Exhibit 99.1

DEFINITIONS

The following is a listing of certain abbreviations, acronyms and other industry terminology used throughout this Annual Report.

Measurements:

Barrel: One barrel of petroleum products that equals 42 U.S. gallons

Bcf : One billion cubic feet of natural gas

Bcf/d: One billion cubic feet of natural gas per day

British Thermal Unit (Btu): A unit of energy needed to raise the temperature of one pound of water by one degree

Fahrenheit

Dekatherms (Dth): A unit of energy equal to one million British thermal units

Mbbls/d: One thousand barrels per day

Mdth/d: One thousand dekatherms per day

MMcf/d: One million cubic feet per day

MMdth: One million dekatherms or approximately one trillion British thermal units

MMdth/d: One million dekatherms per day

Tbtu: One trillion British thermal units

Consolidated Entities:

ACMP: Access Midstream Partners, L.P. prior to its merger with Pre-Merger WPZ

Cardinal: Cardinal Gas Services, L.L.C.

Constitution: Constitution Pipeline Company, LLC

Gulfstar One: Gulfstar One LLC

Jackalope: Jackalope Gas Gathering Services, L.L.C.

Northwest Pipeline: Northwest Pipeline LLC

Pre-merger WPZ: Williams Partners L.P. prior to its merger with ACMP

Transco: Transcontinental Gas Pipe Line Company, LLC

WPZ: Williams Partners L.P.

Partially Owned Entities: Entities in which we do not own a 100 percent ownership interest and which, as of December 31, 2016, we account for as an equity-method investment, including principally the following:

Aux Sable: Aux Sable Liquid Products LP

Bluegrass: Bluegrass Pipeline Company LLC

Caiman II: Caiman Energy II, LLC

Discovery: Discovery Producer Services LLC

Gulfstream: Gulfstream Natural Gas System, L.L.C.

Laurel Mountain: Laurel Mountain Midstream, LLC

Moss Lake: Moss Lake Fractionation LLC and Moss Lake LPG Terminal LLC

OPPL: Overland Pass Pipeline Company LLC

UEOM: Utica East Ohio Midstream LLC

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Government and Regulatory:

EPA: Environmental Protection Agency

Exchange Act, the: Securities and Exchange Act of 1934, as amended

FERC: Federal Energy Regulatory Commission

GAAP: Generally accepted accounting principles

IRS: Internal Revenue Service

SEC: Securities and Exchange Commission

Other:

DRIP: Distribution reinvestment program

Energy Transfer: Energy Transfer Equity, L.P.

ETC: Energy Transfer Corp LP

ETC Merger: Merger wherein Williams would have been merged into ETC

Fractionation: The process by which a mixed stream of natural gas liquids is separated into its constituent products,

such as ethane, propane, and butane

IDR: Incentive distribution right

LNG: Liquefied natural gas; natural gas which has been liquefied at cryogenic temperatures

Merger Agreement: Merger Agreement and Plan of Merger of Williams with Energy Transfer and certain of its

affiliates

MVC: Minimum volume commitment

NGLs: Natural gas liquids; natural gas liquids result from natural gas processing and crude oil refining and are

used as petrochemical feedstocks, heating fuels, and gasoline additives, among other applications

NGL margins:NGL revenues less Btu replacement cost, plant fuel, transportation, and fractionation

PDH facility:Propane dehydrogenation facility

RGP Splitter:Refinery grade propylene splitter

Throughput:The volume of product transported or passing through a pipeline, plant, terminal, or other facility

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PART II

Item 6. Selected Financial Data

The following financial data at December 31, 2016 and 2015, and for each of the three years in the period ended December 31, 2016, should be read in conjunction with the other financial information included in Part II, Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations and Part II, Item 8, FinancialStatements and Supplementary Data of this Exhibit 99.1. All other financial data has been prepared from our accounting records.

	2016			2015			2014		2013		2012
	(Millions, except per-share amounts)
Revenues (1)	$	7,499		$	7,360		$	7,637	$	6,860	$	7,486
Income (loss) from continuing operations (2)	(350		)	(1,314		)	2,335		679		929
Amounts attributable to The Williams Companies, Inc.:
Income (loss) from continuing operations (2)	(424		)	(571		)	2,110		441		723
Diluted earnings (loss) per common share:
Income (loss) from continuing operations (2)	(.57		)	(.76		)	2.91		.64		1.15
Total assets at December 31 (3)	46,835			49,020			50,455		27,065		24,248
Commercial paper and long-term debt due within one year at December 31 (4)	878			675			802		226		1
Long-term debt at December 31 (3)	22,624			23,812			20,780		11,276		10,656
Stockholders’ equity at December 31 (3)	4,643			6,148			8,777		4,864		4,752
Cash dividends declared per common share	1.680			2.450			1.9575		1.438		1.196

_________

(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;

• 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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Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations

General

We are an energy infrastructure company focused on connecting North America’s significant hydrocarbon resource plays to growing markets for natural gas, NGLs, and olefins. Our operations are located principally in the United States and are organized within the Williams Partners reportable segment. All remaining business activities are included in Other.

Williams Partners

Williams Partners consists of our consolidated master limited partnership, WPZ, which includes gas pipeline and midstream businesses. The gas pipeline businesses include interstate natural gas pipelines and pipeline joint project investments; and the midstream businesses provide natural gas gathering, treating, and processing 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. As of December 31, 2016, we owned approximately 60 percent of the interests in WPZ, including the interests of the general partner, which were wholly owned by us, and IDRs.

Williams Partners’ gas pipeline businesses consist primarily of Transco and Northwest Pipeline. The gas pipeline business also holds interests in joint venture interstate and intrastate natural gas pipeline systems including a 50 percent equity-method investment in Gulfstream and a 41 percent interest in Constitution (a consolidated entity), which is under development. As of December 31, 2016, Transco and Northwest Pipeline own and operate a combined total of approximately 13,600 miles of pipelines with a total annual throughput of approximately 4,230 Tbtu of natural gas and peak-day delivery capacity of approximately 15.5 MMdth of natural gas.

Williams Partners’ midstream businesses primarily consist of (1) natural gas gathering, treating, compression, and processing; (2) NGL fractionation, storage and transportation; (3) crude oil production handling and transportation; and (4) olefins production. (See Geismar Olefins Facility Monetization below.) The primary service areas are concentrated in major producing basins in Colorado, Texas, Oklahoma, Kansas, New Mexico, Wyoming, the Gulf of Mexico, Louisiana, Pennsylvania, West Virginia, New York, and Ohio which include the Barnett, Eagle Ford, Haynesville, Marcellus, Niobrara, and Utica Shale plays as well as the Mid-Continent region.

The midstream businesses include equity-method investments in natural gas gathering and processing assets and NGL fractionation and transportation assets, including a 62 percent equity-method investment in UEOM, a 50 percent equity-method investment in the Delaware basin gas gathering system (DBJV) in the Mid-Continent region, a 69 percent equity-method investment in Laurel Mountain, a 58 percent equity-method investment in Caiman II, a 60 percent equity-method investment in Discovery, a 50 percent equity-method investment in OPPL, and Appalachia Midstream Services, LLC, which owns an approximate average 41 percent equity-method investment interest in multiple gas gathering systems in the Marcellus Shale (Appalachia Midstream Investments).

The midstream businesses previously included our Canadian midstream operations, which were comprised of 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. (See Note 3 – Divestiture of Notes to Consolidated Financial Statements.)

Williams Partners’ ongoing strategy is to safely and reliably operate large-scale, interstate natural gas transmission and midstream infrastructures where our assets can be fully utilized and drive low per-unit costs. We focus on consistently attracting new business by providing highly reliable service to our customers and investing in growing markets, including the deepwater Gulf of Mexico, the Marcellus Shale, the Gulf Coast Region, and areas of increasing natural gas demand.

Williams Partners’ interstate transmission and related storage activities are subject to regulation by the FERC and as such, our rates and charges for the transportation of natural gas in interstate commerce, and the extension, expansion

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or abandonment of jurisdictional facilities and accounting, among other things, are subject to regulation. The rates are established through the FERC’s ratemaking process. Changes in commodity prices and volumes transported have limited near-term impact on these revenues because the majority of cost of service is recovered through firm capacity reservation charges in transportation rates.

Other

Our former Williams NGL & Petchem Services segment included certain domestic olefins pipeline assets as well as certain Canadian assets, which included a liquids extraction plant near Fort McMurray, Alberta, that began operations in March 2016, and a propane dehydrogenation facility, which was under development. In September 2016, these Canadian operations were sold. (See Note 3 – Divestiture of Notes to Consolidated Financial Statements.) Considering this and in conjunction with an organizational realignment, effective January 1, 2017, the remaining assets are now reported within Other. Other also includes minor business activities that are not operating segments, as well as corporate operations. All segment disclosures have been recast for this segment change.

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

Dividends

In December 2016, we paid a regular quarterly dividend of $0.20 per share. On February 20, 2017, our board of directors approved a regular quarterly dividend of $0.30 per share payable on March 27, 2017, representing a 50 percent increase from our previous quarterly dividend.

Overview

Net income (loss) attributable to The Williams Companies, Inc., for the year ended December 31, 2016, increased $147 millioncompared to the year ended December 31, 2015, reflecting the absence of certain goodwill impairments, lower impairments of equity-method investments, an increase in olefins margins associated with our Geismar plant, decreases in operating and maintenance expenses, and higher equity earnings. These favorable changes were partially offset by an unfavorable change in net income attributable to noncontrolling interests driven primarily by higher WPZ income as well as the impact of reduced incentive distributions from WPZ associated with the termination of the WPZ Merger Agreement. The favorable changes were also partially offset by increased impairment charges and loss on sale associated with our Canadian operations, lower insurance recoveries, as well as higher interest incurred. See additional discussion in Results of Operations.

Acquisition of Additional Interests in Appalachia Midstream Investments

In February, 2017, we announced agreements to acquire additional interests in two Marcellus Shale gathering systems within Williams Partners’ Appalachia Midstream Investments in exchange for equity-method investment interests in DBJV and the Ranch Westex gas processing plant, both currently reported within the Williams Partners segment. We also expect to receive a total of $200 million in cash as part of the agreements subject to customary closing conditions and purchase price adjustments. The transactions are expected to close in late first-quarter or early second-quarter 2017.

Financial Repositioning

In January 2017, we announced agreements with WPZ, wherein we permanently waived the general partner’s incentive distribution rights and converted our 2 percent general partner interest in WPZ to a non-economic interest in exchange for 289 million newly issued WPZ common units. Pursuant to this agreement, we also purchased approximately 277 thousand WPZ common units for $10 million. Additionally, we purchased approximately 59 million common units of WPZ at a price of $36.08586 per unit in a private placement transaction, funded with proceeds from our equity offering (see Note 15 - Stockholders’ Equity of Notes to Consolidated Financial Statements). Following these transactions, we own a 74 percent limited partner interest in WPZ. It is anticipated that the combination of these

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measures will improve WPZ’s cost of capital, provide for debt reduction, and eliminate WPZ’s need to access the public equity markets for several years.

In addition to the previously announced Geismar monetization process, we have announced plans to monetize other select assets that are not core to our strategy. We expect to raise more than $2 billion in after-tax proceeds from the monetization process of Geismar and the other select assets. As we pursue these other asset monetizations, it is possible that we may incur impairments of certain equity-method investments, property, plant, and equipment, and intangible assets. Such impairments could potentially be caused by indications of fair value implied through the monetization process or, in the case of asset dispositions that are part of a broader asset group, the impact of the loss of future estimated cash flows.

Energy Transfer Merger Agreement

On September 28, 2015, we publicly announced in a press release that we had entered into a Merger Agreement with Energy Transfer and certain of its affiliates. The Merger Agreement provided that, subject to the satisfaction of customary closing conditions, we would merge with and into the newly formed ETC, with ETC surviving the ETC Merger.

On June 29, 2016, Energy Transfer provided us written notice terminating the Merger Agreement, citing the alleged failure of certain conditions under the Merger Agreement.

Termination of WPZ Merger Agreement

On May 12, 2015, we entered into an agreement for a unit-for-stock transaction whereby we would have acquired all of the publicly held outstanding common units of WPZ in exchange for shares of our common stock (WPZ Merger Agreement).

On September 28, 2015, prior to our entry into the Merger Agreement, we entered into a Termination Agreement and Release (Termination Agreement), terminating the WPZ Merger Agreement. Under the terms of the Termination Agreement, we were required to pay a $428 million termination fee to WPZ, at which time we owned approximately 60 percent, including the interests of the general partner and IDRs. Such termination fee settled through a reduction of quarterly incentive distributions we were entitled to receive from WPZ (such reduction not to exceed $209 million per quarter). The distributions from WPZ in November 2015, February 2016, and May 2016 were reduced by $209 million, $209 million, and $10 million, respectively, related to this termination fee.

Organizational Realignment

In September 2016, we announced organizational changes aiming to simplify our structure, increase direct operational alignment to advance our natural gas-focused strategy, and drive continued focus on customer service and execution. Effective January 1, 2017, we implemented these changes, which combined the management of certain of our operations and reduced the overall number of operating areas managed within our business.

Information in this report has generally been prepared to be consistent with the reportable segment presentation in our consolidated financial statement in Part II, Item 8 of this document. These segments are discussed in further detail in the following sections.

Williams Partners

Northwest Pipeline rate case

On January 23, 2017, Northwest Pipeline filed a Stipulation and Settlement Agreement with the FERC for new rates.  The new rates become effective January 1, 2018, and are not expected to materially affect our trend of earnings.  Pursuant to this agreement, Northwest Pipeline can file for new rates to be effective after October 1, 2018, and must file a general rate case for new rates to become effective no later than January 1, 2023.

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Geismar olefins facility monetization

In September 2016, Williams Partners announced the initiation of an ongoing process to explore monetization of its ownership interest in the Geismar, Louisiana, olefins plant and complex, consistent with our strategy to narrow our focus and allocate capital to our natural gas–focused business.

Sale of Canadian operations

In September 2016, we completed the sale of our Canadian operations for total consideration of $1.02 billion. We recognized an impairment charge of $747 million during the second quarter of 2016 related to these operations and an additional loss of $66 million upon completion of the sale. (See Note 3 – Divestiture.)

Barnett Shale and Mid-Continent contract restructurings

In August 2016, Williams Partners conditionally committed to execute a new gas gathering agreement in the Barnett Shale. The agreement was executed in the fourth quarter of 2016, in conjunction with our existing customer, Chesapeake Energy Corporation, closing the sale of its Barnett Shale properties to another producer. That other producer, which has an investment grade credit rating, is now our customer under the new gas gathering agreement. The restructured agreement provided a $754 million up-front cash payment to us primarily in exchange for eliminating future minimum volume commitments. The restructured agreement also provides for revised gathering rates. Based on current commodity price assumptions at the time of the agreement, we generally expect the up-front cash proceeds and the ongoing cash flows generated by gathering services, to represent equivalent net present value of cash flows as compared to expected performance under the existing agreement. Additionally, Williams Partners agreed to a revised contract in the Mid-Continent region, also with Chesapeake Energy Corporation. The revised contract was executed in the third quarter of 2016 and provided an up-front cash payment to us of $66 million primarily in exchange for changing from a cost of service contract to fixed-fee terms. The majority of the up-front cash proceeds from both agreements were recognized as deferred revenue and will be amortized into income in future periods. In the near term, we do not expect that our trend of reported results will be significantly impacted by the effect of the discount associated with the up-front cash proceeds relative to the original minimum volume commitments and reduced gathering rates. It was anticipated that both agreements would reduce customer concentration risk and provide support to realize additional drilling and improved volumes in these regions.

Powder River basin contract restructuring

In October 2016, in conjunction with our partner in the Bucking Horse natural gas processing plant and Jackalope Gas Gathering System, we announced an agreement with Chesapeake Energy Corporation to restructure gathering and processing contracts in the Powder River basin. The restructured contracts became effective in January 2017 and replaced the previous cost-of-service arrangement with MVCs in the near-term such that we do not expect that our near-term trend of reported results will be significantly impacted by the restructured terms.

Rock Springs expansion

In August 2016, the Rock Springs expansion was placed into service. The project expanded Transco’s existing natural gas transmission system from New Jersey to a generation facility in Maryland and increased capacity by 192 Mdth/d.

Gulf Trace expansion

In February 2017, the Gulf Trace expansion was placed into service. The project expanded Transco’s existing natural gas transmission system together with greenfield facilities to provide incremental firm transportation capacity from Station 65 in St. Helena Parish, Louisiana to a new interconnection with Sabine Pass Liquefaction in Cameron Parish, Louisiana. It is expected to increase capacity by 1,200 Mdth/d.

