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Northeast G&P is comprised of our midstream gathering and processing businesses in the Marcellus Shale region primarily in Pennsylvania, New York, and West Virginia and the Utica Shale region of eastern Ohio, as well as a 66 percent interest in Cardinal (a consolidated entity), a 62 percent equity-method investment in UEOM, 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).

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Atlantic-Gulf is comprised of our interstate natural gas pipeline, Transco, and significant 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 entity), which is a proprietary floating production system, and various petrochemical and feedstock pipelines in the Gulf Coast region, as well as a 50 percent equity-method investment in Gulfstream, a 60 percent equity-method investment in Discovery, and a 41 percent interest in Constitution (a consolidated entity), which is developing a pipeline project (see Note 4 – Variable Interest Entities of Notes to Consolidated Financial Statements).

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West is comprised of our interstate natural gas pipeline, Northwest Pipeline, and our gathering, processing, and treating operations in Colorado, Wyoming, and 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, and a 50 percent equity-method investment in OPPL, a 50 percent interest in Jackalope (an equity-method investment following deconsolidation as of June 30, 2018), a 50 percent equity-method investment in RMM, a 15 percent equity-method investment in Brazos Permian II, and our previously owned 50 percent equity-method investment in the Delaware basin gas gathering system (DBJV) in the Mid-Continent region (see Note 6 – Investing Activities of Notes to Consolidated Financial Statements). West also included our former natural gas gathering and processing assets in the Four Corners area of New Mexico and Colorado (see Note 3 – Divestitures of Notes to Consolidated Financial Statements).

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Other 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 – Divestitures of Notes to Consolidated Financial Statements), and a refinery grade propylene splitter in the Gulf region, which was sold in June 2017. This segment also included our previously owned Canadian assets, which included an oil sands offgas processing plant near Fort McMurray, Alberta, and an NGL/olefin fractionation facility at Redwater, Alberta. In September 2016, these Canadian operations were sold. Other also includes minor business activities that are not operating segments, as well as corporate operations.

(1)	Statistics reflect 100 percent of the assets from our 66 percent ownership of Cardinal gathering system.

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(1)	Excludes volumes associated with equity-method investments.

(2)	Annual average Mbbls/d.

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

(1)	Excludes volumes associated with equity-method investments.

(2)	Annual average Mbbls/d.

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(1)	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.

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(1)	Annual average Mbbls/d.

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•	Ethane, primarily used in the petrochemical industry as a feedstock for ethylene production, one of the basic building blocks for plastics;

•	Propane, used for heating, fuel and as a petrochemical feedstock in the production of ethylene and propylene, another building block for petrochemical-based products such as carpets, packing materials, and molded plastic parts;

•	Normal butane, isobutane, and natural gasoline, primarily used by the refining industry as blending stocks for motor gasoline or as a petrochemical feedstock.

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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. Our customers are entitled to the NGLs produced in connection with this type of processing agreement. A portion of our fee-based processing revenue includes a share of the margins on the NGLs produced. For the year ended December 31, 2018, 74 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. Under these contracts, we retain some or all of the extracted NGLs as compensation for our services. For a keep-whole arrangement we replace the Btu content of the retained NGLs that were extracted during processing with natural gas purchases, also known as shrink replacement gas. For a percent-of-liquids arrangement, we deliver to customers an agreed-upon percentage of the extracted NGLs and retain the remainder. NGLs we retain in connection with these types of processing agreements are referred to as our equity NGL production. Under keep-whole agreements, we have commodity price exposure on the difference between NGL and natural gas prices. For the year ended December 31, 2018, 26 percent of our NGL production volumes were under noncash commodity-based contracts.

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

•	Prices impacting our commodity-based activities;

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

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

•	Disciplined growth in our service areas.

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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.

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

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

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

•	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);

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

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

•	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;

•	Development and rate of adoption of alternative energy sources;

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

•	The impact of existing and future laws and regulations (including but not limited to the Tax Cuts and Jobs Act of 2017), 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 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;

•	Changes in the current geopolitical situation;

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

•	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;

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

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

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

•	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;

•	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.

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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.

•	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;

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•	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.

•	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;

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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;

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•	Operating in a marine environment.

