and/or Standard & Poor’s. No more than 5 percent of the total fixed income portfolio may be invested in the fixed income securities of any one issuer with the exception of bond index funds and U.S. government guaranteed and agency securities.

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The following securities and transactions are not authorized: unregistered securities, commodities or commodity contracts, short sales or margin transactions, or other leveraging strategies. Additionally, real estate equity, natural resource property, venture capital, leveraged buyouts, and other high-return, high-risk investments are generally restricted. Use of derivative securities in mutual funds and commingled investment funds held by the plans’ trusts is allowed. However, direct investment in derivative securities requires approval. Currently, investment managers are approved to enter into U.S. Treasury futures contracts on behalf of the plans to implement and manage duration and yield curve strategy in the fixed income portfolio.

There are no significant concentrations of risk within the plans’ investment securities because of the diversity of the types of investments, diversity of the various industries, and the diversity of the fund managers and investment strategies. Generally, the investments held in the plans are publicly traded, therefore, minimizing liquidity risk in the portfolio.

The fair values of our pension plan assets at December 31, 2019 and 2018 by asset class are as follows: 

	2019
	Quoted Prices in Active Markets for Identical Assets (Level 1)				Significant Other Observable Inputs (Level 2)				Significant Unobservable Inputs (Level 3)				Total
	(Millions)
Pension assets:
Cash management fund	$	11			$	—			$	—			$	11
Equity securities	41				22				—				63
Fixed income securities (1):
U.S. Treasury securities	62				—				—				62
Governments and municipal bonds	—				35				—				35
Mortgage and asset-backed securities	—				11				—				11
Corporate bonds	—				360				—				360
Other	5				4				—				9
	$	119			$	432			$	—			551
Commingled investment funds measured at net asset value practical expedient (2):
Equities — U.S. large cap													133
Equities — Global large and mid cap													100
Equities — International emerging markets													26
Fixed income — U.S. long and intermediate duration													380
Fixed income — Corporate bonds													109
Total assets at fair value at December 31, 2019													$	1,299

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	2018
	Quoted Prices in Active Markets for Identical Assets (Level 1)				Significant Other Observable Inputs (Level 2)				Significant Unobservable Inputs (Level 3)				Total
	(Millions)
Pension assets:
Cash management fund	$	10			$	—			$	—			$	10
Equity securities	52				—				—				52
Fixed income securities (1):
U.S. Treasury securities	157				—				—				157
Government and municipal bonds	—				21				—				21
Mortgage and asset-backed securities	—				48				—				48
Corporate bonds	—				210				—				210
Insurance company investment contracts and other	—				6				—				6
	$	219			$	285			$	—			504
Commingled investment funds measured at net asset value practical expedient (2):
Equities — U.S. large cap													123
Equities — International small cap													8
Equities — International emerging markets													19
Equities — International developed markets													51
Fixed income — U.S. long duration													335
Fixed income — Corporate bonds													92
Total assets at fair value at December 31, 2018													$	1,132

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The fair values of our other postretirement benefits plan assets at December 31, 2019 and 2018 by asset class are as follows:

	2019
	Quoted Prices in Active Markets for Identical Assets (Level 1)				Significant Other Observable Inputs (Level 2)				Significant Unobservable Inputs (Level 3)				Total
	(Millions)
Other postretirement benefit assets:
Cash management funds	$	11			$	—			$	—			$	11
Equity securities	35				9				—				44
Fixed income securities (1):
U.S. Treasury securities	8				—				—				8
Governments and municipal bonds	—				4				—				4
Mortgage and asset-backed securities	—				1				—				1
Corporate bonds	—				43				—				43
Mutual fund — Municipal bonds	46				—				—				46
	$	100			$	57			$	—			157
Commingled investment funds measured at net asset value practical expedient (2):
Equities — U.S. large cap													16
Equities — Global large and mid cap													12
Equities — International emerging markets													3
Fixed income — U.S. long and intermediate duration													46
Fixed income — Corporate bonds													13
Total assets at fair value at December 31, 2019													$	247

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	2018
	Quoted Prices in Active Markets for Identical Assets (Level 1)				Significant Other Observable Inputs (Level 2)				Significant Unobservable Inputs (Level 3)				Total
	(Millions)
Other postretirement benefit assets:
Cash management funds	$	11			$	—			$	—			$	11
Equity securities	29				5				—				34
Fixed income securities (1):
U.S. Treasury securities	19				—				—				19
Government and municipal bonds	—				2				—				2
Mortgage and asset-backed securities	—				6				—				6
Corporate bonds	—				25				—				25
Mutual fund — Municipal bonds	43				—				—				43
	$	102			$	38			$	—			140
Commingled investment funds measured at net asset value practical expedient (2):
Equities — U.S. large cap													14
Equities — International small cap													1
Equities — International emerging markets													2
Equities — International developed markets													6
Fixed income — U.S. long duration													40
Fixed income — Corporate bonds													11
Total assets at fair value at December 31, 2018													$	214

____________

(1)	The weighted-average credit quality rating of the fixed income security portfolio is investment grade with a weighted-average duration of approximately 14 years for 2019 and 13 years for 2018.

(2)

The stated intents of the funds vary based on each commingled fund’s investment objective. These objectives generally include strategies to replicate or outperform various market indices. Certain standard withdrawal restrictions generally apply, which may include redemption notification period restrictions ranging from 1 day to 30 days. Additionally, the fund managers retain the right to restrict withdrawals from and/or purchases into the funds so as not to disadvantage other investors in the funds. Generally, the funds also reserve the right to make all or a portion of the redemption in-kind rather than in cash or a combination of cash and in-kind.

The fair value measurement level within the fair value hierarchy is based on the lowest level of any input that is significant to the fair value measurement of an asset.

Shares of the cash management funds and mutual funds are valued at fair value based on published market prices as of the close of business on the last business day of the year, which represents the net asset values of the shares held.

The fair values of equity securities traded on U.S. exchanges are derived from quoted market prices as of the close of business on the last business day of the year. The fair values of equity securities traded on foreign exchanges are also derived from quoted market prices as of the close of business on an active foreign exchange on the last business day of the year. However, the valuation requires translation of the foreign currency to U.S. dollars and this translation is considered an observable input to the valuation.

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The fair values of all commingled investment funds are determined based on the net asset values per unit of each of the funds. The net asset values per unit represent the aggregate values of the funds’ assets at fair value less liabilities, divided by the number of units outstanding.

The fair values of fixed income securities, except U.S. Treasury securities, are determined using pricing models. These pricing models incorporate observable inputs such as benchmark yields, reported trades, broker/dealer quotes, and issuer spreads for similar securities to determine fair value. The U.S. Treasury securities are valued at fair value based on closing prices on the last business day of the year reported in the active market in which the security is traded.

There have been no significant changes in the preceding valuation methodologies used at December 31, 2019 and 2018. Additionally, there were no transfers or reclassifications of investments between Level 1 and Level 2 from December 2018 to December 2019. If transfers between levels had occurred, the transfers would have been recognized as of the end of the period.

Plan Benefit Payments and Employer Contributions

Following are the expected benefits to be paid by the plans. These estimates are based on the same assumptions previously discussed and reflect future service as appropriate. The actuarial assumptions are based on long-term expectations and include, but are not limited to, assumptions as to average expected retirement age and form of benefit payment. Actual benefit payments could differ significantly from expected benefit payments if near-term participant behaviors differ significantly from the actuarial assumptions. 

	Pension Benefits				Other Postretirement Benefits
	(Millions)
2020	$	100			$	14
2021	99				14
2022	97				14
2023	93				14
2024	90				14
2025-2029	433				62

In 2020, we expect to contribute approximately $10 million to our tax-qualified pension plans and approximately $3 million to our nonqualified pension plans, for a total of approximately $13 million, and approximately $6 million to our other postretirement benefit plan.

Defined Contribution Plan

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Note 11 – Leases

We are a lessee through noncancellable lease agreements for property and equipment consisting primarily of buildings, land, vehicles, and equipment used in both our operations and administrative functions.

