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Williams Partners — comprised of our consolidated master limited partnership, WPZ, which includes gas pipeline and midstream businesses. The gas pipeline business includes interstate natural gas pipelines and pipeline joint project investments. The midstream business provides natural gas gathering, treating, processing and compression services; NGL production, fractionation, storage, marketing and transportation; deepwater production handling and crude oil transportation services; an olefin production business and is comprised of several wholly owned and partially owned subsidiaries and joint project investments.

•	Williams NGL & Petchem Services — comprised of our Texas Belle pipeline and certain other domestic olefins pipeline assets. Prior to September 2016, this reporting segment also included certain Canadian growth projects under development, including a propane dehydrogenation facility and a recently completed liquids extraction plant which were subsequently sold.

•	Other — primarily comprised of corporate operations and our Canadian construction services company.

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

•	Prices impacting 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;

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•	Disciplined growth in core service areas and new step-out areas.

•	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 revenues includes a share of the margins on the NGLs produced. For the year ended December 31, 2016, 69 percent of the domestic NGL production volumes were under fee-based contracts.

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Keep-whole: Under keep-whole contracts, we (1) process natural gas produced by customers, (2) retain some or all of the extracted NGLs as compensation for our services, (3) replace the Btu content of the retained NGLs that were extracted during processing with natural gas purchases, also known as shrink replacement gas, and (4) deliver an equivalent Btu content of natural gas for customers at the plant outlet. NGLs we retain in connection with this type of processing agreement are referred to as our equity NGL production. Under these agreements, we have commodity price exposure on the difference between NGL and natural gas prices. For the year ended December 31, 2016, 26 percent of the domestic NGL production volumes were under keep-whole contracts.

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Percent-of-Liquids: Under percent-of-liquids processing contracts, we (1) process natural gas produced by customers, (2) deliver to customers an agreed-upon percentage of the extracted NGLs, (3) retain a portion of the extracted NGLs as compensation for our services, and (4) deliver natural gas to customers at the plant outlet. Under this type of contract, we are not required to replace the Btu content of the retained NGLs that were extracted during processing, and are therefore only exposed to NGL price movements. NGLs we retain in connection with this type of processing agreement are also referred to as our equity NGL production. For the year ended December 31, 2016, 5 percent of the domestic NGL production volumes were under percent-of-liquids contracts.

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

(2)	Statistics reflect 100 percent of the Beaver Creek assets from our 67 percent ownership in the Marcellus South gathering system.

(3)	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.

(4)	Includes our 50 percent ownership of the Jackalope gathering system.

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(1)	Statistics reflect 100 percent of the assets from our 50 percent ownership of Bucking Horse gas processing facility.

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

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

(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 cash distributions by Williams Partners L.P. (WPZ) with respect to limited partner interests;

•	Levels of dividends to Williams stockholders;

•	Future credit ratings of Williams, WPZ, and their affiliates;

•	Amounts and nature of future capital expenditures;

•	Expansion and growth of our business and operations;

•	Financial condition and liquidity;

•	Business strategy;

•	Cash flow from operations or results of operations;

•	Seasonality of certain business components;

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

•	Demand for our services.

•	Whether WPZ will produce sufficient cash flows to provide the level of cash distributions that we expect;

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

•	Whether WPZ elects to pay expected levels of cash distributions and we elect to pay expected levels of dividends;

•	Whether we will be able to effectively execute our financing plan including the receipt of anticipated levels of proceeds from planned asset sales;

•	Whether we will be able to effectively manage the transition in our board of directors and management as well as successfully execute our business restructuring;

•	Availability of supplies, including lower than anticipated volumes from third parties served by our midstream business, and market demand;

•	Volatility of pricing including the effect of lower than anticipated energy commodity prices and margins;

•	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 other

•	Our ability to successfully expand our facilities and operations;

•	Development of alternative energy sources;

•	Availability of adequate insurance coverage and the impact of operational and developmental hazards and unforeseen interruptions;

•	The impact of existing and future laws, regulations, the regulatory environment, environmental liabilities, and litigation, as well as our ability to obtain permits 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;

•	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;

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

•	Acts of terrorism, including cybersecurity threats and related disruptions;

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

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

•	Domestic and foreign governmental regulations and taxes;

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

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Natural gas, NGL, and olefins 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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•	We cannot control the amount of capital expenditures that we are required to fund with respect to these operations;

•	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.