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Redwater expansion

In March 2016, we completed the expansion of our Redwater facilities in support of a long-term agreement to provide gas processing services to a second bitumen upgrader in Canada’s oil sands near Fort McMurray, Alberta. The expanded Redwater facility receives NGL/olefins mixtures from the second bitumen upgrader and fractionates the mixtures into an ethane/ethylene mix, propane, polymer grade propylene, normal butane, an alkylation feed and condensate. We sold these operations in September 2016. (See Note 3 – Divestiture of Notes to Consolidated Financial Statements.)

Other

Horizon liquids extraction plant

In March 2016, we completed a new liquids extraction plant near Fort McMurray, Alberta. The Boreal pipeline was extended to enable transportation of the NGL/olefins mixture from the new liquids extraction plant to Williams Partners’ expanded Redwater facilities. The plant increased the amount of NGLs produced in Canada to a total of approximately 40 Mbbls/d. To mitigate ethane price risk associated with our processing services, we had a long-term agreement with a minimum price for ethane sales to a third-party customer. We sold these operations in September 2016. (See Note 3 – Divestiture of Notes to Consolidated Financial Statements.)

Commodity Prices

NGL per-unit margins were approximately 7 percent lower in 2016 compared to the same period of 2015. Following a sharp decline in late 2014 to early 2015, total NGL margins have remained somewhat consistent in 2015 and 2016. While 2014 and 2015 reflect limited ethane recoveries, we have seen an increase in ethane production during 2016.

NGL margins are defined as NGL revenues less any applicable Btu replacement cost, plant fuel, and third-party transportation and fractionation. Per-unit NGL margins are calculated based on sales of our own equity volumes at the processing plants. Our equity volumes include NGLs where we own the rights to the value from NGLs recovered at our plants under both “keep-whole” processing agreements, where we have the obligation to replace the lost heating value with natural gas, and “percent-of-liquids” agreements whereby we receive a portion of the extracted liquids with no obligation to replace the lost heating value.

The following graph illustrates the NGL production and sales volumes, as well as the margin differential between ethane and non-ethane products and the relative mix of those products.

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The potential impact of commodity prices on our business is further discussed in the following Company Outlook.

Company Outlook

Our strategy is to provide large-scale energy infrastructure designed to maximize the opportunities created by the vast supply of natural gas and natural gas products that exists in the United States. We accomplish this by connecting the growing demand for cleaner fuels and feedstocks with our major positions in the premier natural gas and natural gas products supply basins. We continue to maintain a strong commitment to safety, environmental stewardship, operational excellence, and customer satisfaction. We believe that accomplishing these goals will position us to deliver safe and reliable service to our customers and an attractive return to our shareholders.

Our business plan for 2017 includes the previously announced agreement with WPZ to permanently waive our incentive distribution rights in exchange for WPZ common units as well as our private purchase of $2.1 billion newly issued WPZ commits units. We expect to increase our dividend to $0.30 per share, or $1.20 annually, beginning in the first quarter of 2017. Our business plan also includes previously discussed asset monetizations, which include our ownership interest in the Geismar olefins facility as well as other select assets that are not core to our strategy. The monetizations are expected to yield after-tax proceeds of greater than $2.0 billion. For WPZ, these transactions are expected to improve its cost of capital, remove its need to access the public equity markets for the next several years, enhance growth, and provide for debt reduction, solidifying WPZ as an attractive financing vehicle. The transactions are also expected to facilitate a reduction of our parent-level debt and provides for dividend growth flexibility, while retaining strategic and financing flexibility.

Our growth capital and investment expenditures in 2017 are expected to total $2.1 billion to $2.8 billion. Approximately $1.4 billion to $1.9 billion of our growth capital funding needs include Transco expansions and other interstate pipeline growth projects, most of which are fully contracted with firm transportation agreements. The remaining growth capital spending in 2017 primarily reflects investment in gathering and processing systems in the Northeast region limited primarily to known new producer volumes, including volumes that support Transco expansion

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

As a result of our significant continued capital and investment expenditures on Transco expansions and fee-based gathering and processing projects, as well as the previously discussed sale of our Canadian operations and the planned monetization of the Geismar olefins facility, fee-based businesses are becoming an even more significant component of our portfolio and serve to reduce the influence of commodity price fluctuations on our operating results and cash flows. We expect to benefit as continued growth in demand for low-cost natural gas is driven by increases in LNG exports, industrial demand and power generation. Current forward market prices indicate a slightly more favorable energy commodity price environment in 2017 as compared to 2016, including higher natural gas and NGL prices. However, some of our customers may continue to curtail or delay drilling plans until there is a more sustained recovery in prices, which may negatively impact our gathering volumes. Although there has been some improvement, the credit profiles of certain of our producer customers remain challenged. Unfavorable changes in energy commodity prices or the credit profile of our producer customers may also result in noncash impairments of our assets.

In 2017, our operating results will include increases from our fee-based businesses recently placed in service or expected to be placed in service in 2017 primarily along the Transco system, a full year benefit of expanded capacity on our Gulfstar FPS™, and lower general and administrative expenses due to cost reduction initiatives and asset monetizations. We expect overall gathering and processing volumes to remain steady in 2017 and increase thereafter to meet the growing demand for natural gas and natural gas products.

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

• 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;

• 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.

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

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Expansion Projects

Our ongoing major expansion projects include the following:

Williams Partners

Eagle Ford

We plan to expand our gathering infrastructure in the Eagle Ford region in order to meet our customers’ production plans. The expansion of the gathering infrastructure includes the addition of new facilities, well connections, and gathering pipeline to the existing systems.

Oak Grove Expansion

We plan to expand our processing capacity at our Oak Grove facility by adding a second 200 MMcf/d cryogenic natural gas processing plant, which, based on our customers’ needs, is expected to be placed into service in 2020.

Gathering System Expansion

We will continue to expand the gathering systems in the Marcellus and Utica Shale regions that are needed to meet our customers’ production plans. The expansion of the gathering infrastructure includes additional compression and gathering pipeline to the existing system.

Constitution Pipeline

In December 2014, we received approval from the FERC to construct and operate the jointly owned Constitution pipeline, which will have an expected capacity of 650 Mdth/d. However, in April 2016, the New York State Department of Environmental Conservation (NYSDEC) denied a necessary water quality certification for the New York portion of the pipeline. We remain steadfastly committed to the project, and in May 2016, Constitution appealed the NYSDEC’s denial of the certification and filed an action in federal court seeking a declaration that the State of New York’s authority to exercise permitting jurisdiction over certain other environmental matters is preempted by federal law. (See Note 4 – Variable Interest Entities of Notes to Consolidated Financial Statements.) We currently own 41 percent of Constitution with three other parties holding 25 percent, 24 percent, and 10 percent, respectively. We will be the operator of Constitution. The 126-mile Constitution pipeline will connect our gathering system in Susquehanna County, Pennsylvania, to the Iroquois Gas Transmission and Tennessee Gas Pipeline systems in New York, as well as to a local distribution company serving New York and Pennsylvania. In light of the NYSDEC’s denial of the water quality certification and the actions taken to challenge the decision, the target in-service date has been revised to as early as the second half of 2018, which assumes that the legal challenge process is satisfactorily and promptly concluded.

Garden State

In April 2016, we received approval from the FERC to expand Transco’s existing natural gas transmission system to provide incremental firm transportation capacity from Station 210 in New Jersey to a new interconnection on our Trenton Woodbury Lateral in New Jersey. The project will be constructed in phases and is expected to increase capacity by 180 Mdth/d. We plan to place the initial phase of the project into service during the third quarter of 2017 and the remaining portion in the second quarter of 2018, assuming timely receipt of all necessary regulatory approvals.

Norphlet Project

In March 2016, we announced that we have reached an agreement to provide deepwater gas gathering services to the Appomattox development in the Gulf of Mexico. The project will provide offshore gas gathering services to our existing Transco lateral, which will provide transmission services onshore to our Mobile Bay processing facility. We also plan to make modifications to our Main Pass 261 Platform to install an alternate delivery route from the platform, as well as modifications to our Mobile Bay processing facility. The project is scheduled to go into service during the second quarter of 2020.

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Hillabee

In February 2016, the FERC issued a certificate order for the initial phases of Transco’s Hillabee Expansion Project. The project involves an expansion of Transco’s existing natural gas transmission system from Station 85 in west central Alabama to a proposed new interconnection with the Sabal Trail project in Alabama. The project will be constructed in phases, and all of the project expansion capacity will be leased to Sabal Trail. We plan to place the initial phase of the project into service concurrent with the in-service date of the Sabal Trail project, which is planned to occur as early as the second quarter of 2017. The in-service date of the second phase of the project is planned for the second quarter of 2020 and together they are expected to increase capacity by 1,025 Mdth/d.

In March 2016, WPZ entered into an agreement with the member-sponsors of Sabal Trail to resolve several matters. In accordance with the agreement, the member-sponsors will pay us an aggregate amount of $240 million in three equal installments as certain milestones of the project are met. The first $80 million payment was received in March 2016 and the second installment was received in September 2016. WPZ expects to recognize income associated with these receipts over the term of the capacity lease agreement.

New York Bay Expansion

In July 2016, we received approval from the FERC to expand Transco’s existing natural gas transmission system to provide incremental firm transportation capacity from Pennsylvania to the Rockaway Delivery Lateral transfer point and the Narrows meter station in Richmond County, New York. We plan to place the project into service during the fourth quarter of 2017, and it is expected to increase capacity by 115 Mdth/d.

Atlantic Sunrise

In February 2017, we received approval from the FERC to expand Transco’s existing natural gas transmission system along with greenfield facilities to provide incremental firm transportation capacity from the northeastern Marcellus producing area to markets along Transco’s mainline as far south as Station 85 in west central Alabama. We expect to place a portion of the project facilities into service during the second half of 2017 and are targeting a full in-service during mid-2018, assuming timely receipt of all necessary regulatory approvals. The project is expected to increase capacity by 1,700 Mdth/d.

Virginia Southside II

In July 2016, we received approval from the FERC to expand Transco’s existing natural gas transmission system together with greenfield facilities to provide incremental firm transportation capacity from Station 210 in New Jersey and Station 165 in Virginia to a new lateral extending from our Brunswick Lateral in Virginia. We plan to place the project into service during the fourth quarter of 2017 and it is expected to increase capacity by 250 Mdth/d.

Dalton

In August 2016, we obtained approval from the FERC to expand Transco’s existing natural gas transmission system together with greenfield facilities to provide incremental firm transportation capacity from Station 210 in New Jersey to markets in northwest Georgia. We plan to place the project into service in 2017 and it is expected to increase capacity by 448 Mdth/d.

Gulf Connector

In August 2016, we filed an application with the FERC to expand Transco’s existing natural gas transmission system to provide incremental firm transportation capacity from Station 65 in Louisiana to delivery points in Wharton and San Patricio Counties, Texas. The project will be constructed in two phases, with the initial phase of the project expected to be in service during the second half of 2018 and the remaining phase in 2019, assuming timely receipt of all necessary regulatory approvals. The project is expected to increase capacity by 475 Mdth/d.

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Other

Gulf Coast NGL and Olefin Infrastructure Expansion

Certain previously acquired liquids pipelines in the Gulf Coast region are expected to be combined with an organic build-out of several projects to expand our petrochemical services in that region. The projects include the construction and commissioning of pipeline systems capable of transporting various purity natural gas liquids and olefins products in the Gulf Coast region. In response to the current conditions in the midstream industry, we are slowing the pace of development and may seek partners for these projects.

Critical Accounting Estimates

The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions. We believe that the nature of these estimates and assumptions is material due to the subjectivity and judgment necessary, or the susceptibility of such matters to change, and the impact of these on our financial condition or results of operations.

Pension and Postretirement Obligations

We have employee benefit plans that include pension and other postretirement benefits. Net periodic benefit cost and obligations for these plans are impacted by various estimates and assumptions. These estimates and assumptions include the expected long-term rates of return on plan assets, discount rates, expected rate of compensation increase, health care cost trend rates, and employee demographics, including retirement age and mortality. These assumptions are reviewed annually and adjustments are made as needed. The assumptions utilized to compute cost and the benefit obligations are shown in Note 10 – Employee Benefit Plans of Notes to Consolidated Financial Statements.

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

	Benefit Cost						Benefit Obligation
	One- Percentage- Point Increase			One- Percentage- Point Decrease			One- Percentage- Point Increase			One- Percentage- Point Decrease
	(Millions)
Pension benefits:
Discount rate	$	(9	)	$	10		$	(130	)	$	154
Expected long-term rate of return on plan assets	(13		)	13			—			—
Rate of compensation increase	3			(2		)	9			(7		)
Other postretirement benefits:
Discount rate	1			1			(21		)	25
Expected long-term rate of return on plan assets	(2		)	2			—			—
Assumed health care cost trend rate	—			—			6			(5		)

Our expected long-term rates of return on plan assets, as determined at the beginning of each fiscal year, are based on the average rate of return expected on the funds invested in the plans. We determine our long-term expected rates of return on plan assets using our expectations of capital market results, which include an analysis of historical results as well as forward-looking projections. These capital market expectations are based on a period of at least 10 years and take into account our investment strategy and mix of assets, which are weighted toward domestic and international equity securities. We develop our expectations using input from our third-party independent investment consultant. The forward-looking capital market projections start with current conditions of interest rates, equity pricing, economic growth, and inflation and those are overlaid with forward looking projections of normal inflation, growth, and interest rates to determine expected returns. The capital market return projections for specific asset classes in the investment portfolio are then applied to the relative weightings of the asset classes in the investment portfolio. The resulting rates are an estimate of future results and, thus, likely to be different than actual results.

In 2016, the benefit plans’ assets outperformed their respective benchmarks for fixed income strategies, but generally underperformed the respective benchmarks for equity strategies. While the 2016 investment performance

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was greater than our expected rates of return, the expected rates of return on plan assets are long-term in nature and are not significantly impacted by short-term market performance. Changes to our asset allocation would also impact these expected rates of return. Our expected long-term rate of return on plan assets used for our pension plans was 6.85 percent in 2016. The 2016 actual return on plan assets for our pension plans was approximately 7.5 percent. The 10-year average rate of return on pension plan assets through December 2016 was approximately 3.7 percent.

The discount rates are used to measure the benefit obligations of our pension and other postretirement benefit plans. The objective of the discount rates is to determine the amount, if invested at the December 31 measurement date in a portfolio of high-quality debt securities, that will provide the necessary cash flows when benefit payments are due. Increases in the discount rates decrease the obligation and, generally, decrease the related cost. The discount rates for our pension and other postretirement benefit plans are determined separately based on an approach specific to our plans and their respective expected benefit cash flows as described in Note 1 – General, Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies and Note 10 – Employee Benefit Plans of Notes to Consolidated Financial Statements. Our discount rate assumptions are impacted by changes in general economic and market conditions that affect interest rates on long-term, high-quality debt securities as well as by the duration of our plans’ liabilities.

The expected rate of compensation increase represents average long-term salary increases. An increase in this rate causes the pension obligation and cost to increase.

The assumed health care cost trend rates are based on national trend rates adjusted for our actual historical cost rates and plan design. An increase in this rate causes the other postretirement benefit obligation and cost to increase.

Equity-Method Investments

At the end of the third quarter of 2016, we became aware of changes involving certain of DBJV’s customer contracts, which impacted our estimates of DBJV’s future cash flows. As such, we evaluated this investment for impairment at September 30, 2016, and determined that no impairment was necessary. We also entered into initial discussions with the system operator regarding the terms and economic assumptions of these contract changes.

During the fourth quarter of 2016, these discussions led to negotiations with the system operator to exchange our interest in DBJV and another equity-method investment in the Permian basin (Ranch Westex) for its interests in certain gathering systems in the Northeast and cash. We already hold partial interests in these Northeast gathering systems through our Appalachia Midstream Investments. As previously discussed, we reached agreements for such transactions in February 2017.

As part of the preparation of our year-end financial statements, we evaluated the carrying amounts of our investments in DBJV, Ranch Westex and these certain gathering systems within our Appalachia Midstream Investments for impairment. We also evaluated other equity-method investments within the Northeast area for impairment as of December 31, 2016, including other gathering systems within our Appalachia Midstream Investments and our investment in UEOM. Our impairment evaluations utilized an income approach, but also considered the fair values indicated by the previously described transaction. The estimated fair value of our investment in DBJV exceeded its carrying value and no impairment was necessary. Based on the fair value of the consideration expected to be received, we currently expect to recognize a gain upon consummation of the previously described exchange transaction in 2017.