	Year Ended December 31,
	2019
	(Millions)
Lease Cost:
Operating lease cost	$	40
Short-term lease cost	—
Variable lease cost	27
Sublease income	(2		)
Total lease cost	$	65
Cash paid for amounts included in the measurement of operating lease liabilities	$	39
	December 31, 2019
	(Millions)
Other Information:
Right-of-use asset (included in Regulatory assets, deferred charges, and other in our Consolidated Balance Sheet)	$	207
Operating lease liabilities:
Current (included in Accrued liabilities in our Consolidated Balance Sheet)	$	21
Noncurrent (included in Regulatory liabilities, deferred income, and other in our Consolidated Balance Sheet)	$	188
Weighted-average remaining lease term – operating leases (years)	13
Weighted-average discount rate – operating leases	4.61%

Prior to adopting ASU 2016-02, which was effective January 1, 2019 (see Note 1 – General, Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies), total rent expense was $73 million in 2018 and $62 million in 2017 and primarily included in Operating and maintenance expenses and Selling, general, and administrative expenses in the Consolidated Statement of Operations.

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As of December 31, 2019, the following table represents our operating lease maturities, including renewal provisions that we have assessed as being reasonably certain of exercise, for each of the years ended December 31:

	(Millions)
2020	$	29
2021	33
2022	28
2023	22
2024	19
Thereafter	157
Total future lease payments	288
Less amount representing interest	79
Total obligations under operating leases	$	209

We are the lessor to certain lease agreements for office space in our headquarters building, which are insignificant to our financial statements.

Note 12 – Property, Plant, and Equipment

The following table presents nonregulated and regulated Property, plant, and equipment – net as presented on the Consolidated Balance Sheet for the years ended:

	Estimated Useful Life  (1) (Years)		Depreciation Rates (1) (%)		December 31,
					2019				2018
					(Millions)
Nonregulated:
Natural gas gathering and processing facilities	5 - 40				$	17,593			$	15,324
Construction in progress	Not applicable				354				778
Other	2 - 45				2,519				2,356
Regulated:
Natural gas transmission facilities			1.25 - 7.13		18,076				17,312
Construction in progress	Not applicable		Not applicable		586				965
Other	5 - 45		0.00 - 33.33		2,382				1,926
Total property, plant, and equipment, at cost					41,510				38,661
Accumulated depreciation and amortization					(12,310		)		(11,157		)
Property, plant, and equipment — net					$	29,200			$	27,504

__________

(1)	Estimated useful life and depreciation rates are presented as of December 31, 2019. Depreciation rates and estimated useful lives for regulated assets are prescribed by the FERC.

Depreciation and amortization expense for Property, plant, and equipment – net was $1.390 billion, $1.392 billion, and $1.389 billion in 2019, 2018, and 2017, respectively.

Regulated Property, plant, and equipment – net includes approximately $547 million and $586 million at December 31, 2019 and 2018, respectively, related to amounts in excess of the original cost of the regulated facilities within our gas pipeline businesses as a result of our prior acquisitions. This amount is being amortized over 40 years using the straight-line amortization method. Current FERC policy does not permit recovery through rates for amounts in excess of original cost of construction.

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Asset Retirement Obligations

Our accrued obligations relate to underground storage caverns, offshore platforms and pipelines, fractionation and compression facilities, gas gathering well connections and pipelines, and gas transmission pipelines and facilities. At the end of the useful life of each respective asset, we are legally obligated to plug storage caverns and remove any related surface equipment, to restore land and remove surface equipment at gas processing, fractionation, and compression facilities, to dismantle offshore platforms and appropriately abandon offshore pipelines, to cap certain gathering pipelines at the wellhead connection and remove any related surface equipment, and to remove certain components of gas transmission facilities from the ground.

The following table presents the significant changes to our ARO, of which $1.117 billion and $968 million are included in Regulatory liabilities, deferred income, and other with the remaining current portion in Accrued liabilities at December 31, 2019 and 2018, respectively.

	December 31,
	2019				2018
	(Millions)
Beginning balance	$	1,032			$	998
Liabilities incurred	15				21
Liabilities settled	(8		)		(19		)
Accretion expense	59				71
Revisions (1)	67				(39		)
Ending balance	$	1,165			$	1,032

___________

(1)

Several factors are considered in the annual review process, including inflation rates, current estimates for removal cost, market risk premiums, discount rates, and the estimated remaining useful life of the assets. The 2019 revisions reflect changes in removal cost estimates, decreases in the estimated remaining useful life of certain assets, increases in inflation rates, and decreases in the discount rates used in the annual review process. The 2018 revisions reflect changes in removal cost estimates, decreases in the estimated remaining useful life of certain assets, and increases in the discount rates used in the annual review process.

The funds Transco collects through a portion of its rates to fund its ARO are deposited into an external trust account dedicated to funding its ARO (ARO Trust). (See Note 18 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk.) Under its current rate settlement, Transco’s annual funding obligation is approximately $36 million, with installments to be deposited monthly.

Note 13 – Goodwill and Other Intangible Assets

Goodwill

Changes in the carrying amount of goodwill, included in Intangible assets – net of accumulated amortization in the Consolidated Balance Sheet, by reportable segment for the periods indicated are as follows:

	Northeast G&P				West				Total
	(Millions)
December 31, 2017	$	—			$	47			$	47
Jackalope Deconsolidation (see Note 6)					(47		)		(47		)
December 31, 2018	—				—				—
UEOM Acquisition (see Note 3)	188								188
December 31, 2019	$	188			$	—			$	188

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Our goodwill is not subject to amortization, but is evaluated at least annually for impairment or more frequently if impairment indicators are present. We did not identify or recognize any impairments to goodwill in connection with our evaluation of goodwill for impairment during the years ended December 31, 2019, 2018, and 2017, respectively.

Other Intangible Assets

The gross carrying amount and accumulated amortization of other intangible assets, included in Intangible assets – net of accumulated amortization in the Consolidated Balance Sheet, at December 31 are as follows:

	2019								2018
	Gross Carrying Amount				Accumulated Amortization				Gross Carrying Amount				Accumulated Amortization
	(Millions)
Contractual customer relationships	$	9,560			$	(1,789	)		$	9,232			$	(1,465	)

Other intangible assets primarily relate to gas gathering, processing, and fractionation contractual customer relationships recognized in acquisitions. The increase in the gross carrying amount of other intangible assets during 2019 is primarily related to the acquisition of UEOM (see Note 3 – Acquisitions and Divestitures). Other intangible assets are being amortized on a straight-line basis over a period of 20 years for the acquisition of UEOM and 30 years for other acquisitions, which represents a portion of the term over which the contractual customer relationships are expected to contribute to our cash flows.

We expense costs incurred to renew or extend the terms of our gas gathering, processing, and fractionation contracts with customers. Based on the estimated future revenues during the contract periods (as estimated at the time of the acquisition), the weighted-average period prior to the next renewal or extension of the contractual customer relationships associated with the UEOM acquisition was approximately 10 years. Although a significant portion of the expected future cash flows associated with these contractual customer relationships are dependent on our ability to renew or extend the arrangements beyond the initial contract periods, these expected future cash flows are significantly influenced by the scope and pace of our producer customers’ drilling programs. Once producer customers’ wells are connected to our gathering infrastructure, their likelihood of switching to another provider before the wells are abandoned is reduced due to the significant capital investment required.

The amortization expense related to other intangible assets was $324 million, $333 million, and $347 million in 2019, 2018, and 2017, respectively. The estimated amortization expense for each of the next five succeeding fiscal years is approximately $328 million.