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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;

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•	Accounts and records;

•	Depreciation and amortization policies;

•	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)	Net income (loss) from continuing operations:

•	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, 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;

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For 2014 includes $2.5 billion pre-tax gain recognized as a result of remeasuring to fair value the equity-method investment we held before we acquired a controlling interest in ACMP, $246 million of insurance recoveries related to the 2013 Geismar Incident, and $154 million of cash received related to a contingency settlement. 2014 also includes $78 million of pre-tax equity losses from Bluegrass Pipeline and Moss Lake related primarily to the underlying write-off of previously capitalized project development costs and $76 million of pre-tax acquisition, merger, and transition expenses related to our acquisition of ACMP.

(2)	Stockholders’ equity at December 31:

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Northeast G&P is comprised of our midstream gathering and processing businesses in the Marcellus Shale region primarily in Pennsylvania, New York, and West Virginia and the Utica Shale region of eastern Ohio, as well as a 66 percent interest in Cardinal (a consolidated entity), a 62 percent equity-method investment in UEOM, 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).

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Atlantic-Gulf is comprised of our interstate natural gas pipeline, Transco, and significant 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 entity), which is a proprietary floating production system, and various petrochemical and feedstock pipelines in the Gulf Coast region, as well as a 50 percent equity-method investment in Gulfstream, a 60 percent equity-method investment in Discovery, and a 41 percent interest in Constitution (a consolidated entity), which is developing a pipeline project (see Note 4 – Variable Interest Entities of Notes to Consolidated Financial Statements).

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West is comprised of our interstate natural gas pipeline, Northwest Pipeline, and our gathering, processing, and treating operations in Colorado, Wyoming, and 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, and a 50 percent equity-method investment in OPPL, a 50 percent interest in Jackalope (an equity-method investment following deconsolidation as of June 30, 2018), a 50 percent equity-method investment in RMM, a 15 percent equity-method investment in Brazos Permian II, and our previously owned 50 percent equity-method investment in the Delaware basin gas gathering system (DBJV) in the Mid-

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Other 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 – Divestitures of Notes to Consolidated Financial Statements), and a refinery grade propylene splitter in the Gulf region, which was sold in June 2017. This segment also included our previously owned Canadian assets, which included an oil sands offgas processing plant near Fort McMurray, Alberta, and an NGL/olefin fractionation facility at Redwater, Alberta. In September 2016, these Canadian operations were sold. Other also includes minor business activities that are not operating segments, as well as corporate operations.

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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;

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

•	Counterparty credit and performance risk;

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

•	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 downturn, 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 $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 $38 million increase in gathering fee revenue at Susquehanna Supply Hub driven by 11 percent higher gathered volumes reflecting increased customer production;

•	A $23 million increase in fee revenue at Ohio Valley Midstream reflecting the absence of shut-in volumes from the first half of 2016, as well as new production coming online;

•	A $56 million decrease in Utica gathering fee revenues primarily due to 14 percent lower gathered volumes driven by natural declines in the wet gas areas, partially offset by higher volumes from new development in the dry gas areas.

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•	A $90 million decrease in commodity marketing revenues driven by a $149 million decrease in crude oil revenues 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 revenues primarily reflecting 20 percent higher non-ethane prices;

•	A $14 million decrease in revenues associated with our equity NGLs, as further described below as part of our commodity product 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 $135 million increase in Transco’s natural gas transportation fee revenues primarily due to a $150 million increase associated with expansion projects placed in-service in 2016 and 2017, partially offset by lower volume-based transportation services revenues;

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A $103 million increase in eastern Gulf Coast region fee revenues primarily related to the impact of new volumes at Gulfstar One related to the Gunflint expansion placed in-service in the third quarter of 2016, the absence of the temporary shut-down and subsequent ramp-up of Gulfstar One in the second and third quarters of 2016 to tie-in Gunflint, and the absence of producers’ operational issues in the Tubular Bells field during the first quarter of 2016, partially offset by lower volumes as a result of a temporary increase in 2016 due to disrupted operations of a competitor;

•	A $15 million increase in Transco’s storage revenue primarily related to the absence of an accrual for potential refunds associated with a ruling received in certain rate case litigation in 2016;

•	A $15 million decrease in western Gulf Coast region fee revenues due to lower volumes primarily associated with producer maintenance.