We estimated the fair value of our Appalachia Midstream Investments and UEOM using an income approach with discount rates ranging from 10.2 percent to 12.5 percent and also considered the value implied by the previously described transactions as applicable. For certain gathering systems within our Appalachia Midstream Investments, the fair value was determined to be less than our carrying value, resulting in an other-than-temporary impairment charge of $294 million. No impairment was necessary for other gathering systems within our Appalachia Midstream Investments or our investment in UEOM. For those investments evaluated for which no impairment was required, our estimate of fair value exceeded our carrying value by amounts ranging from approximately 2.5 percent to 7.5 percent. We estimate that an increase in the discount rate utilized of 50 basis points would have resulted in an additional impairment charge of approximately $45 million. We also recorded an additional impairment of $24 million related to our interest in Ranch Westex.

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Judgments and assumptions are inherent in our estimates of future cash flows, discount rates, and market measures utilized. The use of alternate judgments and assumptions could result in a different calculation of fair value, which could ultimately result in the recognition of a different impairment charge in the consolidated financial statements.

At December 31, 2016, our Consolidated Balance Sheet includes approximately $6.7 billion of investments that are accounted for under the equity-method of accounting. We evaluate these investments for impairment when events or changes in circumstances indicate, in our management’s judgment, that the carrying value of such investments may have experienced an other-than-temporary decline in value. We continue to monitor our equity-method investments for any indications that the carrying value may have experienced an other-than-temporary decline in value. When evidence of a loss in value has occurred, we compare our estimate of the fair value of the investment to the carrying value of the investment to determine whether an impairment has occurred. We generally estimate the fair value of our investments using an income approach where significant judgments and assumptions include expected future cash flows and the appropriate discount rate. In some cases, we may utilize a form of market approach to estimate the fair value of our investments.

If the estimated fair value is less than the carrying value and we consider the decline in value to be other-than-temporary, the excess of the carrying value over the fair value is recognized in the consolidated financial statements as an impairment charge. Events or changes in circumstances that may be indicative of an other-than-temporary decline in value will vary by investment, but may include:

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

• Lower than expected cash distributions from investees;

• 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.

Constitution Pipeline Capitalized Project Costs

As of December 31, 2016, Property, plant, and equipment – netin our Consolidated Balance Sheet includes approximately $381 million of capitalized project costs for Constitution, for which we are the construction manager and own a 41 percent consolidated interest. In December 2014, we received approval from the FERC to construct and operate this jointly owned pipeline. However, in April 2016, the New York State Department of Environmental Conservation (NYSDEC) denied a necessary water quality certification for the New York portion of the Constitution pipeline. We remain steadfastly committed to the project, and in May 2016, Constitution appealed the NYSDEC's denial of the certification and filed an action in federal court seeking a declaration that the State of New York's authority to exercise permitting jurisdiction over certain other environmental matters is preempted by federal law.

As a result of the denial by the NYSDEC, we evaluated the capitalized project costs for impairment as of March 31, 2016, and as of December 31, 2016, and determined that no impairment was necessary. Our evaluation considered probability-weighted scenarios of undiscounted future net cash flows, including a scenario assuming successful resolution with the NYSDEC and construction of the pipeline, as well as a scenario where the project does not proceed. We continue to monitor the capitalized project costs associated with Constitution for potential impairment.

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Results of Operations

Consolidated Overview

The following table and discussion is a summary of our consolidated results of operations for the three years ended December 31, 2016. The results of operations by segment are discussed in further detail following this consolidated overview discussion.

	Years Ended December 31,
	2016			$ Change from 2015*	% Change from 2015*		2015			$ Change from 2014*	% Change from 2014*		2014
	(Millions)
Revenues:
Service revenues	$	5,171		+7	—	%	$	5,164		+1,048	+25	%	$	4,116
Product sales	2,328			+132	+6	%	2,196			-1,325	-38	%	3,521
Total revenues	7,499						7,360						7,637
Costs and expenses:
Product costs	1,725			+54	+3	%	1,779			+1,237	+41	%	3,016
Operating and maintenance expenses	1,580			+75	+5	%	1,655			-163	-11	%	1,492
Depreciation and amortization expenses	1,763			-25	-1	%	1,738			-562	-48	%	1,176
Selling, general, and administrative expenses	723			+18	+2	%	741			-80	-12	%	661
Impairment of goodwill	—			+1,098	+100	%	1,098			-1,098	NM		—
Impairment of certain assets	873			-664	NM		209			-157	NM		52
Net insurance recoveries – Geismar Incident	(7		)	-119	-94	%	(126		)	-106	-46	%	(232		)
Other (income) expense – net	142			-102	NM		40			-137	NM		(97		)
Total costs and expenses	6,799						7,134						6,068
Operating income (loss)	700						226						1,569
Equity earnings (losses)	397			+62	+19	%	335			+191	+133	%	144
Gain on remeasurement of equity-method investment	—			—	—	%	—			-2,544	-100	%	2,544
Impairment of equity-method investments	(430		)	+929	+68	%	(1,359		)	-1,359	NM		—
Other investing income (loss) – net	63			+36	+133	%	27			-16	-37	%	43
Interest expense	(1,179		)	-135	-13	%	(1,044		)	-297	-40	%	(747		)
Other income (expense) – net	74			-28	-27	%	102			+71	NM		31
Income (loss) from continuing operations before income taxes	(375		)				(1,713		)				3,584
Provision (benefit) for income taxes	(25		)	-374	-94	%	(399		)	+1,648	NM		1,249
Income (loss) from continuing operations	(350		)				(1,314		)				2,335
Income (loss) from discontinued operations	—			—	—	%	—			-4	-100	%	4
Net income (loss)	(350		)				(1,314		)				2,339
Less: Net income (loss) attributable to noncontrolling interests	74			-817	NM		(743		)	+968	NM		225
Net income (loss) attributable to The Williams Companies, Inc.	$	(424	)				$	(571	)				$	2,114

_______

* + = 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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2016 vs. 2015

Service revenuesincreased slightly primarily due toexpansion projects placed in service in 2015 and 2016, partially offset by a decrease in gathering, processing, and fractionation revenue primarily due to lower volumes in the Barnett Shale and Anadarko basin.

Product sales increased primarily due to higher olefin sales reflecting increased volumes at our Geismar plant as a result of the plant operating at higher production levels in 2016, partially offset by a decrease from our other olefin operations associated with lower volumes and per-unit sales prices. Product sales also reflect higher marketing revenues associated with higher NGL and propylene prices and natural gas and crude oil volumes, partially offset by lower NGL volumes, and crude oil prices.

The decrease in Product costsincludes lower olefin feedstock purchases and lower costs associated with other product sales, partially offset by higher marketing purchases primarily due to the same factors that increased marketing sales. The decline in olefin feedstock purchases is primarily associated with lower per-unit feedstock costs and volumes at our other olefin operations, partially offset by an increase in olefin feedstock purchases at our Geismar plant reflecting increased volumes resulting from higher production levels in 2016.

Operating and maintenance expensesdecreased primarily due to lower labor-related and outside service costs resulting from our first-quarter 2016 workforce reductions and cost containment efforts and lower costs associated with general maintenance activities in the Marcellus Shale, as well as the absence of ACMP transition-related costs recognized in 2015. These decreases are partially offset by $16 million of severance and related costs recognized in 2016 and higher pipeline testing and general maintenance costs at Transco.

Depreciation and amortization expensesincreased primarily due to depreciation on new assets placed in service, including Transco pipeline projects, partially offset by lower depreciation related to Canadian operations sold in 2016.

Selling, general, and administrative expenses(SG&A) decreased primarily due to lower merger and transition costs associated with the ACMP merger and lower labor-related costs resulting from our first-quarter 2016 workforce reductions and cost containment efforts. These decreases were partially offset by certain project development costs associated with the Canadian PDH facility that we began expensing in 2016, as well as $26 million of severance and related costs recognized in 2016 and $17 million of higher costs associated with our evaluation of strategic alternatives.

Impairment of goodwilldecreased due to the absence of a 2015 impairment charge associated with certain goodwill. (See Note 17 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk of Notes to Consolidated Financial Statements.)

Impairment of certain assets reflects 2016 impairments of our Canadian operations and certain Mid-Continent assets, and other assets. Impairments recognized in 2015 relate primarily to previously capitalized development costs and surplus equipment write-downs. (See Note 17 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk of Notes to Consolidated Financial Statements.)

Net insurance recoveries – Geismar Incident changed unfavorably reflecting the receipt of $126 million of insurance proceeds in the second quarter of 2015, as compared to the receipt of $7 million of proceeds in the fourth quarter of 2016.

The unfavorable change inOther (income) expense – netwithin Operating income (loss) includes a loss on the sale of our Canadian operations that were sold in September 2016, project development costs at Constitution as we discontinued capitalization of these costs in April 2016, and an 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, partially offset by a $10 million gain on the sale of idle pipe in 2016.

Operating income (loss) changed favorably primarily due to the absence of a goodwill impairment in 2015, higher olefin margins related to the Geismar plant operating at higher production levels in 2016, lower costs related to the merger and integration of ACMP, and lower costs and expenses primarily associated with cost containment efforts.

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These favorable changes are partially offset by impairments and loss on sale of certain assets in 2016, a decrease in insurance proceeds received, expensed Canadian PDH facility project development costs, and higher depreciation expenses related to new projects placed in service.

Equity earnings (losses)changed favorably primarily due to a $30 million increase at Discovery driven by the completion of the Keathley Canyon Connector in the first quarter of 2015. Additionally, OPPL, Laurel Mountain, and DBJV improved $16 million, $11 million, and $10 million, respectively.

Impairment of equity-method investments reflects 2016 impairment charges associated with our Appalachia Midstream Investments, DBJV, and Laurel Mountain equity-method investments, while the 2015 impairment charges relate to our equity-method investments in Appalachia Midstream Investments, DBJV, UEOM, and Laurel Mountain. (See Note 6 – Investing Activitiesof Notes to Consolidated Financial Statements.)

Other investing income (loss) – netchanged favorably due to a 2016 gain on the sale of an equity-method investment interest in a gathering system that was part of our Appalachia Midstream Investments and higher interest income associated with a receivable related to the sale of certain former Venezuela assets. (See Note 6 – Investing Activities of Notes to Consolidated Financial Statements.)

Interest expenseincreased due to higher Interest incurred of $99 million primarily attributable to new debt issuances in 2016 and 2015 and lower Interest capitalized of $36 million primarily related to construction projects that have been placed into service, partially offset by lower interest due to 2015 and 2016 debt retirements. (See Note 14 – Debt, Banking Arrangements, and Leases of Notes to Consolidated Financial Statements.)

Other income (expense) – net below Operating income (loss) changed unfavorably primarily due to a decrease in allowance for equity funds used during construction (AFUDC) due to decreased spending on Constitution and the absence of a $14 million gain on early debt retirement in 2015.

Provision (benefit) for income taxes changed unfavorably primarily due to a decrease in pretax loss in 2016. See Note 8 – Provision (Benefit) for Income Taxes of Notes to Consolidated Financial Statements for a discussion of the effective tax rates compared to the federal statutory rate for both years.

The unfavorable change in Net income (loss) attributable to noncontrolling interests is primarily due to higher operating results at WPZ, the impact of decreased income allocated to the WPZ general partner driven by the impact of reduced incentive distributions from WPZ associated with the termination of the WPZ Merger Agreement, and the absence of the accelerated amortization of a beneficial conversion feature from the first quarter of 2015. These changes are partially offset by a favorable change primarily related to our partners’ share of Constitution project development costs in 2016.

2015 vs. 2014

Service revenuesincreased primarily due to additional revenues associated with a full year of ACMP operations in 2015, increased revenues associated with the start-up of operations at Gulfstar One during the fourth quarter of 2014, and an increase in Transco’s natural gas transportation fees due to new projects placed in service in 2014 and 2015. Revenues from operations associated with our acquisition of ACMP and the northeast region also increased due to higher volumes related to new well connects. A decrease in Canadian construction management revenues, reflecting a shift to internal customer construction projects, partially offset these increases.

Product sales decreased due to a decrease in marketing revenues primarily associated with lower prices across all products, partially offset by higher non-ethane volumes, and a decrease in revenues from our equity NGLs reflecting lower NGL prices, partially offset by higher NGL volumes. Product sales also decreased due to lower olefin sales from other olefin operations associated with lower per-unit sales prices, partially offset by higher volumes. These decreases are partially offset by an increase in olefin sales primarily due to resuming our Geismar operations during 2015.

Product costs decreased due to a decrease in marketing purchases primarily associated with lower per-unit costs, partially offset by higher non-ethane volumes, and a decrease in natural gas purchases associated with the production of equity NGLs primarily due to lower natural gas prices, partially offset by higher volumes. Product costs also decreased

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due to lower feedstock purchases in our other olefin operations primarily due to lower per-unit feedstock costs across all products as well as lower per-unit costs, partially offset by significantly higher volumes in 2015. These decreases are partially offset by an increase in olefin feedstock purchases primarily associated with resuming our Geismar operations.

Operating and maintenance expenses increased primarily due to new expenses associated with operations acquired in our acquisition of ACMP, increased growth of operating activity in certain areas, increased maintenance and repair expenses, and the return to operations of the Geismar plant. These increases are partially offset by a decrease in Canadian construction management expenses that reflect a shift to internal customer construction projects.

Depreciation and amortization expenses increased primarily due to new expenses associated with operations acquired in our acquisition of ACMP and from depreciation on new projects placed in service, including Gulfstar One and the Geismar expansion.

SG&A increased primarily due to administrative expenses associated with operations acquired in our acquisition of ACMP, including $31 million higher ACMP merger and transition-related costs, partially offset by the absence of $16 million of acquisition costs incurred in 2014. In addition, 2015 includes $32 million of costs associated with our evaluation of strategic alternatives. These increases are partially offset by the absence of $18 million of project development costs incurred in 2014 related to the Bluegrass Pipeline reflecting 100 percent of such costs. The 50 percent noncontrolling interest share of these costs are presented in Net income (loss) attributable to noncontrolling interests.

Impairment of goodwill reflects a 2015 impairment charge associated with certain goodwill. (See Note 17 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk of Notes to Consolidated Financial Statements.)

Impairment of certain assets relate primarily to 2015 impairments of previously capitalized development costs and surplus equipment write-downs. (See Note 17 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk of Notes to Consolidated Financial Statements.)

Net insurance recoveries – Geismar Incident changed unfavorably primarily due to the receipt of $126 million of insurance recoveries in 2015 as compared to the receipt of $246 million of insurance recoveries in 2014.

Other (income) expense – net within Operating income (loss) changedunfavorably primarily due to the absence of $154 million of cash proceeds received in 2014 related to a contingency settlement gain and the absence of a $12 million net gain recognized in 2014 related to a partial acreage dedication release. (See Note 7 – Other Income and Expenses of Notes to Consolidated Financial Statements.)

Operating income (loss) changed unfavorably primarily due to a 2015 impairment of goodwill, higher impairments of certain assets, higher depreciation, operating, and maintenance expenses related to construction projects placed in service and the start-up of the Geismar plant, $229 million lower NGL margins driven by lower prices, lower insurance recoveries related to the Geismar Incident, higher costs related to the merger and integration of ACMP into WPZ, and 2015 strategic alternative expenses. These decreases were partially offset by increased service revenues related to construction projects placed in service, $116 million higher olefin margins primarily due to our Geismar plant that returned to operations in 2015, and contributions from the operations acquired in our acquisition of ACMP.

Equity earnings (losses) changed favorably primarily due to the absence of equity losses from Bluegrass Pipeline and Moss Lake in 2014 and due to contributions from investments acquired in our acquisition of ACMP. In addition, equity earnings at Discovery increased $76 million primarily related to the completion of the Keathley Canyon Connector in early 2015. These changes were partially offset by $33 million of losses associated with our share of impairments recognized at equity investees in 2015. (See Note 6 – Investing Activities of Notes to Consolidated Financial Statements.)

Gain on remeasurement of equity-method investment reflects the 2014 gain recognized as a result of remeasuring to fair value the equity-method investment that we held before we acquired a controlling interest in ACMP. (See Note 2 – Acquisitions of Notes to Consolidated Financial Statements.)

Impairment of equity-method investments reflects 2015 impairment charges associated with certain equity-method investments. (See Note 6 – Investing Activitiesof Notes to Consolidated Financial Statements.)

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Other investing income (loss) – net changed unfavorably primarily due to lower interest income associated with a receivable related to the sale of certain former Venezuela assets.