Note 14 – Accrued Liabilities

	December 31,
	2019				2018
	(Millions)
Interest on debt	$	288			$	282
Employee costs	226				205
Estimated rate refund liabilities (Note 19)	189				—
Contract liabilities (Note 2)	158				244
Asset retirement obligation (Note 12)	48				64
Operating lease liabilities (Note 11)	21				—
Other, including other loss contingencies	346				307
	$	1,276			$	1,102

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Note 15 – Debt and Banking Arrangements

Long-Term Debt

	December 31,
	2019				2018
	(Millions)
Transco:
7.08% Debentures due 2026	$	8			$	8
7.25% Debentures due 2026	200				200
7.85% Notes due 2026	1,000				1,000
4% Notes due 2028	400				400
5.4% Notes due 2041	375				375
4.45% Notes due 2042	400				400
4.6% Notes due 2048	600				600
Other financing obligation - Atlantic Sunrise	857				807
Other financing obligation - Dalton	259				260
Northwest Pipeline:
7.125% Debentures due 2025	85				85
4% Notes due 2027	500				500
WMB:
4.125% Notes due 2020	600				600
5.25% Notes due 2020	1,500				1,500
4% Notes due 2021	500				500
7.875% Notes due 2021	371				371
3.35% Notes due 2022	750				750
3.6% Notes due 2022	1,250				1,250
3.7% Notes due 2023	850				850
4.5% Notes due 2023	600				600
4.3% Notes due 2024	1,000				1,000
4.55% Notes due 2024	1,250				1,250
3.9% Notes due 2025	750				750
4% Notes due 2025	750				750
3.75% Notes due 2027	1,450				1,450
7.5% Debentures due 2031	339				339
7.75% Notes due 2031	252				252
8.75% Notes due 2032	445				445
6.3% Notes due 2040	1,250				1,250
5.8% Notes due 2043	400				400
5.4% Notes due 2044	500				500
5.75% Notes due 2044	650				650
4.9% Notes due 2045	500				500
5.1% Notes due 2045	1,000				1,000
4.85% Notes due 2048	800				800
Various — 7.625% to 10.25% Notes and Debentures due 2019 to 2027	24				55
Credit facility loans	—				160
Debt issuance costs	(119		)		(131		)
Net unamortized debt premium (discount)	(58		)		(62		)
Total long-term debt, including current portion	22,288				22,414
Long-term debt due within one year	(2,140		)		(47		)
Long-term debt	$	20,148			$	22,367

Certain of our debt agreements contain covenants that restrict or limit, among other things, our ability to create liens supporting indebtedness, sell assets, and incur additional debt. Default of these agreements could also restrict our ability to make certain distributions or repurchase equity.

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The following table presents aggregate minimum maturities of long-term debt and other financing obligations, excluding net unamortized debt premium (discount) and debt issuance costs, for each of the next five years: 

	December 31, 2019
	(Millions)
2020	$	2,141
2021	893
2022	2,025
2023	1,477
2024	2,279

Issuances and retirements

We retired $14 million of 8.75 percent senior unsecured notes that matured on January 15, 2020.

We retired $32 million of 7.625 percent senior unsecured notes that matured on July 15, 2019.

On August 24, 2018, Northwest Pipeline issued $250 million of 4 percent senior unsecured notes to investors in a private debt placement. The notes are an additional issuance of Northwest Pipeline’s existing 4 percent senior unsecured notes due 2027. In the fourth quarter of 2018, Northwest Pipeline filed a registration statement and completed an exchange of these notes for substantially identical new notes that are registered under the Securities Act of 1933, as amended.

Northwest Pipeline retired $250 million of 6.05 percent senior unsecured notes that matured on June 15, 2018.

On March 5, 2018, WPZ completed a public offering of $800 million of 4.85 percent senior unsecured notes due 2048. WPZ used the net proceeds for general partnership purposes, primarily the March 28, 2018 repayment of $750 million of 4.875 percent senior unsecured notes that were due in 2024.

On March 15, 2018, Transco issued $400 million of 4 percent senior unsecured notes due 2028 and $600 million of 4.6 percent senior unsecured notes due 2048 to investors in a private debt placement. Transco used the net proceeds to retire $250 million of 6.05 percent senior unsecured notes that matured on June 15, 2018, and for general corporate purposes, including the funding of capital expenditures. In the third quarter of 2018, Transco filed a registration statement and completed an exchange of these notes for substantially identical new notes that are registered under the Securities Act of 1933, as amended.

Other financing obligations

During the construction of the Atlantic Sunrise and Dalton projects, Transco received funding from its partners for their proportionate share of construction costs. Amounts received were recorded within noncurrent liabilities and the costs associated with construction were capitalized in our Consolidated Balance Sheet. Upon placing these projects into service Transco began utilizing the partners’ undivided interest in the assets, including the associated pipeline capacity, and reclassified the funding previously received from its partners from noncurrent liabilities to debt. The obligations, which mature in 2038 and 2052, respectively, require monthly interest and principal payments and both bear an interest rate of approximately 9 percent.

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Credit Facilities

	December 31, 2019
	Stated Capacity				Outstanding
	(Millions)
Long-term credit facility (1)	$	4,500			$	—
Letters of credit under certain bilateral bank agreements					14

________________

(1)	In managing our available liquidity, we do not expect a maximum outstanding amount in excess of the capacity of our credit facility inclusive of any outstanding amounts under our commercial paper program.

Revolving credit facility

On July 13, 2018, we along with Transco and Northwest Pipeline, the lenders named therein, and an administrative agent entered into a credit agreement (Credit Agreement) with aggregate commitments available of $4.5 billion, with up to an additional $500 million increase in aggregate commitments available under certain circumstances. On August 10, 2018, following the completion of the WPZ Merger, the Credit Agreement became effective. The maturity date of the credit facility is August 10, 2023. However, the co-borrowers may request up to two extensions of the maturity date each for an additional one-year period to allow a maturity date as late as August 10, 2025, under certain circumstances. The Credit Agreement allows for swing line loans up to an aggregate of $200 million, subject to available capacity under the credit facility, and letters of credit commitments of $1 billion. Transco and Northwest Pipeline are each able to borrow up to $500 million under this credit facility to the extent not otherwise utilized by the other co-borrowers.

The Credit Agreement contains the following terms and conditions:

•	Various covenants may limit, among other things, a borrower’s and its material subsidiaries’ ability to grant certain liens supporting indebtedness, merge or consolidate, sell all or substantially all of its assets, make certain distributions during an event of default, and enter into certain restrictive agreements.

•	If an event of default with respect to a borrower occurs under the credit facility, the lenders will be able to terminate the commitments and accelerate the maturity of the loans and exercise other rights and remedies.

•

Other than swing line loans, each time funds are borrowed, the applicable borrower may choose from two methods of calculating interest: a fluctuating base rate equal to Citibank N.A.'s alternate base rate plus an applicable margin or a periodic fixed rate equal to the London Interbank Offered Rate plus an applicable margin. We are required to pay a commitment fee based on the unused portion of the credit facility. The applicable margin and the commitment fee are determined by reference to a pricing schedule based on the applicable borrower’s senior unsecured long-term debt ratings.

Significant financial covenants under the Credit Agreement require the ratio of debt to EBITDA (earnings before interest, taxes, depreciation, and amortization), each as defined in the credit facility, to be no greater than:

•	5.75 to 1 for each fiscal quarter end through June 30, 2019;

•	5.5 to 1 for the fiscal quarters ending September 30, 2019, and December 31, 2019;

•	5.0 to 1 for the fiscal quarter ending March 31, 2020, and each subsequent fiscal quarter end, except for the fiscal quarter and the two following fiscal quarters in which one or more acquisitions with a total aggregate purchase price of $25 million or more has been executed, in which case the ratio of debt to EBITDA is to be no greater than 5.5 to 1.

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The ratio of debt to capitalization (defined as net worth plus debt) must be no greater than 65 percent for each of Transco and Northwest Pipeline.

At December 31, 2019, we are in compliance with these covenants.

Commercial Paper Program

On August 10, 2018, following the consummation of the WPZ Merger, we entered into a $4 billion commercial paper program. The maturities of the commercial paper notes vary but may not exceed 397 days from the date of issuance. The commercial paper notes are sold under customary terms in the commercial paper market and are issued at a discount from par, or, alternatively, are sold at par and bear varying interest rates on a fixed or floating basis. The net proceeds of issuances of the commercial paper notes are expected to be used to fund planned capital expenditures and for other general corporate purposes. At December 31, 2019 and 2018, no commercial paper was outstanding.