•	Aging infrastructure and mechanical problems;

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

•	Uncontrolled releases of natural gas (including sour gas), NGLs, olefins products, brine, or industrial chemicals;

•	Collapse or failure of storage caverns;

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•	Operator error;

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

•	Pollution and other environmental risks;

•	Fires, explosions, craterings, and blowouts;

•	Truck and rail loading and unloading;

•	Operating in a marine environment.

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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;

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•	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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•	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;

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•	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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(1)	Revenues for 2014 increased reflecting the consolidation of ACMP beginning in third quarter and new Canadian construction management services.

(2)	Income (loss) from continuing operations:

•	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 pretax 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 pretax 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 pretax acquisition, merger, and transition expenses related to our acquisition of ACMP;

•	For 2013 includes $99 million of deferred income tax expense incurred on undistributed earnings of our foreign operations that are no longer considered permanently reinvested.

(3)	The increases in 2014 reflect assets acquired and debt assumed primarily related to our acquisition of ACMP (see Note 2 – Acquisitions) in third quarter as well as $1.9 billion of related debt issuances and $2.8 billion of debt issuances at WPZ. Additionally, we issued $3.4 billion of equity (see Note 15 – Stockholders' Equity).

(4)	The increases in 2014 and 2013 reflect borrowings under WPZ’s commercial paper program, which was initiated in 2013.

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•	Opposition to infrastructure projects, including the risk of delay in permits needed for our projects;

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

•	Counterparty credit and performance risk, including that of Chesapeake Energy Corporation and its affiliates;

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•	Inability to execute or delay in completing planned asset monetizations;

•	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;

•	Reduced availability of insurance coverage;

•	Lower than expected distributions from WPZ.

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•	A significant or sustained decline in the market value of an investee;

•	Lower than expected cash distributions from investees;

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•	Significant asset impairments or operating losses recognized by investees;

•	Significant delays in or lack of producer development or significant declines in producer volumes in markets served by investees;

•	Significant delays in or failure to complete significant growth projects of investees.

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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 $94 million increase in olefin sales comprised of a $170 million increase from our Geismar plant that returned to service in late March 2015, partially offset by a $76 million decrease from our other olefin operations. The increase at Geismar includes $153 million associated with increased volumes as a result of the plant operating at higher production levels in 2016 than when production resumed in March 2015 following the Geismar Incident and $17 million primarily associated with higher ethylene per-unit sales prices. The decrease in other olefin sales includes a $14 million reduction due to the absence of our former Canadian operations in the fourth quarter of 2016, as well as lower volumes and lower per-unit sales prices within our other olefin operations;

•	A $70 million increase in marketing revenues primarily due to higher NGL and propylene prices and natural gas and crude oil volumes, partially offset by lower NGL volumes and crude oil prices (partially offset in marketing purchases);

•	A $6 million increase in revenues from our equity NGLs due to a $10 million increase associated with higher volumes, partially offset by a $4 million decrease associated with lower NGL prices;

•	A $39 million decrease 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 $39 million decrease in system management gas costs (offset in Product sales);

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A $17 million decrease in olefin feedstock purchases is primarily comprised of $78 million in lower purchases at our other olefins operations, partially offset by $61 million of higher purchases due primarily to increased volumes at our Geismar plant resulting from higher productions levels. The lower costs at our other olefin operations are comprised of $54 million in lower per-unit feedstock costs and $24 million in primarily lower propylene volumes;

•	A $4 million decrease in natural gas purchases associated with the production of equity NGLs reflecting a decrease of $13 million due to lower natural gas prices, partially offset by a $9 million increase associated with higher volumes;

•	Lower costs associated with various other products, primarily condensate;

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•	A $22 million increase in marketing purchases primarily due to the same factors that increased marketing sales (more than offset in marketing revenues). The increase in marketing costs does not reflect the intercompany costs associated with certain gathering and processing services performed by an affiliate.