Interest expense increased due to a $230 million increase in Interest incurred primarily due to new debt issuances in 2014 and 2015 and interest expense associated with debt assumed in conjunction with our acquisition of ACMP. This increase was partially offset by lower interest due to 2015 debt retirements and the absence of a $9 million transaction-related financing fee incurred in the second quarter of 2014 related to our acquisition of ACMP. In addition, Interest capitalized decreased $67 million primarily related to construction projects that have been placed into service. (See Note 2 – Acquisitions and Note 14 – Debt, Banking Arrangements, and Leases of Notes to Consolidated Financial Statements.)

Other income (expense) – net below Operating income(loss) changed favorably primarily due to a $43 million benefit related to an increase in AFUDC associated with an increase in spending on various Transco expansion projects and Constitution, a $14 million gain on early debt retirement in April 2015, and a $9 million contingency gain settlement.

Provision (benefit) for income taxes changed favorably primarily due to lower pretax income in 2015. See Note 8 – Provision (Benefit) for Income Taxes of Notes to Consolidated Financial Statements for a discussion of the effective tax rates compared to the federal statutory rate for both years.

The favorable change in Net income (loss) attributable to noncontrolling interests related to our investment in WPZ is primarily due to lower operating results at WPZ, our increased percentage of limited partner ownership of WPZ, and the impact of increased income allocated to the WPZ general partner, held by us, associated with IDRs. These changes are partially offset by an unfavorable change related to our investment in Gulfstar One associated with its start up in 2014.

Year-Over-Year Operating Results – Segments

We evaluate segment operating performance based upon Modified EBITDA. Note 19 – Segment Disclosures of Notes to Consolidated Financial Statements includes a reconciliation of this non-GAAP measure to Net income (loss). Management uses Modified EBITDA because it is an accepted financial indicator used by investors to compare company performance. In addition, management believes that this measure provides investors an enhanced perspective of the operating performance of our assets. Modified EBITDA should not be considered in isolation or as a substitute for a measure of performance prepared in accordance with GAAP.

Williams Partners

	Years Ended December 31,
	2016			2015			2014
	(Millions)
Service revenues	$	5,173		$	5,135		$	3,888
Product sales	2,318			2,196			3,521
Segment revenues	7,491			7,331			7,409
Product costs	(1,728		)	(1,779		)	(3,016		)
Other segment costs and expenses	(2,203		)	(2,229		)	(1,760		)
Net insurance recoveries – Geismar Incident	7			126			232
Impairment of certain assets	(457		)	(145		)	(52		)
Proportional Modified EBITDA of equity-method investments	754			699			431
Williams Partners Modified EBITDA	$	3,864		$	4,003		$	3,244
NGL margin	$	169		$	159		$	388
Olefin margin	337			226			110

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2016 vs. 2015

Modified EBITDA decreased primarily due to higher impairments, lower insurance recoveries associated with the Geismar Incident, and loss on sale associated with our Canadian operations. These decreases were partially offset by higher olefin margins related to the Geismar plant operating at higher production levels in 2016, lower segment costs and expenses, and higher earnings related to our equity-method investments, including the completion of the Keathley Canyon Connector at Discovery in the first quarter of 2015. Additionally, higher marketing margins, higher service revenues related to projects placed in service, and higher NGL margins improved Modified EBITDA.

The increase in Service revenues is primarily due to a $79 million increase in Transco’s natural gas transportation fee revenues primarily associated with expansion projects placed in service in 2015 and 2016 and a $31 million transportation and fractionation revenue increase associated with Williams’ Horizon liquids extraction plant in Canada. The Canadian operations were sold in late September 2016. These increases were partially offset by a decrease in gathering, processing, and fractionation revenue primarily due to lower volumes primarily in the Barnett Shale and Anadarko basin and a $15 million decrease in Transco’s storage revenue related to potential refunds associated with a ruling received in certain rate case litigation in 2016.

Product sales increased primarily due to:

• 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.

The decrease in Product costs includes:

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

• 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.

The decrease in Other segment costs and expenses is primarily due to lower operating costs and general and administrative expenses reflecting decreases in primarily labor-related and outside services costs resulting from our first-quarter 2016 workforce reductions and ongoing cost containment efforts and lower costs associated with general maintenance activities in the Marcellus Shale, as well as $43 million of lower ACMP Merger and transition-related expenses. Other items partially offsetting these decreases are as follows:

• $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.

Net insurance recoveries – Geismar Incident decreased reflecting $7 million of insurance proceeds received in 2016 compared to $126 million received in 2015.

Impairment of certain assets increased primarily due to 2016 impairments of $341 million associated with our Canadian operations and $63 million associated with certain Mid-Continent gathering assets as well as impairments or write-downs of other certain assets that may no longer be in use or are surplus in nature, partially offset by the absence of 2015 impairments of $94 million associated with previously capitalized project development costs for a gas processing plant and $20 million associated with certain surplus equipment within our Ohio Valley Midstream business. (See Note 17 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk of Notes to Consolidated Financial Statements.)

The increase in Proportional Modified EBITDA of equity-method investments is primarily due to a $30 million increase from Discovery primarily associated with higher fee revenues attributable to the completion of the Keathley Canyon Connector in the first quarter of 2015. Additionally, Caiman II contributed a $20 million increase resulting from higher volumes due to assets placed into service in 2015, OPPL contributed a $16 million increase primarily due to higher transportation volumes and lower expenses, and UEOM contributed an $11 million increase primarily associated with an increase in our ownership percentage. These increases were partially offset by an $29 million decrease from Appalachia Midstream Investments primarily due to lower fee revenues driven by lower rates, partially offset by lower impairments and higher volumes.

2015 vs. 2014

Modified EBITDA increased primarily due to the acquisition of ACMP during the third quarter of 2014 and increased fee revenue associated with contributions from new and expanded facilities, including Gulfstar One during the fourth quarter of 2014, in addition to resuming our Geismar operations and contributions related to the completion of the Keathley Canyon Connector at Discovery. Partially offsetting these increases to Modified EBITDA is a decrease in

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NGL margins as a result of a significant decline in commodity prices beginning in the fourth quarter of 2014 and lower insurance recoveries related to the Geismar Incident.

The increase in Service revenues is primarily due to $810 million additional revenues associated with a full year of ACMP operations in 2015 which includes a $72 million increase in the minimum volume commitment fees, $223 million in increased revenues associated with the start-up of operations at Gulfstar One during the fourth quarter of 2014, and a $155 million increase in Transco’s natural gas transportation fees due to new projects placed in service in 2015 and 2014. Additionally, service revenues reflect higher fees associated with increased volumes and additional contributions in the Northeast. Higher revenues in the Northeast include expanded gathering operations and processing, fractionation and transportation operations, contributing $59 million and $27 million of additional fees, respectively.

The decrease in Product sales includes:

• 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.

The decrease in Product costs includes:

• 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.

The increase in Other segment costs and expenses includes:

• 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.

The decrease in Net insurance recoveries – Geismar Incident is primarily due to the 2015 receipt of $126 million of insurance proceeds compared to $246 million received in 2014, partially offset by the absence of covered insurable

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expenses in excess of our retentions (deductibles) related to the Geismar Incident in 2015 compared to $14 million in 2014.

Impairment of certain assets increased primarily due to a 2015 $94 million impairment charge associated with previously capitalized project development costs for a gas processing plant. (See Note 17 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk of Notes to Consolidated Financial Statements.)

The increase in Proportional Modified EBITDA of equity-method investments is primarily due to a full year contribution of $160 million from investments associated with the acquisition of ACMP and a $103 million increase from Discovery associated with higher fee revenues attributable to the completion of the Keathley Canyon Connector in the first quarter of 2015. Additionally, Caiman II increased $21 million resulting from assets placed into service in 2014 and 2015, partially offset by the absence of business interruption insurance proceeds received in the prior year, and an $11 million decrease at Laurel Mountain. The decrease at Laurel Mountain was primarily due to $13 million of impairments and lower gathering fees due to lower gathering rates indexed to natural gas prices, partially offset by 24 percent higher volumes and an increase in our ownership percentage compared to the prior year.

Other

	Years Ended December 31,
	2016			2015			2014
	(Millions)
Other Modified EBITDA	$	(542	)	$	(112	)	$	(12	)

2016 vs. 2015

The unfavorable change in Modified EBITDA is primarily due to:

• The impairment and loss on sale of our Canadian operations totaling $438 million in 2016;

• An increase of $61 million of certain project development costs associated with the Canadian PDH facility that we began expensing in 2016;

• A $17 million increase in costs related to our evaluation of strategic alternatives.

These unfavorable changes are partially offset by:

• A $10 million gain on the sale of unused pipe in 2016;

• A $31 million decrease in ACMP merger and transition related costs;

• The absence of a $64 million write-off of previously capitalized project development costs for an olefins pipeline project in 2015.

2015 vs. 2014

Modified EBITDA decreased primarily due to:

• A $64 million write-off of previously capitalized project development costs for an olefins pipeline project in 2015;

• $30 million incurred in 2015 related to evaluating our strategic alternatives and the Merger Agreement with Energy Transfer;

• A $24 million increase associated with integration and re-alignment of resources following the ACMP acquisition and merger;

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• An unfavorable change in Proportional Modified EBITDA of equity-method investments primarily due to $104 million from our former equity-method investment in ACMP for the first half of 2014, partially offset by $19 million associated with our share of compensation costs triggered by the ACMP Acquisition recognized in July 2014 and the absence of $78 million for our share of the 2014 write-off of previously capitalized project development costs at Bluegrass Pipeline and Moss Lake.

These unfavorable changes are partially offset by:

• A $9 million contingency gain settlement recognized in fourth quarter of 2015;

•The absence of $18 million of project development costs incurred in 2014 relating to the Bluegrass Pipeline.

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Management’s Discussion and Analysis of Financial Condition and Liquidity

Overview

In 2016, we continued to focus upon growth in our businesses through disciplined investment and reducing our costs and funding needs. Examples of this activity included:

• 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).

Outlook

Fee-based businesses are becoming an even more significant component of our portfolio and serve to reduce the influence of commodity price fluctuations on our cash flows. We expect to benefit as continued growth in demand for low-cost natural gas is driven by increases in LNG exports, industrial demand, and power generation.

We believe we have, or have access to, the financial resources and liquidity necessary to meet our requirements for working capital, capital and investment expenditures, dividends and distributions, debt service payments, and tax payments, while maintaining a sufficient level of liquidity. In particular, as previously discussed in Company Outlook, our expected growth capital and investment expenditures total approximately $2.1 billion to $2.8 billion in 2017. Approximately $1.4 billion to $1.9 billion of our growth capital funding needs include Transco expansions and other interstate pipeline growth projects, most of which are fully contracted with firm transportation agreements. The remaining growth capital spending in 2017 primarily reflects investment in gathering and processing systems in the Northeast region limited primarily to known new producer volumes, including volumes that support Transco expansion projects including our Atlantic Sunrise project. In addition to growth capital and investment expenditures, we also remain committed to projects that maintain our assets for safe and reliable operations, as well as projects that meet legal, regulatory, and/or contractual commitments. We retain the flexibility to adjust planned levels of capital and investment expenditures in response to changes in economic conditions or business opportunities.

In January 2017, WPZ announced that it will redeem all of its $750 million6.125 percent senior notes due 2022 on February 23, 2017. In addition, we expect after-tax proceeds in excess of $2 billion from planned asset monetizations of Geismar and other select assets during 2017, which we expect Williams Partners to use for additional debt reduction and to fund capital and investment expenditures.

Liquidity

Based on our forecasted levels of cash flow from operations and other sources of liquidity, we expect to have sufficient liquidity to manage our businesses in 2017. Our internal and external sources of consolidated liquidity to fund working capital requirements, capital and investment expenditures, debt service payments, dividends and distributions, and tax payments include:

• 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.

WPZ is expected to fund its cash needs through its cash flows from operations and its credit facility and/or commercial paper program, as well as proceeds from planned asset monetizations as previously mentioned. WPZ also established a distribution reinvestment program (DRIP) in the third quarter of 2016.

We previously announced that we intended to reinvest approximately $1.2 billion into WPZ in 2017 via the DRIP, funded primarily by our reduced quarterly cash dividend which would have allowed us to annually retain approximately $1.3 billion for reinvestment. As part of the Financial Repositioning announced in January 2017, we discontinued our participation in the DRIP and expect to increase our regular quarterly cash dividend to $0.30 for the dividend to be paid in March 2017. (See Note 1 – General, Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies of Notes to Consolidated Financial Statements.)

We anticipate our more significant uses of cash to be:

• 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.

Potential risks associated with our planned levels of liquidity discussed above include those previously discussed in Company Outlook.

As of December 31, 2016, we had a working capital deficit (current liabilities, inclusive of $785 million in Long-term debt due within one year, in excess of current assets) of $1.487 billion. Our available liquidity is as follows:

	December 31, 2016
Available Liquidity	WPZ		WMB		Total
	(Millions)
Cash and cash equivalents	$	145	$	25	$	170
Capacity available under our $1.5 billion credit facility (1)			725		725
Capacity available to WPZ under its $3.5 billion credit facility, less amounts outstanding under its $3 billion commercial paper program (2)	3,407				3,407
	$	3,552	$	750	$	4,302

__________

(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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commercial paper program and credit facility during 2016 was $2.326 billion. At December 31, 2016, WPZ was 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 WPZ’s credit facility and WPZ’s commercial paper program. Borrowing capacity available under WPZ’s $3.5 billion credit facility as of February 20, 2017, was $3.5 billion.

As described in Note 14 – Debt, Banking Arrangements, and Leases of Notes to Consolidated Financial Statements, we have determined that we have net assets that are technically considered restricted in accordance with Rule 4-08(e) of Regulation S-X of the Securities and Exchange Commission in excess of 25 percent of our consolidated net assets. We do not expect this determination will impact our ability to pay dividends or meet future obligations as the terms of WPZ’s partnership agreement require it to make quarterly distributions of all available cash, as defined, to its unitholders.

WPZ Incentive Distribution Rights

As part of the Financial Repositioning, we permanently waived our right to incentive distributions from WPZ. (See Overview in Management’s Discussion and Analysis of Financial Condition and Results of Operations.)

Through December 31, 2016, our ownership interest in WPZ included the right to incentive distributions determined in accordance with WPZ’s partnership agreement. In connection with the sale of WPZ’s Canadian operations in the third quarter of 2016, we agreed to waive $150 million of incentive distributions otherwise payable by WPZ to us in the fourth quarter of 2016. (See Note 3 – Divestiture of Notes to Consolidated Financial Statements.)

We had agreed to temporarily waive incentive distributions of approximately $2 million per quarter in connection with WPZ’s acquisition of an approximate 13 percent additional interest in UEOM on June 10, 2015. The waiver would have continued through the quarter ending September 30, 2017.

We were required to pay a $428 million termination fee to WPZ, associated with the Termination Agreement (as described in Note 1 – General, Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies of Notes to Consolidated Financial Statements), which settled through a reduction of quarterly incentive distributions we are entitled to receive from WPZ (such reduction not to exceed $209 million per quarter). The November 2015, February 2016, and May 2016 distributions from WPZ were reduced by $209 million, $209 million, and $10 million, respectively, related to this termination fee.

Registrations

In September 2016, WPZ filed a registration statement for its new DRIP discussed above. In November 2016, WPZ received reinvested distributions of $260 million, of which $250 million related to us.

In May 2015, we filed a shelf registration statement, as a well-known seasoned issuer.

In February 2015, WPZ filed a shelf registration statement, as a well-known seasoned issuer, and WPZ also filed a shelf registration statement for the offer and sale from time to time of common units representing limited partner interests in WPZ having an aggregate offering price of up to $1 billion. These sales are to be made over a period of time and from time to time in transactions at prices which are market prices prevailing at the time of sale, prices related to market price, or at negotiated prices. Such sales are to be made pursuant to an equity distribution agreement between WPZ and certain banks who may act as sales agents or purchase for their own accounts as principals. During 2016 and 2015, WPZ received net proceeds of approximately $115 million and approximately $59 million, respectively, from equity issued under this registration.

Distributions from Equity-Method Investees

The organizational documents of entities in which we have an equity-method investment generally require distribution of their available cash to their members on a quarterly basis. In each case, available cash is reduced, in part, by reserves appropriate for operating their respective businesses. (See Note 6 – Investing Activities of Notes to Consolidated Financial Statements for our more significant equity-method investees.)