Cash Payments for Interest (Net of Amounts Capitalized)

Cash payments for interest (net of amounts capitalized) were $1.153 billion in 2019, $1.064 billion in 2018, and $1.110 billion in 2017.

Note 16 – Stockholders' Equity

On January 28, 2020, our board of directors approved a regular quarterly dividend to common stockholders of $0.40 per share payable on March 30, 2020.

In July 2018, through a wholly owned subsidiary, we contributed 35,000 shares of newly issued Series B Non-Voting Perpetual Preferred Stock (Preferred Stock) to The Williams Companies Foundation, Inc. (a not-for-profit corporation) for use in future charitable and nonprofit causes. The charitable contribution of Preferred Stock was recorded as an expense in the third quarter of 2018. The Preferred Stock was issued for an aggregate value of $35 million and pays non-cumulative quarterly cash dividends when, as and if declared, at a rate of 7.25 percent per year. Our certificate of incorporation authorizes 30 million shares of Preferred Stock, $1 par value per share.

In January 2017, we issued 65 million shares of common stock in a public offering at a price of $29.00 per share. In February 2017, we issued 9.75 million shares of common stock pursuant to the full exercise of the underwriter’s option to purchase additional shares. The net proceeds of approximately $2.1 billion were used to purchase newly issued common units in WPZ as part of our Financial Repositioning. (See Note 1 – General, Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies.)

AOCI

The following table presents the changes in AOCI by component, net of income taxes:

	Cash Flow Hedges				Foreign Currency Translation				Pension and Other Post Retirement Benefits				Total
	(Millions)
Balance at December 31, 2018	$	(2	)		$	(1	)		$	(267	)		$	(270	)
Other comprehensive income (loss) before reclassifications	—				—				59				59
Amounts reclassified from accumulated other comprehensive income (loss)	—				—				12				12
Other comprehensive income (loss)	—				—				71				71
Balance at December 31, 2019	$	(2	)		$	(1	)		$	(196	)		$	(199	)

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Reclassifications out of AOCI are presented in the following table by component for the year ended December 31, 2019:

Note 17 – Equity-Based Compensation

Williams’ Plan Information

The Williams Companies, Inc. 2007 Incentive Plan (the Plan) provides common-stock-based awards to both employees and nonmanagement directors. To date, 40 million new shares have been authorized for making awards under the Plan. The Plan permits the granting of various types of awards including, but not limited to, restricted stock units and stock options. At December 31, 2019, 23 million shares of our common stock were reserved for issuance pursuant to existing and future stock awards, of which 11 million shares were available for future grants.

Additionally, up to 3.6 million new shares of our common stock have been authorized to date to be available for sale under our Employee Stock Purchase Plan (ESPP). Employees purchased 322 thousand shares at a weighted-average price of $19.55 per share during 2019. Approximately 424 thousand shares were available for purchase under the ESPP at December 31, 2019.

Operating and maintenance expenses and Selling, general, and administrative expenses in the Consolidated Statement of Operations include equity-based compensation expense for the years ended December 31, 2019, 2018, and 2017 of $57 million, $54 million, and $70 million, respectively. Income tax benefit recognized related to the stock-based compensation expense for the years ended December 31, 2019, 2018, and 2017 was $14 million, $14 million, and $17 million, respectively. Measured but unrecognized stock-based compensation expense at December 31, 2019, was $60 million, comprised of $2 million related to stock options and $58 million related to restricted stock units. These amounts are expected to be recognized over a weighted-average period of 2.8 years.

Stock Options

The following summary reflects stock option activity and related information for the year ended December 31, 2019:

Stock Options	Options			Weighted- Average Exercise Price				Aggregate Intrinsic Value
	(Millions)							(Millions)
Outstanding at December 31, 2018	7.3			$	31.55
Granted	—			$	—
Exercised	(0.4	)		$	11.31
Cancelled	(0.1	)		$	35.62
Outstanding at December 31, 2019	6.8			$	32.64			$	2
Exercisable at December 31, 2019	5.8			$	33.22			$	2

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The following table summarizes additional information related to stock option activity during each of the last three years:

	Year Ended December 31,
	2019				2018				2017
	(Millions)
Total intrinsic value of options exercised	$	6			$	3			$	4
Tax benefits realized on options exercised	$	1			$	—			$	1
Cash received from the exercise of options	$	4			$	9			$	7

The weighted-average remaining contractual lives for stock options outstanding and exercisable at December 31, 2019, were 4.2 years and 3.6 years, respectively.

The estimated fair value at date of grant of options for our common stock granted in each respective year, using the Black-Scholes option pricing model, is as follows:

	2018				2017
Weighted-average grant date fair value of options for our common stock granted during the year, per share	$	5.49			$	6.61
Weighted-average assumptions:
Dividend yield	4.7		%		4.2		%
Volatility	30.1		%		35.1		%
Risk-free interest rate	2.7		%		2.1		%
Expected life (years)	6.0				6.0

There were no stock options granted in 2019. The expected dividend yield for each respective year is based on the dividend forecast for that year and the grant-date market price of our stock. Our expected future volatility is determined using the historical volatility of our stock and implied volatility on our traded options. Historical volatility is based on the blended 10-year historical volatility of our stock and certain peer companies. The risk-free interest rate is based on the U.S. Treasury Constant Maturity rates as of the grant date. The expected life of the option is based on historical exercise behavior and expected future experience.

Nonvested Restricted Stock Units

The following summary reflects nonvested restricted stock unit activity and related information for the year ended December 31, 2019:

Restricted Stock Units Outstanding	Shares			Weighted- Average Fair Value (1)
	(Millions)
Nonvested at December 31, 2018	4.5			$	28.96
Granted	2.5			$	25.87
Forfeited	(0.5	)		$	28.48
Vested	(1.1	)		$	26.25
Nonvested at December 31, 2019	5.4			$	28.11

______________

(1)	Performance-based restricted stock units are valued considering measures of total shareholder return utilizing a Monte Carlo valuation method and return on capital employed. All other restricted stock units are valued at the grant-date market price. Restricted stock units generally vest after three years.

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Value of Restricted Stock Units	2019				2018				2017
Weighted-average grant date fair value of restricted stock units granted during the year, per share	$	25.87			$	30.48			$	29.47
Total fair value of restricted stock units vested during the year (in millions)	$	29			$	35			$	33

Performance-based restricted stock units granted under the Plan represent 39 percent of nonvested restricted stock units outstanding at December 31, 2019. These grants may be earned at the end of the vesting period based on actual performance against a performance target. Based on the extent to which certain financial targets are achieved, vested shares may range from zero percent to 200 percent of the original grant amount.

Note 18 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk

The following table presents, by level within the fair value hierarchy, certain of our financial assets and liabilities. The carrying values of cash and cash equivalents, accounts receivable, margin deposits, and accounts payable approximate fair value because of the short-term nature of these instruments. Therefore, these assets and liabilities are not presented in the following table.

									Fair Value Measurements Using
	Carrying Amount				Fair Value				Quoted Prices In Active Markets for Identical Assets (Level 1)				Significant Other Observable Inputs (Level 2)				Significant Unobservable Inputs (Level 3)
	(Millions)
Assets (liabilities) at December 31, 2019:
Measured on a recurring basis:
ARO Trust investments	$	201			$	201			$	201			$	—			$	—
Energy derivative assets not designated as hedging instruments	1				1				1				—				—
Energy derivative liabilities not designated as hedging instruments	(3		)		(3		)		(1		)		—				(2		)
Additional disclosures:
Long-term debt, including current portion	(22,288		)		(25,319		)		—				(25,319		)		—
Guarantees	(41		)		(27		)		—				(11		)		(16		)
Assets (liabilities) at December 31, 2018:
Measured on a recurring basis:
ARO Trust investments	$	150			$	150			$	150			$	—			$	—
Energy derivative assets not designated as hedging instruments	3				3				3				—				—
Energy derivative liabilities not designated as hedging instruments	(7		)		(7		)		(4		)		—				(3		)
Additional disclosures:
Long-term debt, including current portion	(22,414		)		(23,330		)		—				(23,330		)		—
Guarantees	(43		)		(30		)		—				(14		)		(16		)

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Fair Value Methods

We use the following methods and assumptions in estimating the fair value of our financial instruments:

Assets and liabilities measured at fair value on a recurring basis

ARO Trust investments: Transco deposits a portion of its collected rates, pursuant to its rate case settlement, into an external trust that is specifically designated to fund future ARO’s. The ARO Trust invests in a portfolio of actively traded mutual funds that are measured at fair value on a recurring basis based on quoted prices in an active market and is reported in Regulatory assets, deferred charges, and other in the Consolidated Balance Sheet. Both realized and unrealized gains and losses are ultimately recorded as regulatory assets or liabilities.