•	$34 million increase related to the 2016 loss on sale of our Canadian operations;

•	$37 million increase for severance and related costs associated with workforce reductions incurred in the first quarter of 2016 and the organizational realignment in the fourth quarter of 2016;

•	$28 million higher project development costs at Constitution as we discontinued capitalization of development costs related to this project beginning in April 2016;

•	$22 million higher contract services for pipeline testing and general maintenance at Transco;

•	$20 million unfavorable change in foreign currency exchange that primarily relates to losses incurred on foreign currency transactions and the remeasurement of the U.S. dollar-denominated current assets and liabilities within our former Canadian operations;

•	$19 million unfavorable change in AFUDC associated with a decrease in spending on Constitution;

•	The absence of a $14 million gain recognized in second-quarter 2015 resulting from the early retirement of certain debt.

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•	A $1,173 million decrease in marketing revenues primarily associated with lower prices across all products, partially offset by higher non-ethane volumes (more than offset in marketing purchases);

•	A $324 million decrease in revenues from our equity NGLs reflecting a decrease of $365 million due to lower NGL prices, partially offset by a $41 million increase associated with higher NGL volumes;

•	A $41 million decrease in revenues primarily due to lower condensate prices;

•	A $214 million increase in olefin sales primarily due to $298 million in higher sales from our Geismar plant that returned to operation, partially offset by an $84 million decrease from our other olefin operations due to lower sales prices, partially offset by higher volumes across all products, particularly propylene.

•	A $1,219 million decrease in marketing purchases primarily due to a decrease in non-ethane per-unit cost (substantially offset in marketing revenues);

•	A $95 million decrease in the natural gas purchases associated with the production of equity NGLs reflecting a decrease of $126 million due to lower natural gas prices, partially offset by a $31 million increase associated with higher volumes;

•	A $20 million decrease in costs primarily due to lower gas prices;

•	A $98 million increase in olefin feedstock purchases is comprised of $127 million in higher purchases due to increased volumes at our Geismar plant as it returned to operation, partially offset by $29 million in lower other olefin operations feedstock purchases primarily due to lower per-unit feedstock costs, partially offset by higher volumes across most products, particularly propylene.

•	An increase for new expenses associated with operations associated with the acquisition of ACMP;

•	The absence of $154 million of cash received in the fourth quarter of 2014 associated with the resolution of a contingent gain related to claims arising from the purchase of a business in a prior period (see Note 7 – Other Income and Expenses of Notes to Consolidated Financial Statements);

•	A $16 million increase in operating expense due to the Geismar plant returning to operation in 2015;

•	The absence of a $12 million net gain recognized in 2014 related to a partial acreage dedication release.

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•	Expansion of WPZ’s interstate natural gas pipeline system through projects such as Rock Springs to meet the demand of growth markets;

•	Completion of WPZ’s Gulfstar One expansion project to provide production handling and gathering services for the Gunflint oil and gas discovery in the eastern deepwater Gulf of Mexico;

•	WPZ’s restructuring of contracts in the Barnett Shale and Mid-Continent region,which included cash payments to WPZ of $820 million;

•	Sale of our Canadian operations (see Note 3 – Divestiture of Notes to Consolidated Financial Statements).

•	Cash and cash equivalents on hand;

•	Cash generated from operations;

•	Distributions from WPZ;

•	Distributions from our equity-method investees based on our level of ownership;

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•	Use of our credit facility;

•	Cash proceeds from issuances of debt and/or equity securities.