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A $31 million increase in NGL and crude oil marketing revenues primarily due to a $72 million increase driven by higher prices, partially offset by a $41 million decrease driven by lower volumes. Average realized non-ethane prices were 47 percent higher and average realized crude prices were 18 percent higher. Non-ethane volumes were 16 percent lower and crude volumes were 13 percent lower driven by shut-ins of certain wells behind Devils Tower as a result of production issues and temporary hurricane-related shut-ins. (Increases in marketing revenues are substantially offset by higher Product costs);

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•	A $12 million increase in system management gas sales from Transco. System management gas sales are offset in Product costs and, therefore, have no impact on Modified EBITDA;

•	A $5 million decrease in revenues associated with our equity NGLs due to a $19 million decrease driven by lower volumes, partially offset by a $14 million increase driven by higher prices. Realized non-ethane prices increased by 32 percent. Non-ethane volumes decreased by 31 percent primarily as a result of a temporary increase in 2016 due to disrupted operations of a competitor.

•	A $28 million increase in marketing purchases (more than offset in Product sales);

•	A $12 million increase in system management gas costs (offset in Product sales);

•	An $8 million decrease in natural gas purchases associated with the production of equity NGLs primarily due to lower volumes.

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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;

•	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.

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•	A $373 million increase in marketing revenues 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 associated with sales of our equity NGLs, as further described below as part of our commodity product 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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A $79 million decrease related to net lower gathering rates, primarily in the Barnett Shale area primarily due to the fourth quarter 2016 contract restructuring, as well as lower rates recognized in the Niobrara, Eagle Ford Shale, and Haynesville Shale regions. These rate decreases are offset by higher commodity-based fee revenues in the Piceance area primarily due to higher per-unit NGL margins and higher rates in the Wamsutter area as a result of renegotiated rates in conjunction with infrastructure expansions. Rates recognized in the Niobrara region represent a portion of the total contractual rate that is received, with the difference reflected as deferred revenue;

•	A $34 million decrease driven by lower volumes in most gathering and processing regions primarily as a result of natural declines and more extreme weather conditions in the Rocky Mountains in the first quarter of 2017, partially offset by higher volumes in the Haynesville Shale region as a result of increased drilling in certain areas;

•	A $39 million increase related to the rate of amortization of deferred revenue associated with the up-front cash payment received in conjunction with the fourth quarter 2016 Barnett Shale contract restructuring.

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A $532 million increase in marketing revenues primarily due to a $450 million increase driven by higher prices and an $82 million increase driven by higher volumes. The average non-ethane per-unit sales price increased by 43 percent, the average ethane per-unit sales prices increased by 30 percent, and the average natural gas per-unit sales price increased by 13 percent. Ethane and non-ethane sales volumes were 28 percent and six percent higher, respectively, partially offset by 17 percent lower natural gas sales volumes. (Higher marketing sales revenues are substantially offset by higher Product costs);

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A $72 million increase in revenues associated with our equity NGLs primarily due to an $80 million increase driven by higher prices, partially offset by an $8 million decrease driven by lower volumes. Realized non-ethane prices increased by 42 percent and realized ethane prices increased by 46 percent. Non-ethane volumes decreased by six percent primarily due to natural declines and to severe winter conditions in the first quarter of 2017;

•	A $24 million increase in other product sales related to certain fabricated equipment sales to affiliates (more than offset by higher other Product costs).

•	A $529 million increase in marketing purchases (more than offset in Product sales);

•	A $30 million increase in natural gas purchases associated with the production of equity NGLs primarily due to a 26 percent increase in per-unit natural gas prices;

•	A $25 million increase in other product costs related to certain fabricated equipment sales to affiliates (offset by higher other Product sales).

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•	The absence of a $1.095 billion gain on the sale of our Geismar Interest in 2017 (see Note 3 – 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) (see Note 15 – Stockholders' Equity of Notes to Consolidated Financial Statements);

•	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 (see Note 1 – General, Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies of Notes to Consolidated Financial Statements);

•	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 17 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk of Notes to Consolidated Financial Statements);

•	A decrease of $62 million for charges reducing 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 (see Note 1 – General, Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies of Notes to Consolidated Financial Statements);

•	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;

•	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 (see Note 3 – Divestitures of Notes to Consolidated Financial Statements).