Energy derivatives: Energy derivatives include commodity-based exchange-traded contracts and over-the-counter contracts, which consist of physical forwards, futures, and swaps that are measured at fair value on a recurring basis. The fair value amounts are presented on a gross basis and do not reflect the netting of asset and liability positions permitted under the terms of our master netting arrangements. Further, the amounts do not include cash held on deposit in margin accounts that we have received or remitted to collateralize certain derivative positions. Energy derivative assets are reported in Other current assets and deferred charges and Regulatory assets, deferred charges, and other in the Consolidated Balance Sheet. Energy derivative liabilities are reported in Accrued liabilities and Regulatory liabilities, deferred income, and other in the Consolidated Balance Sheet.

Reclassifications of fair value between Level 1, Level 2, and Level 3 of the fair value hierarchy, if applicable, are made at the end of each quarter. No transfers between Level 1 and Level 2 occurred during the years ended December 31, 2019 or 2018.

Additional fair value disclosures

Long-term debt, including current portion: The disclosed fair value of our long-term debt is determined primarily by a market approach using broker quoted indicative period-end bond prices. The quoted prices are based on observable transactions in less active markets for our debt or similar instruments. The fair values of the financing obligations associated with our Dalton lateral and Atlantic Sunrise projects, which are included within long-term debt, were determined using an income approach (see Note 15 – Debt and Banking Arrangements).

Guarantees: Guarantees primarily consist of a guarantee we have provided in the event of nonpayment by our previously owned communications subsidiary, Williams Communications Group (WilTel), on a lease performance obligation that extends through 2042. Guarantees also include an indemnification related to a disposed operation.

To estimate the fair value of the WilTel guarantee, an estimated default rate is applied to the sum of the future contractual lease payments using an income approach. The estimated default rate is determined by obtaining the average cumulative issuer-weighted corporate default rate based on the credit rating of WilTel’s current owner and the term of the underlying obligation. The default rate is published by Moody’s Investors Service. The carrying value of the WilTel guarantee is reported in Accrued liabilities in the Consolidated Balance Sheet. The maximum potential undiscounted exposure is approximately $28 million at December 31, 2019. Our exposure declines systematically through the remaining term of WilTel’s obligation.

The fair value of the guarantee associated with the indemnification related to a disposed operation was estimated using an income approach that considered probability-weighted scenarios of potential levels of future performance. The terms of the indemnification do not limit the maximum potential future payments associated with the guarantee. The carrying value of this guarantee is reported in Regulatory liabilities, deferred income, and other in the Consolidated Balance Sheet.

We are required by our revolving credit agreement to indemnify lenders for certain taxes required to be withheld from payments due to the lenders and for certain tax payments made by the lenders. The maximum potential amount of future payments under these indemnifications is based on the related borrowings and such future payments cannot

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currently be determined. These indemnifications generally continue indefinitely unless limited by the underlying tax regulations and have no carrying value. We have never been called upon to perform under these indemnifications and have no current expectation of a future claim.

Nonrecurring fair value measurements

The following table presents impairments of assets and equity-method investments associated with certain nonrecurring fair value measurements within Level 3 of the fair value hierarchy, except as specifically noted. Impairments of equity-method investments are reported in Other investing income (loss) – net in the Consolidated Statement of Operations.

										Impairments
										Year Ended December 31,
		Segment		Date of Measurement		Fair Value				2019				2018				2017
						(Millions)
Impairment of certain assets:
Certain pipeline project (1)		Atlantic-Gulf		December 31, 2019		$	22			$	354
Certain gathering assets (2)		West		December 31, 2019		25				20
Certain gathering assets (2)		West		June 30, 2019		40				59
Certain idle gathering assets (3)		West		March 31, 2019		—				12
Certain gathering assets (4)		West		December 31, 2018		470								$	1,849
Certain idle pipeline assets (5)		Other		June 30, 2018		25								66
Certain gathering assets (6)		West		September 30, 2017		439												$	1,019
Certain gathering assets (7)		Northeast G&P		September 30, 2017		21												115
Certain NGL pipeline (8)		Other		September 30, 2017		32												68
Certain olefins pipeline project (9)		Other		June 30, 2017		18												23
Other impairments and write-downs (10)										19				—				23
Impairment of certain assets										$	464			$	1,915			$	1,248
Impairment of equity-method investments:
Laurel Mountain (11)		Northeast G&P		September 30, 2019		$	242			$	79
Appalachia Midstream Investments (12)		Northeast G&P		September 30, 2019		102				17
Pennant (13)		Northeast G&P		August 31, 2019		11				17
UEOM (14)		Northeast G&P		March 17, 2019		1,210				74
UEOM (14)		Northeast G&P		December 31, 2018		1,293								$	32
Other										(1		)
Impairment of equity-method investments										$	186			$	32

______________

(1)	Relates to the Constitution development project. The estimated fair value of the Property, plant, and equipment – net was based on probability-weighted third-party quotes. See Note 4 – Variable Interest Entities for further discussion.

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(2)

Relates to a gas gathering system in the Eagle Ford region with expected declines in asset utilization and possible idling of the gathering system. We designated these operations as held for sale, included in Other current assets and deferred charges, as of December 31, 2019. As a result, we measured the fair value of the disposal group using the expected sales price under a contract with a third party. These inputs resulted in a fair value measurement within Level 2 of the fair value hierarchy. The estimated fair value of the Property, plant, and equipment – net at June 30, 2019, was determined using a market approach, which incorporated indications of interest from third parties.

(3)	Reflects impairment of Property, plant, and equipment – net that is no longer in use for which the fair value was determined to be lower than the carrying value.

(4)

Relates to our gathering operations in the Barnett Shale. Certain of our contractual gathering rates, primarily those in the Barnett Shale, are based on a percentage of the New York Mercantile Exchange (NYMEX) natural gas prices. During the fourth quarter of 2018, we determined there was a sustained decline in the forward price curves for natural gas. During this same period, a large producer customer in the Barnett Shale removed their remaining drilling rig. These factors gave rise to an impairment evaluation of these assets, which incorporated management’s projections of future drilling activity and gathering rates, taking into consideration the information previously noted as well as recently available information regarding producer drilling cost assumptions in the basin. The resulting estimate of future undiscounted cash flows was less than our carrying value, necessitating the estimation of the fair value of the Property, plant, and equipment – net and Intangible assets – net of accumulated amortization. To arrive at the fair value, we utilized an income approach with a discount rate of 8.5 percent, reflecting an estimated cost of capital and risks associated with the underlying assets.

(5)

Relates to certain idle pipelines. The estimated fair value of the Property, plant, and equipment – net was determined by a market approach incorporating information derived from bids received for these assets, which we marketed for sale together with certain other assets. These inputs resulted in a fair value measurement within Level 2 of the fair value hierarchy. We sold these assets in the fourth quarter of 2018. (See Note 3 – Acquisitions and Divestitures.)

(6)

Relates to certain gathering operations in the Mid-Continent region. During the third quarter of 2017, we received solicitations and engaged in negotiations for the sale of certain of these assets which led to our impairment evaluation. The estimated fair value of the Property, plant, and equipment – net and Intangible assets – net of accumulated amortization was determined using an income approach and incorporated market inputs based on ongoing negotiations for a potential sale of a portion of the underlying assets. For the income approach, we utilized a discount rate of 10.2 percent, reflecting an estimated cost of capital and risks associated with the underlying assets.