•	Working capital requirements;

•	Maintenance and expansion capital and investment expenditures;

•	Interest on our long-term debt;

•	Repayment of current debt maturities, and additional reductions in WPZ’s debt with funds received as part of the Financial Repositioning;

•	Investment in WPZ as part of the Financial Repositioning (see Note 15 – Stockholders' Equity of Notes to Consolidated Financial Statements);

•	Quarterly dividends to our shareholders.

(1)

The highest amount outstanding under our credit facility during 2016 was $1.224 billion. At December 31, 2016, we were in compliance with the financial covenants associated with this credit facility. See Note 14 – Debt, Banking Arrangements, and Leases of Notes to Consolidated Financial Statements for additional information on our credit facility. Borrowing capacity available under this facility as of February 20, 2017, was $1.265 billion.

(2)	In managing our available liquidity, we do not expect a maximum outstanding amount in excess of the capacity of WPZ’s credit facility inclusive of any outstanding amounts under its commercial paper program. WPZ has $93 million of Commercial paper outstanding at December 31, 2016. The highest amount outstanding under WPZ’s

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

(2)	Includes $750 million of 6.125 percent senior notes due 2022 that WPZ intends to redeem on February 23, 2017 and related interest, presented in the table above according to the original contractual terms.

(3)

Includes approximately $244 million in open property, plant, and equipment purchase orders. Includes an estimated $418 million long-term ethane purchase obligation with index-based pricing terms that is reflected in this table at December 31, 2016 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 resold at comparable prices in the Mont Belvieu market. Includes an estimated $619 million long-term ethane purchase obligation with index-based pricing terms that primarily supplies third parties at their plants and is valued in this table at a price calculated using December 31, 2016 prices. Any excess purchased volumes may be sold at comparable market prices. Includes an estimated $586 million long-term mixed NGLs purchase obligation with index-based pricing terms that is reflected in this table at December 31, 2016 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.)

(4)

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 $72 million in 2016 and $70 million in 2015. In 2017, 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 2016, 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 2017, 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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(5)	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)	Excludes capital leases.

(3)	The weighted-average interest rates for WPZ’s $850 million term loan, and our $775 million credit facility borrowing at December 31, 2016 were 2.50 percent and 2.51 percent, respectively.

(4)	The weighted-average interest rate was 1.06 percent and 0.92 percent at December 31, 2016 and 2015, respectively.

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(5)	The weighted-average interest rates for WPZ’s $1.3 billion credit facility borrowing, WPZ’s $850 million term loan, and our $650 million credit facility borrowing at December 31, 2015 were 1.63 percent, 1.85 percent, and 2.32 percent, respectively.

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•	Determining whether an entity is a 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;

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

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•	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, goodwill, and other identifiable intangible assets;

•	Litigation-related contingencies;

•	Environmental remediation obligations;

•	Realization of deferred income tax assets;

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

•	Asset retirement obligations;

•	Pension and postretirement valuation variables;

•	Acquisition related purchase price allocations.

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•	Write-offs of capitalized project development costs on our discontinued investments in Bluegrass Pipeline Company LLC (Bluegrass) of $67 million and Moss Lake Fractionation LLC and Moss Lake LPG Terminal LLC (collectively referred to as Moss Lake) of $4 million;

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A $7 million equity loss recognized from our interest in ACMP that was accounted for under the equity-method of accounting for the first six months of the year, including $19 million of equity losses associated with certain compensation-related costs at ACMP that were triggered by the acquisition and $30 million noncash amortization of the difference between the cost of our investment and our underlying share of the net assets for the first six months of the year.

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(1)	Includes equity-method investments in multiple gathering systems in the Marcellus Shale with an approximate average 41 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 – Divestiture).

(2)	In November 2014, we settled a claim arising from the resolution of a contingent gain related to claims associated with the purchase of a business in a prior period. Pursuant to the settlement, we received $154 million in cash, all of which was recognized as a gain in the fourth quarter of 2014.