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Credit Ratings

Our ability to borrow money is impacted by our credit ratings and the credit ratings of WPZ. The current ratings are as follows:

	Rating Agency	Outlook	Senior Unsecured Debt Rating	Corporate Credit Rating
WMB:	S&P Global Ratings	Stable	BB	BB
	Moody’s Investors Service	Stable	Ba2	N/A
	Fitch Ratings	Stable	BB+	N/A
WPZ:	S&P Global Ratings	Stable	BBB-	BBB-
	Moody’s Investors Service	Stable	Baa3	N/A
	Fitch Ratings	Stable	BBB-	N/A

Considering our credit ratings as of December 31, 2016, we estimate that we could be required to provide up to $36 million in additional collateral of either cash or letters of credit with third parties under existing contracts.  At the present time, we have not provided any additional collateral to third parties but no assurance can be given that we will not be requested to provide collateral in the future. As of December 31, 2016, we estimate that a downgrade to a rating below investment-grade for WPZ could require it to provide up to $376 million in additional collateral of either cash or letters of credit with third parties under existing contracts.

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Sources (Uses) of Cash

The following table summarizes the sources (uses) of cash and cash equivalents for each of the periods presented (see Notes to Consolidated Financial Statements for the Notes referenced in the table):

	Cash Flow	Years Ended December 31,
	Category	2016			2015			2014
		(Millions)
Sources of cash and cash equivalents:
Operating activities - net	Operating	$	3,680		$	2,708		$	2,134
Proceeds from WPZ’s credit-facility borrowings	Financing	3,250			3,832			1,646
Proceeds from our credit-facility borrowings	Financing	2,280			2,097			1,040
Proceeds from sale of Canadian operations (see Note 3)	Investing	1,020			—			—
Proceeds from WPZ’s debt offerings (see Note 14)	Financing	998			3,842			2,740
Distributions from unconsolidated affiliates in excess of cumulative earnings	Investing	472			404			206
Proceeds from equity offerings	Financing	123			86			3,471
Contributions from noncontrolling interests	Financing	29			111			340
Special distribution from Gulfstream (see Note 6)	Financing	—			396			—
Proceeds from our debt offerings	Financing	—			—			1,895
Proceeds from WPZ’s commercial paper - net	Financing	—			—			572
Uses of cash and cash equivalents:
Payments on WPZ’s credit-facility borrowings	Financing	(4,560		)	(3,162		)	(1,156		)
Payments on our credit-facility borrowings	Financing	(2,155		)	(1,817		)	(670		)
Capital expenditures	Investing	(2,051		)	(3,167		)	(4,031		)
Quarterly dividends on common stock	Financing	(1,261		)	(1,836		)	(1,412		)
Dividends and distributions to noncontrolling interests	Financing	(940		)	(942		)	(840		)
Payments of WPZ’s commercial paper - net	Financing	(409		)	(306		)	—
Payments on WPZ’s debt retirements (see Note 14)	Financing	(375		)	(1,533		)	—
Purchases of and contributions to equity-method investments	Investing	(177		)	(595		)	(482		)
Contribution to Gulfstream for repayment of debt (see Note 6)	Financing	(148		)	(248		)	—
Purchases of businesses, net of cash acquired	Investing	—			(112		)	(5,958		)
Other sources / (uses) - net	Financing and Investing	294			102			64
Increase (decrease) in cash and cash equivalents		$	70		$	(140	)	$	(441	)

Operating activities

The factors that determine operating activities are largely the same as those that affect Net income (loss), with the exception of noncash items such as Depreciation and amortization, Provision (benefit) for deferred income taxes, Impairment of goodwill, Impairment of equity-method investments, Impairment of and net (gain) loss on sale of assets and businesses, andGain on remeasurement of equity-method investment.

Our Net cash provided (used) by operating activitiesin 2016 increased from 2015 primarily due to the impact of net favorable changes in operating working capital and receipts from contract restructurings.

OurNet cash provided (used) by operating activities in 2015 increased from 2014 primarily due to the impact of net favorable changes in operating working capital and the absence of contributions from ACMP for the first six months of 2014.

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Off-Balance Sheet Arrangements and Guarantees of Debt or Other Commitments

We have various other guarantees and commitments which are disclosed in Note 4 – Variable Interest Entities, Note 11 – Property, Plant, and Equipment, Note 14 – Debt, Banking Arrangements, and Leases, Note 17 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk, and Note 18 – Contingent Liabilities and Commitments of Notes to Consolidated Financial Statements. We do not believe these guarantees and commitments or the possible fulfillment of them will prevent us from meeting our liquidity needs.

Contractual Obligations

The table below summarizes the maturity dates of our contractual obligations at December 31, 2016:

	2017		2018 - 2019		2020 - 2021		Thereafter		Total
					(Millions)
Long-term debt: (1)(2)
Principal	$	785	$	1,382	$	3,767	$	17,506	$	23,440
Interest	1,099		2,132		1,928		7,947		13,106
Commercial paper	93		—		—		—		93
Operating leases	66		109		81		90		346
Purchase obligations (3)	1,074		733		646		320		2,773
Other obligations (4)(5)	2		1		1		1		5
Total	$	3,119	$	4,357	$	6,423	$	25,864	$	39,763

______________

(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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results for assumptions such as returns on plan assets, interest rates, retirement rates, mortality, and other significant assumptions or by changes to current legislation and regulations.

(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.

Effects of Inflation

Our operations have historically not been materially affected by inflation. Approximately 39 percent of our gross property, plant, and equipment is comprised of our interstate natural gas pipeline assets. They are subject to regulation, which limits recovery to historical cost. While amounts in excess of historical cost are not recoverable under current FERC practices, we anticipate being allowed to recover and earn a return based on increased actual cost incurred to replace existing assets. Cost-based regulations, along with competition and other market factors, may limit our ability to recover such increased costs. For our gathering and processing assets, operating costs are influenced to a greater extent by both competition for specialized services and specific price changes in crude oil and natural gas and related commodities than by changes in general inflation. Crude oil, natural gas, and NGL prices are particularly sensitive to the market perceptions concerning the supply and demand balance in the near future, as well as general economic conditions. However, our exposure to certain of these price changes is reduced through the fee-based nature of certain of our services and the use of hedging instruments.

Environmental

We are a participant in certain environmental activities in various stages including assessment studies, cleanup operations, and/or remedial processes at certain sites, some of which we currently do not own (see Note 18 – Contingent Liabilities and Commitments of Notes to Consolidated Financial Statements). We are monitoring these sites in a coordinated effort with other potentially responsible parties, the EPA, or other governmental authorities. We are jointly and severally liable along with unrelated third parties in some of these activities and solely responsible in others. Current estimates of the most likely costs of such activities are approximately $38 million, all of which are included in Accrued liabilities and Regulatory liabilities, deferred income, and other on the Consolidated Balance Sheet at December 31, 2016. We will seek recovery of approximately $9 million of these accrued costs through future natural gas transmission rates. The remainder of these costs will be funded from operations. During 2016, we paid approximately$6 million for cleanup and/or remediation and monitoring activities. We expect to pay approximately $9 million in 2017 for these activities. Estimates of the most likely costs of cleanup are generally based on completed assessment studies, preliminary results of studies, or our experience with other similar cleanup operations. At December 31, 2016, certain assessment studies were still in process for which the ultimate outcome may yield different estimates of most likely costs. Therefore, the actual costs incurred will depend on the final amount, type, and extent of contamination discovered at these sites, the final cleanup standards mandated by the EPA or other governmental authorities, and other factors.

In March 2008, the EPA promulgated a new, lower National Ambient Air Quality Standard (NAAQS) for ground-level ozone. In May 2012, the EPA completed designation of new eight-hour ozone nonattainment areas. Several Transco facilities are located in 2008 ozone nonattainment areas. In December 2014, the EPA proposed to further reduce the ground-level ozone NAAQS from the March 2008 levels and subsequently finalized a rule on October 1, 2015. We are monitoring the rule's implementation as the reduction will trigger additional federal and state regulatory actions that may impact our operations. To date, no federal actions have been proposed to mandate additional emission controls at these facilities. Pursuant to recently finalized state regulatory actions associated with implementation of the 2008 ozone standard, we anticipate that some facilities may be subject to increased controls within five years. Implementation of the regulations is expected to result in impacts to our operations and increase the cost of additions to Property, plant, and equipment – net on the Consolidated Balance Sheetfor both new and existing facilities in affected areas. We are unable at this time to estimate with any certainty the cost of additions that may be required to meet the regulations.

On January 22, 2010, the EPA set a new one-hour nitrogen dioxide (NO2) NAAQS. The effective date of the new NO2 standard was April 12, 2010. On January 20, 2012, the EPA determined pursuant to available information that no area in the country is violating the 2010 NO2 NAAQS and thus designated all areas of the country as “unclassifiable/attainment.” Also, at that time the EPA noted its plan to deploy an expanded NO2 monitoring network beginning in 2013. However on October 5, 2012, the EPA proposed a graduated implementation of the monitoring network between

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January 1, 2014 and January 1, 2017. Once three years of data is collected from the new monitoring network, the EPA will reassess attainment status with the one-hour NO2 NAAQS. Until that time, the EPA or states may require ambient air quality modeling on a case by case basis to demonstrate compliance with the NO2 standard. Because we are unable to predict the outcome of the EPA’s or states’ future assessment using the new monitoring network, we are unable to estimate the cost of additions that may be required to meet this regulation.

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

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Item 7A. Quantitative and Qualitative Disclosures About Market Risk

Interest Rate Risk

Our current interest rate risk exposure is related primarily to our debt portfolio. Our debt portfolio is primarily comprised of fixed rate debt, which mitigates the impact of fluctuations in interest rates. Any borrowings under the credit facilities and any issuances under WPZ’s commercial paper program could be at a variable interest rate and could expose us to the risk of increasing interest rates. The maturity of our long-term debt portfolio is partially influenced by the expected lives of our operating assets. (See Note 14 – Debt, Banking Arrangements, and Leases of Notes to Consolidated Financial Statements.)

The tables below provide information by maturity date about our interest rate risk-sensitive instruments as of December 31, 2016 and 2015. Long-term debt in the tables represents principal cash flows, net of (discount) premium and debt issuance costs, and weighted-average interest rates by expected maturity dates. The fair value of our publicly traded long-term debt is valued using indicative year-end traded bond market prices. Private debt is valued based on market rates and the prices of similar securities with similar terms and credit ratings.

		2017			2018			2019			2020			2021			Thereafter (1)			Total		Fair Value December 31, 2016
	(Millions)
Long-term debt, including current portion:
Fixed rate	$	785		$	500		$	32		$	2,121		$	871		$	17,475		$	21,784	$	22,465
Interest rate		5.2	%		5.2	%		5.2	%		5.2	%		5.2	%		5.6	%
Variable rate	$	—		$	850		$	—		$	775		$	—		$	—		$	1,625	$	1,625
Interest rate (3)
Commercial paper:
Variable rate	$	93		$	—		$	—		$	—		$	—		$	—		$	93	$	93
Interest rate (4)
		2016			2017			2018			2019			2020			Thereafter (1)			Total		Fair Value December 31, 2015
	(Millions)
Long-term debt, including current portion: (2)
Fixed rate	$	375	(*)	$	785		$	500		$	32		$	2,121		$	17,364		$	21,177	$	16,796
Interest rate		5.1	%		5.1	%		5.0	%		5.0	%		5.0	%		5.5	%
Variable rate	$	—		$	—		$	850		$	—		$	1,960		$	—		$	2,810	$	2,810
Interest rate (5)
Commercial paper:
Variable rate	$	499		$	—		$	—		$	—		$	—		$	—		$	499	$	499
Interest rate (4)
_____________
(*) $200 million presented as long-term debt at December 31, 2015, due to WPZ’s intent and ability to refinance.

__________________

(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.

34

(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.

Commodity Price Risk

We are exposed to the impact of fluctuations in the market price of NGLs, olefins, and natural gas, as well as other market factors, such as market volatility and energy commodity price correlations. We are exposed to these risks in connection with our owned energy-related assets, our long-term energy-related contracts, and limited proprietary trading activities. Our management of the risks associated with these market fluctuations includes maintaining sufficient liquidity, as well as using various derivatives and nonderivative energy-related contracts. The fair value of derivative contracts is subject to many factors, including changes in energy commodity market prices, the liquidity and volatility of the markets in which the contracts are transacted, and changes in interest rates. At December 31, 2016 and 2015, our derivative activity was not material. (See Note 17 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk of Notes to Consolidated Financial Statements.)

Foreign Currency Risk

In September 2016, we disposed of our Canadian operations, which comprised substantially all of our foreign operations. (See Note 3 – Divestiture of Notes to Consolidated Financial Statements.)

35

Item 8. Financial Statements and Supplementary Data

Report of Independent Registered Public Accounting Firm

The Board of Directors and Stockholders of

The Williams Companies, Inc.

We have audited the accompanying consolidated balance sheet of The Williams Companies, Inc. as of December 31, 2016 and 2015, and the related consolidated statements of operations, comprehensive income (loss), changes in equity and cash flows for each of the three years in the period ended December 31, 2016. Our audits also included the financial statement schedules listed in the index at Item 9.01(d) in this Current Report Form 8-K. These financial statements and schedules are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements and schedules based on our audits. We did not audit the financial statements of Gulfstream Natural Gas System, L.L.C. (“Gulfstream”), a limited liability corporation in which the Company has a 50 percent interest. In the consolidated financial statements, the Company’s investment in Gulfstream was $261million and $293 million as of December 31, 2016 and 2015, respectively, and the Company’s equity earnings in the net income of Gulfstream were $69million and $65 million, respectively, for the years then ended. For the periods indicated above, Gulfstream’s financial statements were audited by other auditors whose report has been furnished to us, and our opinion, insofar as it relates to the amounts included for Gulfstream for 2016 and 2015, is based solely on the report of the other auditors. 

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits and the report of other auditors provide a reasonable basis for our opinion.

In our opinion, based on our audits and, for 2016 and 2015, the report of other auditors, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of The Williams Companies, Inc. at December 31, 2016 and 2015, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 2016, in conformity with U.S. generally accepted accounting principles. Also, in our opinion, the related financial statement schedules, when considered in relation to the basic financial statements taken as a whole, present fairly in all material respects the information set forth therein.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), The Williams Companies, Inc.'s internal control over financial reporting as of December 31, 2016, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) and our report dated February 22, 2017 expressed an unqualified opinion thereon.

/s/ Ernst & Young LLP

Tulsa, Oklahoma

February 22, 2017,

except as it relates to the change in segments described under the Description of Business heading in Note 1 and in Note 19, the changes due to the application of Accounting Standards Update 2016-09 described under the Accounting standards issued and adopted heading in Note 1, and the other matters disclosed in Note 20, as to which the date is May 25, 2017

36

Report of Independent Registered Public Accounting Firm

To the Members of Gulfstream Natural Gas System, L.L.C.

We have audited the balance sheets of Gulfstream Natural Gas System, L.L.C. (the “Company”) as of December 31, 2016 and 2015, and the related statements of operations, comprehensive income, cash flows, and members’ equity for each of the three years in the period ended December 31, 2016. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States) and in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, such financial statements present fairly, in all material respects, the financial position of Gulfstream Natural Gas System, L.L.C. as of December 31, 2016 and 2015, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2016, in conformity with accounting principles generally accepted in the United States of America.

/s/ DELOITTE & TOUCHE LLP

Houston, Texas

February 22, 2017

37

The Williams Companies, Inc.