(7)

Relates to certain gathering operations in the Marcellus South region resulting from an anticipated decline in future volumes following a third-quarter 2017 shut-in by the primary producer. The estimated fair value of the Property, plant, and equipment – net and Intangible assets – net of accumulated amortization was determined by the income approach utilizing a discount rate of 11.1 percent, reflecting an estimated cost of capital and risks associated with the underlying assets.

(8)

Relates to an NGL pipeline near the Houston Ship Channel region which we anticipated would be underutilized for the foreseeable future. The estimated fair value of the Property, plant, and equipment – net was primarily determined by using a market approach based on our analysis of observable inputs in the principal market. We sold these assets in the fourth quarter of 2018. (See Note 3 – Acquisitions and Divestitures.)

(9)	Relates primarily to project development costs associated with an olefins pipeline project in the Gulf Coast region, where we consider the likelihood of completion to be remote. The estimated fair value of the remaining Property, plant, and equipment – net considered a market approach based on our analysis of observable inputs in the principal

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market, as well as an estimate of replacement cost. We sold these assets in the fourth quarter of 2018. (See Note 3 – Acquisitions and Divestitures.)

(10)	Reflects multiple individually insignificant impairments and write-downs of other certain assets that may no longer be in use or are surplus in nature for which the fair value was determined to be lower than the carrying value.

(11)	Relates to a gas gathering system in the Marcellus region that was adversely impacted by lower sustained forward natural gas price expectations and changes in expected producer activity. The estimated fair value was determined using an income approach. We utilized a discount rate of 10.2 percent in our analysis.

(12)	Relates to a certain gathering system held in Appalachia Midstream Investments that was adversely impacted by changes in the timing of expected producer activity. The estimated fair value was determined using an income approach. We utilized a discount rate of 9.0 percent in our analysis.

(13)	The estimated fair value of Pennant Midstream, LLC (“Pennant”) was determined by a market approach based on recent observable third-party transactions. These inputs resulted in a fair value measurement within Level 2 of the fair value hierarchy.

(14)

The estimated fair value at March 17, 2019, was determined by a market approach based on the transaction price for the purchase of the remaining interest in UEOM as finalized just prior to the signing and closing of the acquisition in March 2019 (see Note 3 – Acquisitions and Divestitures). These inputs resulted in a fair value measurement within Level 2 of the fair value hierarchy. The estimated fair value at December 31, 2018, was determined by a market approach based on our analysis of inputs in the principal market.

Concentration of Credit Risk

The following table summarizes concentration of receivables, net of allowances:

	December 31,
	2019				2018
	(Millions)
NGLs, natural gas, and related products and services	$	613			$	626
Transportation of natural gas and related products	277				232
Accounts Receivable related to revenues from contracts with customers	890				858
Other	106				134
Trade accounts and other receivables	$	996			$	992

Customers include producers, distribution companies, industrial users, gas marketers, and pipelines primarily located in the continental United States. As a general policy, collateral is not required for receivables, but customers’ financial condition and credit worthiness are evaluated regularly. Based upon this evaluation, we may obtain collateral to support receivables.

In 2019, 2018, and 2017, Chesapeake Energy Corporation, and its affiliates, a customer currently primarily within our West segment, accounted for approximately 6 percent, 8 percent, and 10 percent, respectively, of our consolidated revenues, and as of December 31, 2019, accounted for $78 million of the consolidated Trade accounts and other receivables balance.

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Note 19 – Contingent Liabilities and Commitments

Reporting of Natural Gas-Related Information to Trade Publications

Direct and indirect purchasers of natural gas in various states filed individual and class actions against us, our former affiliate WPX Energy, Inc. (WPX) and its subsidiaries, and others alleging the manipulation of published gas price indices and seeking unspecified amounts of damages. Such actions were transferred to the Nevada federal district court for consolidation of discovery and pre-trial issues. We have agreed to indemnify WPX and its subsidiaries related to this matter.

In the individual action, filed by Farmland Industries Inc. (Farmland), the court issued an order on May 24, 2016, granting one of our co-defendant’s motion for summary judgment as to Farmland’s claims. On January 5, 2017, the court extended such ruling to us, entering final judgment in our favor. Farmland appealed. On March 27, 2018, the appellate court reversed the district court’s grant of summary judgment, and on April 10, 2018, the defendants filed a petition for rehearing with the appellate court, which was denied on May 9, 2018. The case was remanded to the Nevada federal district court and subsequently has been remanded to its originally filed court, the Kansas federal district court.

In the putative class actions, on March 30, 2017, the court issued an order denying the plaintiffs’ motions for class certification. On June 13, 2017, the United States Court of Appeals for the Ninth Circuit granted the plaintiffs’ petition for permission to appeal the order. On August 6, 2018, the Ninth Circuit reversed the order denying class certification and remanded the case to the Nevada federal district court.

We reached an agreement to settle two of the actions, and on April 22, 2019, the Nevada federal district court preliminarily approved the settlements, which are on behalf of Kansas and Missouri class members. The final fairness hearing on the settlement occurred August 5, 2019, and a final judgment of dismissal with prejudice was entered the same day.

Two putative class actions remain unresolved, and they have been remanded to their originally filed court, the Wisconsin federal district court.

Because of the uncertainty around the remaining pending unresolved issues, we cannot reasonably estimate a range of potential exposure at this time. However, it is reasonably possible that the ultimate resolution of these actions and our related indemnification obligation could result in a potential loss that may be material to our results of operations. In connection with this indemnification, we have an accrued liability balance associated with this matter, and as a result, have exposure to future developments.

Alaska Refinery Contamination Litigation

We are involved in litigation arising from our ownership and operation of the North Pole Refinery in North Pole, Alaska, from 1980 until 2004, through our wholly owned subsidiaries, Williams Alaska Petroleum Inc. (WAPI) and MAPCO Inc. We sold the refinery to Flint Hills Resources Alaska, LLC (FHRA), a subsidiary of Koch Industries, Inc., in 2004. The litigation involves three cases, with filing dates ranging from 2010 to 2014. The actions primarily arise from sulfolane contamination allegedly emanating from the refinery. A putative class action lawsuit was filed by James West in 2010 naming us, WAPI, and FHRA as defendants. We and FHRA filed claims against each other seeking, among other things, contractual indemnification alleging that the other party caused the sulfolane contamination. In 2011, we and FHRA settled the claim with James West. Certain claims by FHRA against us were resolved by the Alaska Supreme Court in our favor. FHRA’s claims against us for contractual indemnification and statutory claims for damages related to off-site sulfolane were remanded to the Alaska Superior Court. The State of Alaska filed its action in March 2014, seeking damages. The City of North Pole (North Pole) filed its lawsuit in November 2014, seeking past and future damages, as well as punitive damages. Both we and WAPI asserted counterclaims against the State of Alaska and North Pole, and cross-claims against FHRA. FHRA has also filed cross-claims against us.

The underlying factual basis and claims in the cases are similar and may duplicate exposure. As such, in February 2017, the three cases were consolidated into one action in state court containing the remaining claims from the James

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West case and those of the State of Alaska and North Pole. The State of Alaska later announced the discovery of additional contaminants per- and polyfluoralkyl (PFOS and PFOA) offsite of the refinery, and the Court permitted the State of Alaska to amend its complaint to add a claim for offsite PFOS/PFOA contamination. The Court subsequently remanded the offsite PFOS/PFOA claims to the Alaska Department of Environmental Conservation for investigation and stayed the claims pending their potential resolution at the administrative agency. Several trial dates encompassing all three cases have been scheduled and stricken. In the summer of 2019, the Court deconsolidated the cases for purposes of trial. A bench trial on all claims except North Pole’s claims began in October 2019.