•	Selling, general, and administrative expenses includes $26 million in 2015 and $27 million in 2014 (including $16 million of acquisition costs) primarily related to professional advisory fees within the Williams Partners segment.

•	Selling, general, and administrative expenses includes $9 million in 2015 and $15 million in 2014 of related employee transition costs within the Williams Partners segment and $32 million in 2015 and $10 million in 2014 of general corporate expenses associated with integration and realignment of resources within the Other segment.

•	Operating and maintenance expenses includes $12 million in 2015 and $15 million in 2014 primarily related to employee transition costs within the Williams Partners segment.

•	Interest incurred includes transaction-related financing costs of $2 million in 2015 from the merger and $9 million in 2014 from the acquisition.

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Service revenues 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 Williams Partners segment. Service revenues also includes $58 million, $239 million, and $167 million recognized in the fourth quarter of 2016, 2015, and 2014, respectively, from minimum volume commitment fees in the Barnett Shale and Mid-Continent regions within the Williams Partners segment.

•	Selling, general, and administrative expenses and Operating and maintenance expenses include $42 million in 2016 of severance and other related costs.

•	Other income (expense) – net below Operating income (loss) includes $89 million, $95 million, and $44 million for equity AFUDC for 2016, 2015, and 2014, respectively, primarily within the Williams Partners segment.

•	Other income (expense) – net below Operating income (loss) includes a $14 million gain in 2015 resulting from the early retirement of certain debt within the Williams Partners segment.

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(1)

For the years ended December 31, 2016 and December 31, 2015, 0.6 million and 1.7 million weighted-average nonvested restricted stock units, and 0.5 million and 1.5 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.

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(1)	The weighted-average credit quality rating of the pension assets fixed income security portfolio is investment grade with a weighted-average duration of approximately 8 years for 2016 and 2015.

(2)	The weighted-average credit quality rating of the other postretirement benefit assets fixed income security portfolio is investment grade with a weighted-average duration of approximately 8 years for 2016 and 7 years for 2015.

(3)

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 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, 2016. Depreciation rates and estimated useful lives for regulated assets are prescribed by the FERC.

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(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 2016 revisions reflect changes in removal cost estimates, increases in the estimated remaining useful life of certain assets, and decreases in the inflation rate and discount rates used in the annual review process. The 2015 revisions reflect changes in removal cost estimates and the estimated remaining useful life of assets, a decrease in the inflation rate, and increases in the discount rates used in the annual review process.

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(1)	Presented as long-term debt at December 31, 2015, due to Transco’s intent and ability to refinance.

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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, enter into certain affiliate transactions, make certain distributions during an event of default, make investments, and allow any material change in the nature of its business.

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

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Each time funds are borrowed under our credit facility, the borrower may choose from two methods of calculating interest: a fluctuating base rate equal to the bank’s alternate base rate plus an applicable margin or a periodic fixed rate equal to LIBOR plus an applicable margin. The borrower is required to pay a commitment fee based on the unused portion of its respective credit facility. The applicable margin and the commitment fee are determined for us by reference to a pricing schedule based on our senior unsecured long-term debt ratings.

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•

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, enter into certain affiliate transactions, make certain distributions during an event of default, enter into certain restrictive agreements, and allow any material change in the nature of its business.

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

•

Other than swing line loans, each time funds are borrowed, the borrower must choose whether such borrowing will be an alternate base rate borrowing or a Eurodollar borrowing.  If such borrowing is an alternate base rate borrowing, interest is calculated on the basis of the greater of (a) the Prime Rate, (b) the Federal Funds Effective Rate plus one half of 1 percent and (c) a periodic fixed rate equal to the London Interbank Offered Rate (LIBOR) plus 1 percent, plus, in the case of each of (a), (b) and (c), an applicable margin. If the borrowing is a Eurodollar borrowing, interest is calculated on the basis of LIBOR for the relevant period plus an applicable margin.  Interest on swing line loans is calculated as the sum of the alternate base rate plus an applicable margin.  The borrower is required to pay a commitment fee based on the unused portion of the credit facility. The applicable margin and the commitment fee are determined for each borrower by reference to a pricing schedule based on such borrower’s senior unsecured long-term debt ratings.