Consolidated Statement of Operations

		Years Ended December 31,
		2016			2015			2014
	(Millions, except per-share amounts)
Revenues:
Service revenues		$	5,171		$	5,164		$	4,116
Product sales		2,328			2,196			3,521
Total revenues		7,499			7,360			7,637
Costs and expenses:
Product costs		1,725			1,779			3,016
Operating and maintenance expenses		1,580			1,655			1,492
Depreciation and amortization expenses		1,763			1,738			1,176
Selling, general, and administrative expenses		723			741			661
Impairment of goodwill (Note 17)		—			1,098			—
Impairment of certain assets (Note 17)		873			209			52
Net insurance recoveries – Geismar Incident		(7		)	(126		)	(232		)
Other (income) expense – net		142			40			(97		)
Total costs and expenses		6,799			7,134			6,068
Operating income (loss)		700			226			1,569
Equity earnings (losses)		397			335			144
Gain on remeasurement of equity-method investment (Note 2)		—			—			2,544
Impairment of equity-method investments (Note 17)		(430		)	(1,359		)	—
Other investing income (loss) – net		63			27			43
Interest incurred		(1,217		)	(1,118		)	(888		)
Interest capitalized		38			74			141
Other income (expense) – net		74			102			31
Income (loss) from continuing operations before income taxes		(375		)	(1,713		)	3,584
Provision (benefit) for income taxes		(25		)	(399		)	1,249
Income (loss) from continuing operations		(350		)	(1,314		)	2,335
Income (loss) from discontinued operations		—			—			4
Net income (loss)		(350		)	(1,314		)	2,339
Less: Net income (loss) attributable to noncontrolling interests		74			(743		)	225
Net income (loss) attributable to The Williams Companies, Inc.		$	(424	)	$	(571	)	$	2,114
Amounts attributable to The Williams Companies, Inc.:
Income (loss) from continuing operations		$	(424	)	$	(571	)	$	2,110
Income (loss) from discontinued operations		—			—			4
Net income (loss)		$	(424	)	$	(571	)	$	2,114
Basic earnings (loss) per common share:
Income (loss) from continuing operations		$	(.57	)	$	(.76	)	$	2.93
Income (loss) from discontinued operations		—			—			.01
Net income (loss)		$	(.57	)	$	(.76	)	$	2.94
Weighted-average shares (thousands)		750,673			749,271			719,325
Diluted earnings (loss) per common share:
Income (loss) from continuing operations		$	(.57	)	$	(.76	)	$	2.91
Income (loss) from discontinued operations		—			—			.01
Net income (loss)		$	(.57	)	$	(.76	)	$	2.92
Weighted-average shares (thousands)		750,673			749,271			723,641

See accompanying notes.

38

The Williams Companies, Inc.

Consolidated Statement of Comprehensive Income (Loss)

	Years Ended December 31,
	2016			2015			2014
	(Millions)
Net income (loss)	$	(350	)	$	(1,314	)	$	2,339
Other comprehensive income (loss):
Cash flow hedging activities:
Net unrealized gain (loss) from derivative instruments, net of taxes of ($1) in 2016	4			6			—
Reclassifications into earnings of net derivative instruments (gain) loss, net of taxes of $1 in 2016 and 2015	(2		)	(6		)	—
Foreign currency translation activities:
Foreign currency translation adjustments, net of taxes of ($37), $31, and $18 in 2016, 2015, and 2014, respectively	50			(204		)	(96		)
Reclassification into earnings upon sale of foreign entities, net of taxes of ($36) in 2016	119			—			—
Pension and other postretirement benefits:
Prior service credit (cost) arising during the year (Note 10)	—			—			(1		)
Amortization of prior service cost (credit) included in net periodic benefit cost, net of taxes of $2, $3, and $3 in 2016, 2015, and 2014, respectively	(4		)	(3		)	(5		)
Net actuarial gain (loss) arising during the year, net of taxes of $8, ($5) and $60 in 2016, 2015, and 2014, respectively (Note 10)	(15		)	8			(100		)
Amortization of actuarial (gain) loss included in net periodic benefit cost, net of taxes of ($12), ($18), and ($15) in 2016, 2015, and 2014, respectively	20			28			26
Other comprehensive income (loss)	172			(171		)	(176		)
Comprehensive income (loss)	(178		)	(1,485		)	2,163
Less: Comprehensive income (loss) attributable to noncontrolling interests	143			(813		)	206
Comprehensive income (loss) attributable to The Williams Companies, Inc.	$	(321	)	$	(672	)	$	1,957

See accompanying notes.

39

The Williams Companies, Inc.

Consolidated Balance Sheet

	December 31,
	2016			2015
	(Millions, except per-share amounts)
ASSETS
Current assets:
Cash and cash equivalents	$	170		$	100
Trade accounts and other receivables (net of allowance of $6 at December 31, 2016 and $3 at December 31, 2015)	938			1,041
Inventories	138			127
Other current assets and deferred charges	216			259
Total current assets	1,462			1,527
Investments	6,701			7,336
Property, plant, and equipment – net	28,428			29,579
Intangible assets – net of accumulated amortization	9,663			10,017
Regulatory assets, deferred charges, and other	581			561
Total assets	$	46,835		$	49,020
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable	$	623		$	744
Accrued liabilities	1,448			1,078
Commercial paper	93			499
Long-term debt due within one year	785			176
Total current liabilities	2,949			2,497
Long-term debt	22,624			23,812
Deferred income tax liabilities	4,238			4,218
Regulatory liabilities, deferred income, and other	2,978			2,268
Contingent liabilities and commitments (Note 18)
Equity:
Stockholders’ equity:
Common stock (960 million shares authorized at $1 par value; 785 million shares issued at December 31, 2016 and 784 million shares issued at December 31, 2015)	785			784
Capital in excess of par value	14,887			14,807
Retained deficit	(9,649		)	(7,960		)
Accumulated other comprehensive income (loss)	(339		)	(442		)
Treasury stock, at cost (35 million shares of common stock)	(1,041		)	(1,041		)
Total stockholders’ equity	4,643			6,148
Noncontrolling interests in consolidated subsidiaries	9,403			10,077
Total equity	14,046			16,225
Total liabilities and equity	$	46,835		$	49,020

See accompanying notes.

40

The Williams Companies, Inc.

Consolidated Statement of Changes in Equity

	The Williams Companies, Inc., Stockholders
	Common Stock		Capital in Excess of Par Value			Retained Deficit			Accumulated Other Comprehensive Income (Loss)			Treasury Stock			Total Stockholders’ Equity			Noncontrolling Interests			Total Equity
	(Millions)
Balance – December 31, 2013	$	718	$	11,599		$	(6,248	)	$	(164	)	$	(1,041	)	$	4,864		$	4,057		$	8,921
Net income (loss)	—		—			2,114			—			—			2,114			225			2,339
Other comprehensive income (loss)	—		—			—			(157		)	—			(157		)	(19		)	(176		)
Issuance of common stock for acquisition of business (Note 15)	61		3,317			—			—			—			3,378			—			3,378
Noncontrolling interest resulting from acquisition of business (Note 2)	—		—			—			—			—			—			7,502			7,502
Cash dividends – common stock (Note 15)	—		—			(1,412		)	—			—			(1,412		)	—			(1,412		)
Dividends and distributions to noncontrolling interests	—		—			—			—			—			—			(840		)	(840		)
Stock-based compensation and related common stock issuances, net of tax	3		85			—			—			—			88			—			88
Sales of limited partner units of Williams Partners L.P.	—		—			—			—			—			—			55			55
Changes in ownership of consolidated subsidiaries, net	—		(73		)	—			(20		)	—			(93		)	137			44
Contributions from noncontrolling interests	—		—			—			—			—			—			340			340
Deconsolidation of Bluegrass Pipeline (Note 6)	—		—			—			—			—			—			(63		)	(63		)
Other	—		(3		)	(2		)	—			—			(5		)	1			(4		)
Net increase (decrease) in equity	64		3,326			700			(177		)	—			3,913			7,338			11,251
Balance – December 31, 2014	782		14,925			(5,548		)	(341		)	(1,041		)	8,777			11,395			20,172
Net income (loss)	—		—			(571		)	—			—			(571		)	(743		)	(1,314		)
Other comprehensive income (loss)	—		—			—			(101		)	—			(101		)	(70		)	(171		)
Cash dividends – common stock (Note 15)	—		—			(1,836		)	—			—			(1,836		)	—			(1,836		)
Dividends and distributions to noncontrolling interests	—		—			—			—			—			—			(942		)	(942		)
Stock-based compensation and related common stock issuances, net of tax	2		28			—			—			—			30			—			30
Sales of limited partner units of Williams Partners L.P.	—		—			—			—			—			—			59			59
Changes in ownership of consolidated subsidiaries, net	—		(160		)	—			—			—			(160		)	254			94
Contributions from noncontrolling interests	—		—			—			—			—			—			111			111
Other	—		14			(5		)	—			—			9			13			22
Net increase (decrease) in equity	2		(118		)	(2,412		)	(101		)	—			(2,629		)	(1,318		)	(3,947		)
Balance – December 31, 2015	784		14,807			(7,960		)	(442		)	(1,041		)	6,148			10,077			16,225
Net income (loss)	—		—			(424		)	—			—			(424		)	74			(350		)
Other comprehensive income (loss)	—		—			—			103			—			103			69			172
Cash dividends – common stock (Note 15)	—		—			(1,261		)	—			—			(1,261		)	—			(1,261		)
Dividends and distributions to noncontrolling interests	—		—			—			—			—			—			(940		)	(940		)
Stock-based compensation and related common stock issuances, net of tax	1		56			—			—			—			57			—			57
Sales of limited partner units of Williams Partners L.P.	—		—			—			—			—			—			114			114
Changes in ownership of consolidated subsidiaries, net	—		12			—			—			—			12			(18		)	(6		)
Contributions from noncontrolling interests	—		—			—			—			—			—			29			29
Other	—		12			(4		)	—			—			8			(2		)	6
Net increase (decrease) in equity	1		80			(1,689		)	103			—			(1,505		)	(674		)	(2,179		)
Balance – December 31, 2016	$	785	$	14,887		$	(9,649	)	$	(339	)	$	(1,041	)	$	4,643		$	9,403		$	14,046

See accompanying notes.

41

The Williams Companies, Inc.

Consolidated Statement of Cash Flows

	Years Ended December 31,
	2016			2015			2014
	(Millions)
OPERATING ACTIVITIES:
Net income (loss)	$	(350	)	$	(1,314	)	$	2,339
Adjustments to reconcile to net cash provided (used) by operating activities:
Depreciation and amortization	1,763			1,738			1,176
Provision (benefit) for deferred income taxes	(26		)	(337		)	1,264
Impairment of goodwill	—			1,098			—
Impairment of equity-method investments	430			1,359			—
Impairment of and net (gain) loss on sale of assets and businesses	918			215			67
Amortization of stock-based awards	73			82			53
Gain on remeasurement of equity-method investment	—			—			(2,544		)
Cash provided (used) by changes in current assets and liabilities:
Accounts and notes receivable	82			39			(276		)
Inventories	(25		)	105			(36		)
Other current assets and deferred charges	(4		)	4			(44		)
Accounts payable	35			(88		)	(8		)
Accrued liabilities	512			54			(184		)
Other, including changes in noncurrent assets and liabilities	272			(247		)	327
Net cash provided (used) by operating activities	3,680			2,708			2,134
FINANCING ACTIVITIES:
Proceeds from (payments of) commercial paper – net	(409		)	(306		)	572
Proceeds from long-term debt	6,528			9,772			7,321
Payments of long-term debt	(7,091		)	(6,516		)	(1,828		)
Proceeds from issuance of common stock	9			27			3,416
Proceeds from sale of limited partner units of consolidated partnership	114			59			55
Dividends paid	(1,261		)	(1,836		)	(1,412		)
Dividends and distributions paid to noncontrolling interests	(940		)	(942		)	(840		)
Contributions from noncontrolling interests	29			111			340
Payments for debt issuance costs	(9		)	(35		)	(40		)
Special distribution from Gulfstream	—			396			—
Contribution to Gulfstream for repayment of debt	(148		)	(248		)	—
Other – net	(16		)	(31		)	(2		)
Net cash provided (used) by financing activities	(3,194		)	451			7,582
INVESTING ACTIVITIES:
Property, plant, and equipment:
Capital expenditures (1)	(2,051		)	(3,167		)	(4,031		)
Net proceeds from dispositions	30			3			34
Proceeds from sale of businesses, net of cash divested	1,020			—			—
Purchases of businesses, net of cash acquired	—			(112		)	(5,958		)
Purchases of and contributions to equity-method investments	(177		)	(595		)	(482		)
Distributions from unconsolidated affiliates in excess of cumulative earnings	472			404			206
Other – net	290			168			74
Net cash provided (used) by investing activities	(416		)	(3,299		)	(10,157		)
Increase (decrease) in cash and cash equivalents	70			(140		)	(441		)
Cash and cash equivalents at beginning of year	100			240			681
Cash and cash equivalents at end of year	$	170		$	100		$	240
_________
(1) Increases to property, plant, and equipment	$	(1,912	)	$	(3,024	)	$	(3,916	)
Changes in related accounts payable and accrued liabilities	(139		)	(143		)	(115		)
Capital expenditures	$	(2,051	)	$	(3,167	)	$	(4,031	)

See accompanying notes.

42

The Williams Companies, Inc.

Notes to Consolidated Financial Statements

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

General

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

Financial Repositioning

In January 2017, we announced agreements with Williams Partners L.P. (WPZ), wherein we permanently waived the general partner’s incentive distribution rights (IDRs) and converted our 2 percent general partner interest in WPZ to a non-economic interest in exchange for 289 million newly issued WPZ common units. Pursuant to this agreement, we also purchased approximately 277 thousand WPZ common units for $10 million. Additionally, we purchased approximately 59 million common units of WPZ at a price of $36.08586 per unit in a private placement transaction, funded with proceeds from our equity offering (see Note 15 – Stockholders’ Equity). According to the terms of this agreement, following WPZ’s quarterly distribution in February 2017, we paid additional consideration of approximately $50 millionto WPZ for these units. Following these transactions, we own a 74 percent limited partner interest in WPZ.

Termination of WPZ Merger Agreement

On May 12, 2015, we entered into an agreement for a unit-for-stock transaction whereby we would have acquired all of the publicly held outstanding common units of WPZ in exchange for shares of our common stock (WPZ Merger Agreement).

On September 28, 2015, we entered into a Termination Agreement and Release (Termination Agreement), terminating the WPZ Merger Agreement. Under the terms of the Termination Agreement, we were required to pay a $428 million termination fee to WPZ, at which time we owned approximately 60 percent, including the interests of the general partner and IDRs. Such termination fee settled through a reduction of quarterly incentive distributions we were entitled to receive from WPZ (such reduction not to exceed $209 million per quarter). The distributions from WPZ in November 2015, February 2016, and May 2016 were reduced by $209 million, $209 million, and $10 million, respectively, related to this termination fee.

ACMP Merger

On February 2, 2015, Williams Partners L.P. merged with and into Access Midstream Partners, L.P. (ACMP Merger). For the purpose of these financial statements and notes, WPZ refers to the renamed merged partnership, while Pre-merger Access Midstream Partners, L.P. (ACMP) and Pre-merger Williams Partners L.P. (Pre-merger WPZ) refer to the separate partnerships prior to the consummation of the ACMP Merger and subsequent name change. The net assets of Pre-merger WPZ and ACMP were combined at our historical basis. Our basis in ACMP reflected our business combination accounting resulting from acquiring control of ACMP on July 1, 2014.

Description of Business

We are a Delaware corporation whose common stock is listed and traded on the New York Stock Exchange. Our operations are located principally in the United States. We have one reportable segment, Williams Partners. All remaining business activities are included in Other. For periods after the ACMP Acquisition (see Note 2 – Acquisitions), the acquired ACMP business is reported within Williams Partners. For periods prior to the ACMP Acquisition, the results associated with our former equity-method investment in ACMP are reported within Other.

43

The Williams Companies, Inc.

Notes to Consolidated Financial Statements – (Continued)

Williams Partners

Williams Partners consists of our consolidated master limited partnership, WPZ, and primarily includes gas pipeline and midstream businesses.

WPZ’s gas pipeline businesses primarily consist of two interstate natural gas pipelines, which are Transcontinental Gas Pipe Line Company, LLC (Transco) and Northwest Pipeline LLC (Northwest Pipeline), and several joint venture investments in interstate and intrastate natural gas pipeline systems, including a 50 percent equity-method investment in Gulfstream Natural Gas System, L.L.C. (Gulfstream), and a 41 percent interest in Constitution Pipeline Company, LLC (Constitution) (a consolidated entity), which is under development.

WPZ’s midstream businesses primarily consist of (1) natural gas gathering, treating, compression, and processing; (2) natural gas liquid (NGL) fractionation, storage, and transportation; (3) crude oil production handling and transportation; and (4) olefins production. The primary service areas are concentrated in major producing basins in Colorado, Texas, Oklahoma, Kansas, New Mexico, Wyoming, the Gulf of Mexico, Louisiana, Pennsylvania, West Virginia, New York, and Ohio which include the Barnett, Eagle Ford, Haynesville, Marcellus, Niobrara, and Utica Shale plays as well as the Mid-Continent region.

The midstream businesses include equity-method investments in natural gas gathering and processing assets and NGL fractionation and transportation assets, including a 62 percent equity-method investment in Utica East Ohio Midstream, LLC (UEOM), a 50 percent equity-method investment in the Delaware basin gas gathering system (DBJV) in the Mid-Continent region, a 69 percent equity-method investment in Laurel Mountain Midstream, LLC (Laurel Mountain), a 58 percent equity-method investment in Caiman Energy II, LLC (Caiman II), a 60 percent equity-method investment in Discovery Producer Services, LLC (Discovery), a 50 percent equity-method investment in Overland Pass Pipeline, LLC (OPPL), and Appalachia Midstream Services, LLC, which owns equity-method investments with an approximate average 41 percent interest in multiple gathering systems in the Marcellus Shale (Appalachia Midstream Investments).