In January 2020, the Alaska Superior Court issued its Memorandum of Decision finding in favor of the State of Alaska and FHRA, with the total incurred and potential future damages estimated to be $86 million. The Court did not award natural resource damages to the State of Alaska and also found that FHRA is not entitled to contractual indemnification from us because FHRA contributed to the sulfolane contamination. A final judgment has not been entered in the case. We expect to appeal the decision. We have recorded an additional charge in the fourth quarter of 2019, reported within Income (loss) from discontinued operations in the Consolidated Statement of Operations, adjusting our accrued liability to our estimate of the probable loss. It is reasonably possible that we may not be successful on appeal and could ultimately pay up to the amount of judgment.

Royalty Matters

Certain of our customers, including one major customer, have been named in various lawsuits alleging underpayment of royalties and claiming, among other things, violations of anti-trust laws and the Racketeer Influenced and Corrupt Organizations Act. We have also been named as a defendant in certain of these cases filed in Pennsylvania based on allegations that we improperly participated with that major customer in causing the alleged royalty underpayments. We believe that the claims asserted are subject to indemnity obligations owed to us by that major customer. That customer has reached a tentative settlement to resolve substantially all Pennsylvania royalty cases pending, which settlement would apply to both the customer and us. The settlement as reported would not require any contribution from us.

Litigation Against Energy Transfer and Related Parties

On April 6, 2016, we filed suit in Delaware Chancery Court against Energy Transfer Equity, L.P. (Energy Transfer) and LE GP, LLC (the general partner for Energy Transfer) alleging willful and material breaches of the Agreement and Plan of Merger (ETE Merger Agreement) with Energy Transfer resulting from the private offering by Energy Transfer on March 8, 2016, of Series A Convertible Preferred Units (Special Offering) to certain Energy Transfer insiders and other accredited investors. The suit seeks, among other things, an injunction ordering the defendants to unwind the Special Offering and to specifically perform their obligations under the ETE Merger Agreement. On April 19, 2016, we filed an amended complaint seeking the same relief. On May 3, 2016, Energy Transfer and LE GP, LLC filed an answer and counterclaims.

On May 13, 2016, we filed a separate complaint in Delaware Chancery Court against Energy Transfer, LE GP, LLC, and the other Energy Transfer affiliates that are parties to the ETE Merger Agreement, alleging material breaches of the ETE Merger Agreement for failing to cooperate and use necessary efforts to obtain a tax opinion required under the ETE Merger Agreement (Tax Opinion) and for otherwise failing to use necessary efforts to consummate the merger under the ETE Merger Agreement wherein we would be merged with and into the newly formed Energy Transfer Corp LP (ETC) (ETC Merger). The suit sought, among other things, a declaratory judgment and injunction preventing Energy Transfer from terminating or otherwise avoiding its obligations under the ETE Merger Agreement due to any failure to obtain the Tax Opinion.

The Court of Chancery coordinated the Special Offering and Tax Opinion suits. On May 20, 2016, the Energy Transfer defendants filed amended affirmative defenses and verified counterclaims in the Special Offering and Tax Opinion suits, alleging certain breaches of the ETE Merger Agreement by us and seeking, among other things, a declaration that we were not entitled to specific performance, that Energy Transfer could terminate the ETC Merger, and that Energy Transfer is entitled to a $1.48 billion termination fee. On June 24, 2016, following a two-day trial, the

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court issued a Memorandum Opinion and Order denying our requested relief in the Tax Opinion suit. The court did not rule on the substance of our claims related to the Special Offering or on the substance of Energy Transfer’s counterclaims. On June 27, 2016, we filed an appeal of the court’s decision with the Supreme Court of Delaware, seeking reversal and remand to pursue damages. On March 23, 2017, the Supreme Court of Delaware affirmed the Court of Chancery’s ruling. On March 30, 2017, we filed a motion for reargument with the Supreme Court of Delaware, which was denied on April 5, 2017.

On September 16, 2016, we filed an amended complaint with the Court of Chancery seeking damages for breaches of the ETE Merger Agreement by defendants.  On September 23, 2016, Energy Transfer filed a second amended and supplemental affirmative defenses and verified counterclaim with the Court of Chancery seeking, among other things, payment of the $1.48 billion termination fee due to our alleged breaches of the ETE Merger Agreement. On December 1, 2017, the court granted our motion to dismiss certain of Energy Transfer’s counterclaims, including its claim seeking payment of the $1.48 billion termination fee. On December 8, 2017, Energy Transfer filed a motion for reargument, which the Court of Chancery denied on April 16, 2018. The Court of Chancery previously scheduled trial for May 20 through May 24, 2019; the court struck the trial setting and has re-scheduled trial for June 8 through June 11 and June 15, 2020.

Former Olefins Business

SABIC Petrochemicals, the other interest owner in our former Geismar, Louisiana, olefins facility we sold in July 2017, is seeking recovery from us for losses it allegedly suffered, including its share of personal injury settlements in which it was a co-defendant, as well as amounts related to lost income, defense costs, and property damage associated with an explosion and fire at the plant in June 2013. Due to the complexity of the various claims and available defenses, we are unable to reliably estimate any reasonably possible losses at this time. Trial began on October 14, 2019, as scheduled, but on October 21, 2019, the Court declared a mistrial due to the conduct of an officer of SABIC Petrochemicals and SABIC Petrochemicals’ expert witness. No new trial date has been set. We believe that certain losses incurred arising directly from the explosion and fire will be covered by our general liability policy and any uninsured losses are not expected to be material.

Other

On August 31, 2018, Transco submitted to the FERC a general rate filing principally designed to recover increased costs and to comply with the terms of the settlement in its prior rate proceeding. The new rates became effective March 1, 2019, subject to refund and the outcome of a hearing. In October 2019, we reached an agreement on the terms of a settlement with the participants that would resolve all issues in the rate case without the need for a hearing, and on December 31, 2019, we filed a formal stipulation and agreement with the FERC setting forth such terms of settlement. We anticipate FERC approval of the stipulation and agreement in the second quarter of 2020. As of December 31, 2019, we have provided a $189 million reserve for rate refunds related to increased rates collected since March 2019, which we believe is adequate for any refunds that may be required.

Environmental Matters

We are a participant in certain environmental activities in various stages including assessment studies, cleanup operations, and/or remedial processes at certain sites, some of which we currently do not own. We are monitoring these sites in a coordinated effort with other potentially responsible parties, the U.S. Environmental Protection Agency (EPA), or other governmental authorities. We are jointly and severally liable along with unrelated third parties in some of these activities and solely responsible in others. Certain of our subsidiaries have been identified as potentially responsible parties at various Superfund and state waste disposal sites. In addition, these subsidiaries have incurred, or are alleged to have incurred, various other hazardous materials removal or remediation obligations under environmental laws. As of December 31, 2019, we have accrued liabilities totaling $31 million for these matters, as discussed below. Estimates of the most likely costs of cleanup are generally based on completed assessment studies, preliminary results of studies, or our experience with other similar cleanup operations. At December 31, 2019, certain assessment studies were still

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in process for which the ultimate outcome may yield different estimates of most likely costs. 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.

Continuing operations

Our interstate gas pipelines are involved in remediation activities related to certain facilities and locations for polychlorinated biphenyls, mercury, and other hazardous substances. These activities have involved the EPA and various state environmental authorities, resulting in our identification as a potentially responsible party at various Superfund waste sites. At December 31, 2019, we have accrued liabilities of $4 million for these costs. We expect that these costs will be recoverable through rates.

We also accrue environmental remediation costs for natural gas underground storage facilities, primarily related to soil and groundwater contamination. At December 31, 2019, we have accrued liabilities totaling $7 million for these costs.

Former operations

We have potential obligations in connection with assets and businesses we no longer operate. These potential obligations include remediation activities at the direction of federal and state environmental authorities and the indemnification of the purchasers of certain of these assets and businesses for environmental and other liabilities existing at the time the sale was consummated. Our responsibilities relate to the operations of the assets and businesses described below.

•	Former agricultural fertilizer and chemical operations and former retail petroleum and refining operations;

•	Former petroleum products and natural gas pipelines;

•	Former petroleum refining facilities;

•	Former exploration and production and mining operations;

•	Former electricity and natural gas marketing and trading operations.