•	5.75 to 1, for the quarters ending December 31, 2015, March 31, 2016 and June 30, 2016;

•	5.50 to 1, for the quarters ending September 30, 2016 and December 31, 2016;

•	5.00 to 1, for the quarter ending March 31, 2017 and each subsequent fiscal quarter, except for the the fiscal quarter and the two following fiscal quarters in which one or more acquisitions has been executed, in which case the ratio of debt to EBITDA is to be no greater than 5.5 to 1.00.

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(1)

Performance-based restricted stock units are valued utilizing a Monte Carlo valuation method using measures of total shareholder return. Certain of the performance-based restricted stock units are subject to a holding period of up to two years after the vesting date. Discounts for the restrictions of liquidity were applied to the estimated fair value at the date of certain awards and ranged from 5.83 percent to 15.58 percent. The discounts were developed using the Chaffe model and the Finnerty model. 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)	Excludes capital leases.

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(1)	Relates to certain surplus equipment. The estimated fair value was determined by a market approach based on our analysis of observable inputs in the principal market.

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(2)	Relates to a gas processing plant, the completion of which is considered remote due to unfavorable impact of low natural gas prices on customer drilling activities. The assessed fair value primarily represents the estimated salvage value of certain equipment measured using a market approach based on our analysis of observable inputs in the principal market.

(3)	Relates to an olefins pipeline project, the completion of which is considered remote due to lack of customer interest. The assessed fair value primarily represents the estimated fair value of unused pipeline measured using a market approach based on our analysis of observable inputs in the principal market.

(4)

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 – Divestiture.

(5)	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.

(6)	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 zero or an insignificant salvage value.

(7)

Relates to equity-method investments in DBJV and certain of the Appalachia Midstream Investments. The historical carrying value of these 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 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 were 11.8 percent and 8.8 percent for DBJV and certain of the Appalachia Midstream Investments, respectively, and reflected our cost of capital as impacted by market conditions, and risks associated with the underlying businesses.

(8)

Relates to equity-method investments in DBJV, certain of the Appalachia Midstream Investments, UEOM, and Laurel Mountain. We estimated the fair value of these 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 10.8 percent to 14.4 percent and reflected further fourth-quarter 2015 increases in our cost of capital, revised estimates of expected future cash flows, and risks associated with the underlying businesses.

(9)

Relates to equity-method investments in DBJV and 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 investments, along with lower natural gas prices for Laurel Mountain. We estimated the fair value of these 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 our cost of capital, revised estimates of expected future cash flows, and risks associated with the underlying businesses.

(10)

Relates to equity-method investments in Ranch Westex and multiple Appalachia Midstream Investments. The historical carrying value of these 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

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

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•	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)	2014 Additions to long-lived assets within our Williams Partners segment primarily includes the acquisition-date fair value of long-lived assets from the ACMP Acquisition. (See Note 2 - Acquisitions.)

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•	$173 million of income associated with the amortization of deferred income related to the restructuring of certain gas gathering contracts in the Barnett Shale and Mid-Continent regions and $58 million of related minimum volume commitment fees (see Note 7 – Other Income and Expenses of Notes to Consolidated Financial Statements);

•	$318 million impairment loss on certain equity-method investments (see Note 17 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk).

•	$239 million in revenue associated with minimum volume commitment fees in the Barnett Shale and Mid-Continent regions (see Note 7 – Other Income and Expenses);

•	$180 million impairment loss on certain assets (see Note 17 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk);

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•	$898 million impairment loss on certain equity-method investments (see Note 17 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk);

•	$1,098 million impairment of goodwill (see Note 17 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk).

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