The midstream businesses also included our Canadian midstream operations, which were comprised of an oil sands offgas processing plant located near Fort McMurray, Alberta, and an NGL/olefin fractionation facility at Redwater, Alberta. In September 2016, we completed the sale of our Canadian operations. (See Note 3 – Divestiture.)

Other

Our former Williams NGL & Petchem Services segment included certain domestic olefins pipeline assets as well as certain Canadian assets, which included a liquids extraction plant located near Fort McMurray, Alberta, that began operations in March 2016, and a propane dehydrogenation facility which was under development. In September 2016, the Canadian assets were sold. (See Note 3 – Divestiture.) Considering this and in conjunction with an organizational realignment effective January 1, 2017, the remaining assets are now reported in Other. Other also includes minor business activities that are not operating segments, as well as corporate operations. All segment disclosures have been recast for this segment change.

Basis of Presentation

Canada Dropdown

In February 2014, we contributed certain Canadian operations to Pre-merger WPZ (Canada Dropdown) for total consideration of $56 million of cash from Pre-merger WPZ (including a $31 million post-closing adjustment received in the second quarter of 2014), 25,577,521 Pre-merger WPZ Class D limited-partner units, and an increase in the capital account of its general partner to allow us to maintain our 2 percent general partner interest. In lieu of cash distributions, the Class D units received quarterly distributions of additional paid-in-kind Class D units.

In October 2014, a purchase price adjustment was finalized whereby we paid $56 million in cash to Pre-merger WPZ in the fourth quarter and waived $2 million in payment of IDRs with respect to the November 2014 distribution.

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Notes to Consolidated Financial Statements – (Continued)

Consolidated master limited partnership

As of December 31, 2016, we owned approximately 60 percent of the interests in WPZ, a variable interest entity (VIE) (see Note 4 – Variable Interest Entities), including the interests of the general partner, which are wholly owned by us, and IDRs.

During 2016, WPZ issued 3,273,601 common units pursuant to an equity distribution agreement between WPZ and certain banks resulting in net proceeds of $115 million. WPZ also implemented a distribution reinvestment program in the third quarter of 2016 resulting in 7,891,414 common units issued associated with reinvested distributions of $260 million, of which $250 million related to our participation. In addition, in August 2016, WPZ completed an equity issuance of 6,975,446 common units sold to us in a private placement transaction for an aggregate purchase price of $250 million.

The above transactions, WPZ’s quarterly distribution of additional paid-in-kind Class B units to us, and other equity issuances by WPZ had the combined net impact of decreasing Noncontrolling interests in consolidated subsidiaries by $18 million, and increasing Capital in excess of par value by $12 million and Deferred income tax liabilities by $6 million in the Consolidated Balance Sheet.

WPZ is self-funding and maintains separate lines of bank credit and cash management accounts and also has a commercial paper program. (See Note 14 – Debt, Banking Arrangements, and Leases.) Cash distributions from WPZ to all partners, including us, are governed by WPZ’s partnership agreement.

Discontinued operations

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

Significant risks and uncertainties

We have announced plans to monetize our olefins production plant in Geismar, Louisiana, as well as other select assets that are not core to our strategy. As we pursue these other select asset monetizations, it is possible that we may incur impairments of certain equity-method investments, property, plant, and equipment, and intangible assets. Such impairments could potentially be caused by indications of fair value implied through the monetization process or, in the case of asset dispositions that are part of a broader asset group, the impact of the loss of future estimated cash flows.

Summary of Significant Accounting Policies

Principles of consolidation

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

• 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.

We apply the equity method of accounting to investments over which we exercise significant influence but do not control.

Equity-method investment basis differences

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

Use of estimates

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

Significant estimates and assumptions include:

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

• Litigation-related contingencies;

• Environmental remediation obligations;

• 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.

These estimates are discussed further throughout these notes.

Regulatory accounting

Transco and Northwest Pipeline are regulated by the Federal Energy Regulatory Commission (FERC). Their rates, which are established by the FERC, are designed to recover the costs of providing the regulated services, and their competitive environment makes it probable that such rates can be charged and collected. Therefore, our management has determined that it is appropriate under Accounting Standards Codification (ASC) Topic 980, “Regulated Operations,” to account for and report regulatory assets and liabilities related to these operations consistent with the economic effect of the way in which their rates are established. Accounting for these operations that are regulated can differ from the accounting requirements for nonregulated operations. For example, for regulated operations, allowance for funds used during construction (AFUDC) represents the estimated cost of debt and equity funds applicable to utility plant in process of construction and is capitalized as a cost of property, plant, and equipment because it constitutes an actual cost of construction under established regulatory practices; nonregulated operations are only allowed to capitalize the cost of debt funds related to construction activities, while a component for equity is prohibited. The components

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of our regulatory assets and liabilities relate to the effects of deferred taxes on equity funds used during construction, asset retirement obligations, fuel cost differentials, levelized incremental depreciation, negative salvage, and pension and other postretirement benefits. Our current and noncurrent regulatory asset and liability balances for the years ended December 31, 2016 and 2015 are as follows:

	December 31,
	2016		2015
	(Millions)
Current assets reported within Other current assets and deferred charges	$	91	$	84
Noncurrent assets reported within Regulatory assets, deferred charges, and other	387		370
Total regulated assets	$	478	$	454
Current liabilities reported within Accrued liabilities	$	11	$	4
Noncurrent liabilities reported within Regulatory liabilities, deferred income, and other	498		434
Total regulated liabilities	$	509	$	438

Cash and cash equivalents

Cash and cash equivalents in the Consolidated Balance Sheet includes amounts primarily invested in funds with high-quality, short-term securities and instruments that are issued or guaranteed by the U.S. government. These have maturity dates of three months or less when acquired.

Accounts receivable

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

Inventories

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

Property, plant, and equipment

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

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

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

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

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We record a liability and increase the basis in the underlying asset for the present value of each expected future asset retirement obligation (ARO) at the time the liability is initially incurred, typically when the asset is acquired or constructed. As regulated entities, Northwest Pipeline and Transco offset the depreciation of the underlying asset that is attributable to capitalized ARO cost to a regulatory asset as management expects to recover these amounts in future rates. We measure changes in the liability due to passage of time by applying an interest rate to the liability balance. This amount is recognized as an increase in the carrying amount of the liability and as a corresponding accretion expense included in Operating and maintenance expenses in the Consolidated Statement of Operations, except for regulated entities, for which the liability is offset by a regulatory asset. The regulatory asset is amortized commensurate with our collection of those costs in rates.

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

Goodwill

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

Other intangible assets

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

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

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

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

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

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

Deferred income

We record a liability for deferred income related to cash received from customers in advance of providing our services.  Such amounts are generally recognized in revenue upon satisfying our performance obligations, primarily providing services based on units of production or over remaining contractual service periods ranging from 1 to 25 years.  Deferred incomeis reflected within Accrued liabilitiesand Regulatory liabilities, deferred income, and otheron the Consolidated Balance Sheet.  (See Note 13 – Accrued Liabilities.) 

During 2016, we received cash proceeds totaling $820 million associated with restructuring certain gas gathering contracts in the Barnett Shale and Mid-Continent regions. The proceeds were recorded as deferred incomeand are being amortized into income in 2016 and future periods.

In October 2016, we received $104 million of newly constructed assets as part of a noncash investing transaction with a customer for which we provide production handling and other services. The transaction was recorded in Property, plant, and equipment – net and deferred income in the Consolidated Balance Sheet and is being amortized based on units of production through 2024. Due to the noncash nature of this transaction, it is not presented within the Consolidated Statement of Cash Flows.

Contingent liabilities

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

Cash flows from revolving credit facilities and commercial paper program

Proceeds and payments related to borrowings under our credit facilities are reflected in the financing activities in the Consolidated Statement of Cash Flows on a gross basis. Proceeds and payments related to borrowings under our commercial paper program are reflected in the financing activities in the Consolidated Statement of Cash Flows on a net basis, as the outstanding notes generally have maturity dates less than three months from the date of issuance. (See Note 14 – Debt, Banking Arrangements, and Leases.)

Treasury stock

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

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Notes to Consolidated Financial Statements – (Continued)

Derivative instruments and hedging activities

We may utilize derivatives to manage a portion of our commodity price risk. These instruments consist primarily of swaps, futures, and forward contracts involving short- and long-term purchases and sales of energy commodities. We report the fair value of derivatives, except those for which the normal purchases and normal sales exception has been elected, in Other current assets and deferred charges; Regulatory assets, deferred charges, and other;Accrued liabilities; or Regulatory liabilities, deferred income, and other in the Consolidated Balance Sheet. We determine the current and noncurrent classification based on the timing of expected future cash flows of individual trades. We report these amounts on a gross basis. Additionally, we report cash collateral receivables and payables with our counterparties on a gross basis. (See Note 17 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk.)

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

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

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

We may also designate a hedging relationship for certain commodity derivatives. For a derivative to qualify for designation in a hedging relationship, it must meet specific criteria and we must maintain appropriate documentation. We establish hedging relationships pursuant to our risk management policies. We evaluate the hedging relationships at the inception of the hedge and on an ongoing basis to determine whether the hedging relationship is, and is expected to remain, highly effective in achieving offsetting changes in fair value or cash flows attributable to the underlying risk being hedged. We also regularly assess whether the hedged forecasted transaction is probable of occurring. If a derivative ceases to be or is no longer expected to be highly effective, or if we believe the likelihood of occurrence of the hedged forecasted transaction is no longer probable, hedge accounting is discontinued prospectively, and future changes in the fair value of the derivative are recognized currently in Product sales or Product costsin the Consolidated Statement of Operations.

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

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

Certain gains and losses on derivative instruments included in the Consolidated Statement of Operations are netted together to a single net gain or loss, while other gains and losses are reported on a gross basis. Gains and losses recorded

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on a net basis include unrealized gains and losses on all derivatives that are not designated as hedges and for which we have not elected the normal purchases and normal sales exception.

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

Revenue recognition

Revenues

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

Service revenues

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

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

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

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

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

Product sales

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

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Notes to Consolidated Financial Statements – (Continued)

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

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

Our domestic olefins business produces olefins from purchased or produced feedstock and we recognize revenues when the olefins are sold and delivered.

Our Canadian businesses that were sold in September 2016 had processing and fractionation operations where we retained certain NGLs and olefins from an upgrader’s offgas stream and we recognized revenues when the fractionated products were sold and delivered.

Interest capitalized

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

Employee stock-based awards

We recognize compensation expense on employee stock-based awards, net of estimated forfeitures, on a straight-line basis. (See Note 16 – Equity-Based Compensation.)

Pension and other postretirement benefits

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

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

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

Unrecognized actuarial gains and losses and unrecognized prior service costs and credits are deferred and recorded in AOCI or, for Transco and Northwest Pipeline, as a regulatory asset or liability, until amortized as a component of net periodic benefit cost. Unrecognized actuarial gains and losses in excess of 10 percent of the greater of the benefit obligation or the market-related value of plan assets are amortized over the participants’ average remaining future years of service, which is approximately 13 years for our pension plans and approximately 7 years for our other postretirement benefit plans. Unrecognized prior service costs and credits for the other postretirement benefit plans are amortized on a straight line basis over the average remaining years of service to eligibility for eligible plan participants, which is approximately 4 years.

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Notes to Consolidated Financial Statements – (Continued)

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

Income taxes

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

Earnings (loss) per common share

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

Foreign currency translation

Certain of our foreign subsidiaries that used the Canadian dollar as their functional currency were sold in 2016. The assets and liabilities of such foreign subsidiaries were translated at the spot rate in effect at the applicable reporting date, and the combined statements of operations were translated into the U.S. dollar at the average exchange rates in effect during the applicable period. The resulting cumulative translation adjustment was recorded as a separate component of AOCI in the Consolidated Balance Sheet.

Transactions denominated in currencies other than the functional currency were recorded based on exchange rates at the time such transactions arose. Subsequent changes in exchange rates when the transactions were settled resulted in transaction gains and losses which were reflected in Other (income) expense – net within Costs and expenses in the Consolidated Statement of Operations. Substantially all of our Canadian operations were sold in September 2016.

Accounting standards issued and adopted

Effective January 1, 2017, we adopted Accounting Standards Update (ASU) 2016-09 “Compensation - Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting” (ASU 2016-09). The objective of ASU 2016-09 is to simplify several aspects of the accounting for share-based payment transactions, including the income tax consequences, classification of awards as either equity or liabilities, and classification on the statement of cash flows. ASU 2016-09 requires entities to classify as a financing activity, on the statement of changes in cash flows, cash paid by an employer to a taxing authority when directly withholding shares from an employee’s award to satisfy the employer’s statutory tax withholding obligation. This guidance must be applied retrospectively and we have adjusted operating and financing activities on the Consolidated Statement of Cash Flows for all periods presented.

Accounting standards issued but not yet adopted

In January 2017, the Financial Accounting Standards Board (FASB) issued ASU 2017-04 “Intangibles - Goodwill and Other (Topic 350): Simplifying the Test for Goodwill Impairment” (ASU 2017-04). ASU 2017-04 modifies the concept of goodwill impairment to represent the amount by which a reporting unit’s carrying value exceeds its fair

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value, not to exceed the carrying amount of goodwill. Under ASU 2017-04, entities will no longer be required to determine the implied fair value of goodwill by assigning the fair value of a reporting unit to its individual assets and liabilities as if that reporting unit had been acquired in a business combination. ASU 2017-04 is effective for goodwill impairment testing for interim and annual periods beginning after December 15, 2019, and requires a prospective transition. Early adoption is permitted for interim and annual goodwill impairment tests performed after January 1, 2017, and we plan to adopt this standard in 2017. Our Williams Partners reportable segment has $47 million of goodwill included in Intangible assets – net of accumulated amortization in the Consolidated Balance Sheet (see Note 12 – Goodwill and Other Intangible Assets).

In August 2016, the FASB issued ASU 2016-15 “Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments” (ASU 2016-15). ASU 2016-15 provides specific guidance on eight cash flow classification issues, including debt prepayment or debt extinguishment costs and distributions received from equity method investees, to reduce diversity in practice. ASU 2016-15 is effective for interim and annual periods beginning after December 15, 2017. Early adoption is permitted. ASU 2016-15 requires a retrospective transition. We are evaluating the impact of ASU 2016-15 on our consolidated financial statements.

In June 2016, the FASB issued ASU 2016-13 “Financial Instruments - Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments” (ASU 2016-13). ASU 2016-13 changes the impairment model for most financial assets and certain other instruments. For trade and other receivables, held-to-maturity debt securities, loans, and other instruments, entities will be required to use a new forward-looking “expected loss” model that generally will result in the earlier recognition of allowances for losses. The guidance also requires increased disclosures. ASU 2016-13 is effective for interim and annual periods beginning after December 15, 2019. Early adoption is permitted. ASU 2016-13 requires varying transition methods for the different categories of amendments. We are evaluating the impact of ASU 2016-13 on our consolidated financial statements. Although we do not expect ASU 2016-13 to have a significant impact, it will impact our trade receivables as the related allowance for credit losses will be recognized earlier under the expected loss model than under our current policy.

In February 2016, the FASB issued ASU 2016-02 “Leases (Topic 842)” (ASU 2016-02). ASU 2016-02 establishes a comprehensive new lease accounting model. ASU 2016-02 clarifies the definition of a lease, requires a dual approach to lease classification similar to current lease classifications, and causes lessees to recognize leases on the balance sheet as a lease liability with a corresponding right-of-use asset. ASU 2016-02 is effective for interim and annual periods beginning after December 15, 2018. Early adoption is permitted. ASU 2016-02 requires a modified retrospective transition for capital or operating leases existing at or entered into after the beginning of the earliest comparative period presented in the financial statements. We are reviewing contracts to identify leases, particularly reviewing the applicability of ASU 2016-02 to contracts involving easements/rights-of-way.

In May 2014, the FASB issued ASU 2014-09 establishing Accounting Standards Codification (ASC) Topic 606, “Revenue from Contracts with Customers” (ASC 606). ASC 606 establishes a comprehensive new revenue recognition model designed to depict the transfer of goods or services to a customer in an amount that reflects the consideration the entity expects to be entitled to receive in exchange for those goods or services and requires significantly enhanced revenue disclosures. In August 2015, the FASB issued ASU 2015-14 “Revenue from Contracts with Customers (Topic 606): Deferral of the Effective Date” (ASU 2015-14). Per ASU 2015-14, the standard is effective for interim and annual reporting periods beginning after December 15, 2017. ASC 606 allows either full retrospective or modified retrospective transition and early adoption is permitted for annual periods beginning after December 15, 2016.