At December 31, 2019, we have accrued environmental liabilities of $20 million related to these matters.

Other Divestiture Indemnifications

Pursuant to various purchase and sale agreements relating to divested businesses and assets, we have indemnified certain purchasers against liabilities that they may incur with respect to the businesses and assets acquired from us. The indemnities provided to the purchasers are customary in sale transactions and are contingent upon the purchasers

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incurring liabilities that are not otherwise recoverable from third parties. The indemnities generally relate to breach of warranties, tax, historic litigation, personal injury, property damage, environmental matters, right of way, and other representations that we have provided.

At December 31, 2019, other than as previously disclosed, we are not aware of any material claims against us involving the indemnities; thus, we do not expect any of the indemnities provided pursuant to the sales agreements to have a material impact on our future financial position. Any claim for indemnity brought against us in the future may have a material adverse effect on our results of operations in the period in which the claim is made.

In addition to the foregoing, various other proceedings are pending against us which are incidental to our operations, none of which are expected to be material to our expected future annual results of operations, liquidity, and financial position.

Summary

We have disclosed our estimated range of reasonably possible losses for certain matters above, as well as all significant matters for which we are unable to reasonably estimate a range of possible loss. We estimate that for all other matters for which we are able to reasonably estimate a range of loss, our aggregate reasonably possible losses beyond amounts accrued are immaterial to our expected future annual results of operations, liquidity, and financial position. These calculations have been made without consideration of any potential recovery from third parties.

Commitments

Commitments for construction and acquisition of property, plant, and equipment are approximately $206 million at December 31, 2019.

Note 20 – Segment Disclosures

Our reportable segments are Atlantic-Gulf, Northeast G&P, and West. All remaining business activities are included in Other. (See Note 1 – General, Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies.)

Performance Measurement

We evaluate segment operating performance based upon Modified EBITDA (earnings before interest, taxes, depreciation, and amortization). This measure represents the basis of our internal financial reporting and is the primary performance measure used by our chief operating decision maker in measuring performance and allocating resources among our reportable segments. Intersegment revenues primarily represent the sale of NGLs from our natural gas processing plants to our marketing business.

We define Modified EBITDA as follows:

•Net income (loss) before:

◦Income (loss) from discontinued operations;

◦Provision (benefit) for income taxes;

◦Interest incurred, net of interest capitalized;

◦Equity earnings (losses);

◦Other investing income (loss) – net;

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◦Depreciation and amortization expenses;

◦Accretion expense associated with asset retirement obligations for nonregulated operations.

•	This measure is further adjusted to include our proportionate share (based on ownership interest) of Modified EBITDA from our equity-method investments calculated consistently with the definition described above.

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The following table reflects the reconciliation of Segment revenues to Total revenues as reported in the Consolidated Statement of Operations and Other financial information:

	Atlantic-Gulf				Northeast G&P				West				Other				Eliminations				Total
	(Millions)
2019
Segment revenues:
Service revenues
External	$	2,812			$	1,291			$	1,813			$	17			$	—			$	5,933
Internal	49				47				—				13				(109		)		—
Total service revenues	2,861				1,338				1,813				30				(109		)		5,933
Total service revenues – commodity consideration	41				12				150				—				—				203
Product sales
External	217				115				1,733				—				—				2,065
Internal	71				35				64				—				(170		)		—
Total product sales	288				150				1,797				—				(170		)		2,065
Total revenues	$	3,190			$	1,500			$	3,760			$	30			$	(279	)		$	8,201
Other financial information:
Additions to long-lived assets	$	1,179			$	1,245			$	466			$	21			$	—			$	2,911
Proportional Modified EBITDA of equity-method investments	177				454				115				—				—				746
2018
Segment revenues:
Service revenues
External	$	2,460			$	935			$	2,085			$	22			$	—			$	5,502
Internal	49				41				—				12				(102		)		—
Total service revenues	2,509				976				2,085				34				(102		)		5,502
Total service revenues – commodity consideration	59				20				321				—				—				400
Product sales
External	174				245				2,365				—				—				2,784
Internal	261				42				83				—				(386		)		—
Total product sales	435				287				2,448				—				(386		)		2,784
Total revenues	$	3,003			$	1,283			$	4,854			$	34			$	(488	)		$	8,686
Other financial information:
Additions to long-lived assets	$	2,297			$	477			$	361			$	36			$	—			$	3,171
Proportional Modified EBITDA of equity-method investments	183				493				94				—				—				770
2017
Segment revenues:
Service revenues
External	$	2,202			$	837			$	2,246			$	27			$	—			$	5,312
Internal	37				35				—				11				(83		)		—
Total service revenues	2,239				872				2,246				38				(83		)		5,312
Product sales
External	257				264				1,840				358				—				2,719
Internal	227				27				173				8				(435		)		—
Total product sales	484				291				2,013				366				(435		)		2,719
Total revenues	$	2,723			$	1,163			$	4,259			$	404			$	(518	)		$	8,031
Other financial information:
Additions to long-lived assets	$	2,001			$	460			$	321			$	32			$	—			$	2,814
Proportional Modified EBITDA of equity-method investments	264				452				79				—				—				795

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The following table reflects the reconciliation of Modified EBITDA to Net income (loss) as reported in the Consolidated Statement of Operations:

							Year Ended December 31,
							2019				2018				2017
							(Millions)
Modified EBITDA by segment:
Atlantic-Gulf							$	1,895			$	2,023			$	1,238
Northeast G&P							1,314				1,086				819
West							1,232				308				412
Other							6				(29		)		997
							4,447				3,388				3,466
Accretion expense associated with asset retirement obligations for nonregulated operations							(33		)		(33		)		(33		)
Depreciation and amortization expenses							(1,714		)		(1,725		)		(1,736		)
Equity earnings (losses)							375				396				434
Other investing income (loss) – net							(79		)		187				282
Proportional Modified EBITDA of equity-method investments							(746		)		(770		)		(795		)
Interest expense							(1,186		)		(1,112		)		(1,083		)
(Provision) benefit for income taxes							(335		)		(138		)		1,974
Income (loss) from discontinued operations							(15		)		—				—
Net income (loss)							$	714			$	193			$	2,509

The following table reflects Total assets and Equity-method investments by reportable segments:

		Total Assets								Equity-Method Investments
		December 31, 2019				December 31, 2018				December 31, 2019				December 31, 2018
		(Millions)
Atlantic-Gulf		$	16,575			$	16,346			$	741			$	776
Northeast G&P		15,399				14,526				3,973				5,319
West		13,487				13,948				1,521				1,726
Other		1,151				849				—				—
Eliminations (1)		(572		)		(367		)		—				—
Total		$	46,040			$	45,302			$	6,235			$	7,821

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(1)	Eliminations primarily relate to the intercompany notes and accounts receivable generated by our cash management program.

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•	$1.849 billion impairment of certain assets in the Barnett Shale region (see Note 18 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk of Notes to Consolidated Financial Statements);

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•	$591 million gain on the sale of our natural gas gathering and processing assets in the Four Corners area of New Mexico and Colorado (see Note 3 – Acquisitions and Divestitures of Notes to Consolidated Financial Statements);

•	$141 million deconsolidation gain associated with our investment in the Brazos Permian II joint venture (see Note 6 – Investing Activities of Notes to Consolidated Financial Statements);

•	$101 million gain on the sale of certain assets and operations located in the Gulf Coast area (see Note 3 – Acquisitions and Divestitures of Notes to Consolidated Financial Statements).

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The Williams Companies, Inc.

Schedule II — Valuation and Qualifying Accounts

					Additions
	Beginning Balance				Charged (Credited) To Costs and Expenses				Other				Deductions				Ending Balance
	(Millions)
2019
Deferred tax asset valuation allowance (1)	$	320			$	(1	)		$	—			$	—			$	319
2018
Deferred tax asset valuation allowance (1)	224				96				—				—				320
2017
Deferred tax asset valuation allowance (1)	334				(110		)		—				—				224

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(1)    Deducted from related assets.

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