•	A $1.095 billion gain recognized on the sale of our Geismar Interest in July 2017. (See Note 3 – Divestitures of Notes to Consolidated Financial Statements);

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The absence of the $747 million 2016 impairment of our Canadian operations, partially offset by the $23 million impairment of an olefins pipeline project in the Gulf Coast region in the second quarter of 2017 and the $68 million impairment of a certain NGL pipeline asset in the third quarter of 2017 (see Note 17 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk of Notes to Consolidated Financial Statements);

•	The absence of $61 million of certain project development costs associated with the Canadian PDH facility that we expensed in 2016;

•	A $65 million favorable change in the loss on the sale of our Canadian operations in September 2016;

•	A $38 million decrease in costs related to our evaluation of strategic alternatives;

•	The absence of $32 million of transportation and fractionation fees incurred in 2016 related to the Redwater fractionation facility, which was included in the sale of our Canadian operations in September 2016;

•	A $29 million increase in income associated with an increase in a regulatory asset primarily driven by our increased ownership in WPZ.

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•	A $164 million decrease due to the absence of results from our former Geismar Olefins and RGP Splitter plants subsequent to their sale in July 2017;

•	A $63 million charge reducing 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);

•	A $35 million 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 reduction in revenues associated with an NGL pipeline near the Houston Ship Channel region;

•	The absence of a $10 million gain on the sale of unused pipe in 2016.

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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. Through completion of the WPZ Merger on August 10, 2018, the highest combined amount outstanding under WPZ’s commercial paper program and credit facility and our former credit facility during 2018 was $1.325 billion. In July 2018, we along with Transco and Northwest Pipeline entered into a new unsecured revolving credit agreement with aggregate commitments available of $4.5 billion under the credit facility, which became effective upon completion of the WPZ Merger. The highest amount outstanding under our current commercial paper program and credit facility during 2018 was $886 million. At December 31, 2018, we were in compliance with the financial covenants associated with our credit facility. See Note 14 – Debt, Banking Arrangements, and Leases of Notes to Consolidated Financial Statements for additional information on our credit facility and commercial paper program. Borrowing capacity available under our credit facility as of February 19, 2019, was $4.5 billion.

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

(2)

Includes approximately $480 million in open property, plant, and equipment purchase orders. Includes an estimated $329 million long-term ethane purchase obligation with index-based pricing terms that is reflected in this table at December 31, 2018 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. Includes an estimated $453 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, 2018 prices. Any excess purchased volumes may be sold at comparable market prices. Includes an estimated $211 million long-term mixed NGLs purchase obligation with index-based pricing terms that is reflected in this table at December 31, 2018 prices. Includes an estimated $312 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, 2018 prices. Any excess purchased volumes may be sold at comparable market prices. Includes an estimated $332 million long-term mixed NGLs purchase obligation with index-based pricing terms that is reflected in this table at December 31, 2018 prices. In addition, we have not included certain natural gas life-of-lease contracts for which the future volumes are indeterminable. We have not included commitments, beyond purchase orders, for the acquisition or construction of property, plant, and equipment or expected contributions to our jointly owned investments. (See Company Outlook — Expansion Projects.)

(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 $93 million in 2018 and $90 million in 2017. In 2019, we expect to contribute approximately $69 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 2018, we contributed $80 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 2019, we expect to contribute approximately $60 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

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(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.

(3)	The weighted-average interest rate for our $270 million credit facility borrowing at December 31, 2017 was 3.16 percent.

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*	Accumulated Other Comprehensive Income (Loss)

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•	Determining whether an entity is a variable interest entity (VIE);

•	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;

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•	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.

•	Impairment assessments of investments, property, plant, and equipment, 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;

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

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•	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.

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(1)

Service revenues in our Consolidated Statement of Operations include leasing revenues associated with our headquarters building and management fees that we receive for certain services we provide to operated joint ventures and other investments. The leasing revenues and the management fees do not constitute revenue from contracts with customers. Product sales in our Consolidated Statement of Operations include amounts associated with our derivative contracts that are not within the scope of ASC 606.

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(1)	Includes WPZ, which was a consolidated VIE at December 31, 2017 (see Note 1 – General, Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies).

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

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(1)	Primarily relates to gains and losses incurred on foreign currency transactions and the remeasurement of U.S. dollar-denominated current assets and liabilities within our former Canadian operations (see Note 3 – Divestitures).

•	Service revenues for the year ended December 31, 2016, includes $173 million associated with the amortization of deferred income related to the restructuring of certain gas gathering contracts in the Barnett Shale and Mid-Continent regions within the West segment.

•	Service revenues for the year ended December 31, 2016 were reduced by $15 million related to potential refunds associated with a ruling received in certain rate case litigation within the Atlantic-Gulf segment.

•

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 15 – Stockholders' Equity). Selling, general, and administrative expenses for the year ended December 31, 2018, also includes $20 million for WPZ Merger related costs within the Other segment.

•	Selling, general, and administrative expenses and Operating and maintenance expenses for the year ended December 31, 2017, included $22 million in severance and other related costs within the Other segment. The year ended December 31, 2016, included $42 million in severance and other related costs associated with an

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•

Selling, general, and administrative expenses for the years ended December 31, 2017 and 2016 included $9 million and $47 million, respectively, of costs associated with our evaluation of strategic alternatives within the Other segment. Selling, general, and administrative expenses for the year ended December 31, 2016, also included $61 million of project development costs related to a proposed propane dehydrogenation facility in Alberta, Canada within the Other segment. Beginning in the first quarter of 2016, these costs did not qualify for capitalization.

•

Other income (expense) – net below Operating income (loss) includes $89 million, $71 million, and $66 million for equity AFUDC primarily within the Atlantic-Gulf segment for the years ended December 31, 2018, 2017, and 2016, respectively. Other income (expense) – net below Operating income (loss) also includes $35 million, $52 million, and $23 million for the years ended December 31, 2018, 2017, and 2016, respectively, of income associated with regulatory assets related to the effects of deferred taxes on equity funds used during construction primarily within the Other segment.

•

Other income (expense) – net below Operating income (loss) for the year ended December 31, 2018, includes a $7 million net loss associated with the March 28, 2018, early retirement of $750 million of 4.875 percent senior unsecured notes that were due in 2024. The net loss within the Other segment reflects $34 million in premiums paid, partially offset by $27 million of unamortized premium. The year ended December 31, 2017, included a net gain of $30 million associated with the February 23, 2017, early retirement of $750 million of 6.125 percent senior unsecured notes that were due in 2022 and a net loss of $3 million associated with the July 3, 2017, early retirement of $1.4 billion of 4.875 percent senior unsecured notes that were due in 2023. The net gain for the February 23, 2017, early retirement within the Other segment reflects $53 million of unamortized premium, partially offset by $23 million in premiums paid. The net loss for the July 3, 2017, early retirement within the Other segment reflects $51 million of unamortized premium, offset by $54 million in premiums paid (see Note 14 – Debt, Banking Arrangements, and Leases).

•	Other income (expense) – net below Operating income (loss) includes settlement charge expense related to the program to pay out certain deferred vested pension benefits as follows (see Note 10 – Employee Benefit Plans):

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Other income (expense) – net below Operating income (loss) for the year ended December 31, 2017, included a $102 million charge for regulatory assets associated with the effects of deferred taxes on equity funds used during construction as a result of Tax Reform, comprised of $33 million within the Atlantic-Gulf segment, $6 million within the West segment, and $63 million within the Other segment (see Note 1 – General, Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies).

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(1)

For the years ended December 31, 2018 and December 31, 2016, 2.0 million and 0.6 million weighted-average nonvested restricted stock units, respectively, and 0.5 million and 0.5 million weighted-average stock options, respectively, have been excluded from the computation of diluted earnings (loss) per common share as their inclusion would be antidilutive due to our loss attributable to The Williams Companies, Inc.

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(1)	The weighted-average credit quality rating of the fixed income security portfolio is investment grade with a weighted-average duration of approximately 13 years for 2018 and 12 years for 2017.

(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 10 days 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.

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(1)	Estimated useful life and depreciation rates are presented as of December 31, 2018. Depreciation rates and estimated useful lives for regulated assets are prescribed by the FERC.

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(1)	The decrease in accretion expense in 2018 primarily reflects the absence of a 2017 adjustment associated with obligations identified from certain Transco land agreements.

(2)

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 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 2017 revisions reflect changes in removal cost estimates and decreases in the estimated remaining useful life of certain assets and discount rates used in the annual review process.

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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.

•	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.

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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.

•	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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(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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(1)

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 these assets. 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.

(2)

Relates to certain idle pipelines. The estimated fair value 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 – Divestitures.)

(3)

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 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.

(4)	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 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.

(5)	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 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 – Divestitures.)

(6)

Relates primarily to project development costs associated with an olefins pipeline project in the Gulf Coast region, the likelihood of completion we considered remote. The estimated fair value of the remaining pipe and equipment considered a market approach based on our analysis of observable inputs in the principal market, as well as an estimate of replacement cost. We sold these assets in the fourth quarter of 2018. (See Note 3 – Divestitures.)

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(7)

Relates to our Canadian operations. We designated these operations as held for sale as of June 30, 2016. As a result, we measured the fair value of the disposal group, resulting in an impairment charge. The estimated fair value was determined by a market approach based primarily on inputs received in the marketing process and reflected our estimate of the potential assumed proceeds. We disposed of our Canadian operations through a sale during the third quarter of 2016. (See Note 3 – Divestitures.)

(8)	Relates to certain gathering assets within the Mid-Continent region. The estimated fair value was determined by a market approach based on our analysis of observable inputs in the principal market.

(9)	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.

(10)	Relates to Northeast G&P’s equity-method investment in UEOM. The estimated fair value was determined by a market approach based on our analysis of inputs in the principal market.

(11)

Relates to West’s previously held interest in Ranch Westex and multiple, currently held Appalachia Midstream Investments at Northeast G&P. The historical carrying value of these equity-method investments was initially recorded based on estimated fair value during the third quarter of 2014 in conjunction with the acquisition of ACMP. We estimated the fair value of these Appalachia Midstream Investments using an income approach based on expected future cash flows and appropriate discount rates. The determination of estimated future cash flows involved significant assumptions regarding gathering volumes, rates, and related capital spending. The discount rate utilized for the Appalachia Midstream Investments evaluation was 10.2 percent and reflected an estimated cost of capital as impacted by market conditions and risks associated with the underlying businesses. In addition to utilizing an income approach, we also considered a market approach for certain Appalachia Midstream Investments and Ranch Westex based on an agreement reached in February 2017 to exchange our interests in DBJV and Ranch Westex for additional interests in certain Appalachia Midstream Investments and cash. (See Note 6 – Investing Activities.)

(12)

Relates to West’s previously held interest in DBJV and Northeast G&P’s currently held equity-method investment in Laurel Mountain. Our carrying values in these equity-method investments had been written down to fair value at December 31, 2015. Our first-quarter 2016 analysis reflected higher discount rates for both of these equity-method investments, along with lower natural gas prices for Laurel Mountain. We estimated the fair value of these equity-method investments using an income approach based on expected future cash flows and appropriate discount rates. The determination of estimated future cash flows involved significant assumptions regarding gathering volumes and related capital spending. Discount rates utilized ranged from 13.0 percent to 13.3 percent and reflected increases in the estimated cost of capital, revised estimates of expected future cash flows, and risks associated with the underlying businesses.

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•	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.

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•	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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(1)	Decrease in Other is due primarily to a decreased cash balance.

(2)	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 17 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk of Notes to Consolidated Financial Statements);

•	$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 – Divestitures);

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

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

•	$1.923 billion benefit for income taxes resulting from Tax Reform rate change (see Note 8 – Provision (Benefit) for Income Taxes);

•	$674 million of regulatory charges resulting from Tax Reform and $102 million of charges associated with regulatory asset-related deferred taxes on equity funds used during construction due to Tax Reform (see Note 7 – Other Income and Expenses).

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•	$1.095 billion gain on the sale of Williams Olefins, L.L.C., a wholly owned subsidiary which owned our interest in the Geismar, Louisiana, olefins plant (Geismar Interest) (see Note 3 – Divestitures);

•	$1.210 billion impairment on certain assets (see Note 17 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk).

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