We continue to evaluate the impact the standard may have on our financial statements. For each revenue contract type, we are conducting a formal contract review process to evaluate the impact, if any, that the new revenue standard may have. We have substantially completed that process, but continue to evaluate our accounting for noncash consideration, which exists in contracts where we receive commodities as full or partial consideration, contracts with a significant financing component, which may exist in situations where the timing of the consideration we received varies significantly from the timing of the service we provide, and the accounting for contributions in aid of construction. As such, we are unable to determine the potential impact upon the amount and timing of revenue recognition and related disclosures. Additionally, we have identified possible financial system and internal control changes necessary for

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adoption. We currently anticipate utilizing a modified retrospective transition upon the adoption of ASC 606 as of January 1, 2018.

Note 2 – Acquisitions

ACMP

On December 20, 2012, we purchased approximately 24 percent of ACMP’s outstanding limited partnership units and 50 percent of the ACMP general partner 2 percent interest which included IDRs for approximately $2.19 billion in cash, including transaction costs. We accounted for these acquired interests as equity-method investments.

On July 1, 2014, we acquired control of ACMP (ACMP Acquisition) through the acquisition of an additional 26 percent of ACMP’s outstanding limited partnership units and the remaining 50 percent interest in the general partner for $5.995 billion in cash. The acquisition was funded through the issuance of equity (see Note 15 – Stockholders' Equity) and debt, credit facility borrowings, and cash on hand.

At the time of acquisition, ACMP owned, operated, developed, and acquired natural gas gathering systems and other midstream energy assets. The purpose of the acquisition was to enhance our position in the Marcellus and Utica Shale plays, provide additional diversity via the Eagle Ford, Haynesville, Barnett, Mid-Continent, and Niobrara areas, and to fortify our stable, fee-based business model and support our dividend growth strategy.

Our basis in ACMP reflects business combination accounting, which, among other things, requires identifiable assets acquired and liabilities assumed to be measured at their acquisition-date fair values. Prior to the ACMP Acquisition we accounted for our investment in ACMP using the equity method. The acquisition-date fair value of our equity-method investment in ACMP was $4.6 billion. As a result of remeasuring our equity-method investment to fair value, for the year ended December 31, 2014 we recognized a $2.5 billion noncash gain within the Gain on remeasurement of equity-method investment line item in the Consolidated Statement of Operations.

The valuation techniques used to measure the acquisition-date fair value of the ACMP Acquisition, including our previous equity-method investment in ACMP, consisted of valuing the limited partner units and general partner interest separately. The limited partner units, consisting of common and Class B units, were valued based on ACMP’s closing common unit price at July 1, 2014. The general partner interest, including IDRs, was valued on a noncontrolling basis using an income approach based on a discounted cash flow analysis and a market comparison analysis based on comparable guideline companies and an implied fair value from our purchase.

The following table presents the allocation of the acquisition-date fair value of the major classes of the assets acquired, which are presented in the Williams Partners segment, liabilities assumed, and noncontrolling interest at July 1, 2014. The fair value of accounts receivable acquired equaled contractual amounts receivable. Changes to the preliminary allocation disclosed in Exhibit 99.1 of our Form 8-K dated May 6, 2015, which were recorded in the first quarter of 2015, reflect an increase of $150 million in Property, plant, and equipment and $25 million in Goodwill, and a decrease of $168 million in Other intangible assets and $7 million in Investments. These adjustments during the measurement period were not considered significant to require retrospective revisions of our financial statements.

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	(Millions)
Accounts receivable	$	168
Other current assets	63
Investments	5,865
Property, plant, and equipment	7,165
Goodwill	499
Other intangible assets	8,841
Current liabilities	(408		)
Debt	(4,052		)
Other noncurrent liabilities	(9		)
Noncontrolling interest in ACMP’s subsidiaries	(958		)
Noncontrolling interest in ACMP	(6,544		)

Other intangible assets recognized in the acquisition are related to contractual customer relationships from gas gathering agreements with our customers. The basis for determining the value of these intangible assets was estimated future net cash flows to be derived from acquired contractual customer relationships discounted using a risk-adjusted discount rate. These intangible assets are being amortized on a straight-line basis over 30 years during which contractual customer relationships are expected to contribute to our cash flows. As estimated at the time of acquisition, approximately 56 percent of the expected future revenues from these contractual customer relationships were impacted by our ability and intent to renew or renegotiate existing customer contracts. We expense costs incurred to renew or extend the terms of our gas gathering, processing, and fractionation contracts with customers. Based on the estimated future revenues during the current contract periods (as estimated at the time of acquisition), the weighted-average periods to the next renewal or extension of the existing customer contracts were approximately 17 years.

The noncash adjustment to record the fair value of the noncontrolling interest in ACMP was determined based on the common units and ACMP’s closing common unit price at July 1, 2014.

The following unaudited pro forma Total revenues and Net income (loss) attributable to The Williams Companies, Inc. for the year ended December 31, 2014, are presented as if the ACMP Acquisition had been completed on January 1, 2014. These pro forma amounts are not necessarily indicative of what the actual results would have been if the acquisition had in fact occurred on the date or for the period indicated, nor do they purport to project Total revenues or Net income (loss) attributable to The Williams Companies, Inc. for any future periods or as of any date. These amounts do not give effect to any potential cost savings, operating synergies, or revenue enhancements to result from the transactions or the potential costs to achieve these cost savings, operating synergies, and revenue enhancements.

	December 31,
	2014
	(Millions)
Total revenues	$	8,181
Net income (loss) attributable to The Williams Companies, Inc.	$	622

Significant adjustments to pro forma Net income (loss) attributable to The Williams Companies, Inc. include the removal of the previously described $2.5 billion gain on remeasurement of equity-method investment, and include additional depreciation and amortization expense associated with reflecting the acquired investments, property, plant, and equipment, and other intangible assets at fair value. The adjustments assume estimated useful lives of 30 years. Other significant adjustments to pro forma Net income (loss) attributable to The Williams Companies, Inc. include interest expense related to debt financing associated with the acquisition as well as Net income (loss) attributable to noncontrolling interests.

During the year ended December 31, 2014, ACMP contributed Total revenues of $781 million and Net income (loss) attributable to The Williams Companies, Inc. of $165 million.

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Notes to Consolidated Financial Statements – (Continued)

Costs related to this acquisition were $16 million in 2014 and are reported within our Williams Partners segment and included in Selling, general, and administrative expenses in the Consolidated Statement of Operations. Direct transaction costs associated with financing commitments were $9 million in 2014 and reported within Interest incurred in the Consolidated Statement of Operations. Equity earnings (losses) within the Consolidated Statement of Operations in 2014 includes $19 million of equity losses associated with certain compensation-related costs at ACMP that were triggered by the acquisition.

Eagle Ford Gathering System

In May 2015, WPZ acquired a gathering system comprised of approximately 140 miles of pipeline and a sour gas compression facility in the Eagle Ford Shale for $112 million. The acquisition was accounted for as a business combination, and the allocation of the acquisition-date fair value of the major classes of assets acquired includes $80 million of Property, plant, and equipment – net and $32 million of Intangible assets – net of accumulated amortization in the Consolidated Balance Sheet. Changes to the preliminary allocation disclosed in the second quarter of 2015 reflect an increase of $20 million in Property, plant, and equipment – net, and a decrease of $20 million in Intangible assets – net of accumulated amortization.

UEOM Equity-Method Investment

In June 2015, WPZ acquired an approximate 13 percent additional interest in its equity-method investment, UEOM, for $357 million. Following the acquisition WPZ owns approximately 62 percent of UEOM. However, WPZ continues to account for this as an equity-method investment because WPZ does not control UEOM due to the significant participatory rights of its partner. In connection with the acquisition of the additional interest, we agreed to waive approximately $2 million of our WPZ IDR payments each quarter through 2017. See Note 1 – General, Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies for discussion of agreement with WPZ wherein we permanently waived IDR payment obligations from WPZ.

Note 3 – Divestiture

In September 2016, we completed the sale of subsidiaries conducting Canadian operations, including subsidiaries of WPZ, (such subsidiaries, the disposal group). Consideration received to date totaled $1.020 billion, net of $31 million of cash divested and subject to customary working capital adjustments. In connection with the sale, we waived $150 million of incentive distributions otherwise payable by WPZ to us in the fourth quarter of 2016 in recognition of certain affiliate contracts wherein WPZ’s Canadian operations provided services to certain of our other businesses. The proceeds were primarily used to reduce borrowings on credit facilities.

During the second quarter of 2016, we designated these operations as held for sale. As a result, we measured the fair value of the disposal group as of June 30, 2016, resulting in an impairment charge of $747 million, reflected in Impairment of certain assets in the Consolidated Statement of Operations. (See Note 17 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk.) During the second half of 2016 we recorded an additional loss of $66 million upon completion of the sale, primarily reflecting revisions to the sales price and estimated contingent consideration and including a $15 million benefit related to transactions to hedge our foreign currency exchange risk on the Canadian proceeds, reflected in Other (income) expense – net within Costs and expenses in the Consolidated Statement of Operations. The total loss consists of a loss of $34 million at Williams Partners and $32 million at Other.

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Notes to Consolidated Financial Statements – (Continued)

The following table presents the results of operations for the disposal group, excluding the impairment and loss noted above:

	Years Ended December 31,
	2016			2015
	(Millions)
Income (loss) before income taxes of disposal group	$	(98	)	$	17
Income (loss) before income taxes of disposal group attributable to The Williams Companies, Inc.	(95		)	15

Note 4 – Variable Interest Entities

On January 1, 2016, we adopted ASU 2015-02 “Amendments to the Consolidation Analysis," which eliminated certain presumptions related to a general partner interest in a master limited partnership. As a result of adopting this new accounting standard, our consolidated master limited partnership is now a VIE. We are the primary beneficiary of WPZ because we have the power to direct the activities that most significantly impact WPZ’s economic performance.

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Notes to Consolidated Financial Statements – (Continued)

The following table presents amounts included in our Consolidated Balance Sheet that are for the use or obligation of WPZ and/or its subsidiaries, and which comprise a significant portion of our consolidated assets and liabilities:

	December 31,
	2016			2015			Classification
	(Millions)
Assets (liabilities):
Cash and cash equivalents	$	145		$	73		Cash and cash equivalents
Trade accounts and other receivables – net	925			1,026			Trade accounts and other receivables
Inventories	138			127			Inventories
Other current assets	205			190			Other current assets and deferred charges
Investments	6,701			7,336			Investments
Property, plant, and equipment – net	28,021			28,593			Property, plant, and equipment – net
Intangible assets – net	9,662			10,016			Intangible assets – net of accumulated amortization
Regulatory assets, deferred charges, and other noncurrent assets	467			479			Regulatory assets, deferred charges, and other
Accounts payable	(589		)	(625		)	Accounts payable
Accrued liabilities including current asset retirement obligations	(1,122		)	(757		)	Accrued liabilities
Commercial paper	(93		)	(499		)	Commercial paper
Long-term debt due within one year	(785		)	(176		)	Long-term debt due within one year
Long-term debt	(17,685		)	(19,001		)	Long-term debt
Deferred income tax liabilities	(20		)	(119		)	Deferred income tax liabilities
Noncurrent asset retirement obligations	(798		)	(857		)	Regulatory liabilities, deferred income, and other
Regulatory liabilities, deferred income, and other noncurrent liabilities	(1,860		)	(1,066		)	Regulatory liabilities, deferred income, and other

The assets and liabilities presented in the table above also include the consolidated interests of the following individual VIEs within WPZ:

Gulfstar One

WPZ owns a 51 percentinterest in Gulfstar One LLC (Gulfstar One), a subsidiary that, due to certain risk-sharing provisions in its customer contracts, is a VIE. Gulfstar One includes a proprietary floating-production system, Gulfstar FPS, and associated pipelines which provide production handling and gathering services for the Tubular Bells oil and gas discovery in the eastern deepwater Gulf of Mexico. WPZ is the primary beneficiary because it has the power to direct the activities that most significantly impact Gulfstar One’s economic performance.

Constitution

WPZ owns a 41 percent interest in Constitution, a subsidiary that, due to shipper fixed-payment commitments under its long-term firm transportation contracts, is a VIE. WPZ is the primary beneficiary because it has the power to direct the activities that most significantly impact Constitution’s economic performance. WPZ, as construction manager for Constitution, is responsible for constructing the proposed pipeline connecting its gathering system in Susquehanna County, Pennsylvania, to the Iroquois Gas Transmission and the Tennessee Gas Pipeline systems. The total remaining

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The Williams Companies, Inc.

Notes to Consolidated Financial Statements – (Continued)

cost of the project is estimated to be approximately $687 million, which is expected to be funded with capital contributions from WPZ and the other equity partners on a proportional basis.

In December 2014, we received approval from the FERC to construct and operate the Constitution pipeline. However, in April 2016, the New York State Department of Environmental Conservation (NYSDEC) denied a necessary water quality certification for the New York portion of the Constitution pipeline. We remain steadfastly committed to the project, and in May 2016, Constitution appealed the NYSDEC's denial of the certification and filed an action in federal court seeking a declaration that the State of New York's authority to exercise permitting jurisdiction over certain other environmental matters is preempted by federal law. The oral argument before the Second Circuit Court of Appeals regarding the NYSDEC’s denial of Constitution’s application for water quality certification under Section 401 of the Clean Water Act was held on November 16, 2016. We anticipate a decision from the Second Circuit Court of Appeals as early as second quarter 2017. In light of the NYSDEC's denial of the water quality certification and the actions taken to challenge the decision, the project in-service date is targeted as early as the second half of 2018, which assumes that the legal challenge process is satisfactorily and promptly concluded. An unfavorable resolution could result in the impairment of a significant portion of the capitalized project costs, which total $381 million on a consolidated basis at December 31, 2016, and are included within Property, plant, and equipment – netin the Consolidated Balance Sheet. Beginning in April 2016, we discontinued capitalization of development costs related to this project. It is also possible that we could incur certain supplier-related costs in the event of a prolonged delay or termination of the project.

Cardinal

WPZ owns a 66 percent interest in Cardinal Gas Services, L.L.C. (Cardinal), a subsidiary that provides gathering services for the Utica Shale region and is a VIE due to certain risks shared with customers. WPZ is the primary beneficiary because it has the power to direct the activities that most significantly impact Cardinal’s economic performance. Future expansion activity is expected to be funded with capital contributions from WPZ and the other equity partner on a proportional basis.

Jackalope

WPZ owns a 50 percent interest in Jackalope Gas Gathering Services, L.L.C. (Jackalope), a subsidiary that provides gathering and processing services for the Powder River basin and is a VIE due to certain risks shared with customers. WPZ is the primary beneficiary because it has the power to direct the activities that most significantly impact Jackalope’s economic performance. Future expansion activity is expected to be funded with capital contributions from WPZ and the other equity partner on a proportional basis.

Note 5 – Related Party Transactions

Transactions with Equity-Method Investees

We have purchases from our equity-method investees included in Product costs in the Consolidated Statement of Operationsof $180 million, $187 million, and $197 million for the years ended 2016, 2015, and 2014, respectively. We have $19 million and $12 million included in Accounts payablein the Consolidated Balance Sheetwith our equity-method investees at December 31, 2016 and 2015, respectively.

WPZ has operating agreements with certain equity-method investees. These operating agreements typically provide for reimbursement or payment to WPZ for certain direct operational payroll and employee benefit costs, materials, supplies, and other charges and also for management services. We supplied a portion of these services, primarily those related to employees since WPZ does not have any employees, to certain equity-method investees. The total charges to equity-method investees for these fees are $66 million, $64 million, and $65 million for the years ended 2016, 2015, and 2014, respectively.

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The Williams Companies, Inc.

Notes to Consolidated Financial Statements – (Continued)

Board of Directors

A former member of our Board of Directors, who was elected in 2013 and resigned during 2016, is also the current chairman, president, and chief executive officer of an energy services company that is a customer of ours. We recorded $144 million, $111 million, and $115 million in Service revenues in the Consolidated Statement of Operations from this company for transportation and storage of natural gas for the years ended December 31, 2016, 2015, and 2014, respectively.

Note 6 – Investing Activities

Impairment of equity-method investments

The following table presents other-than-temporary impairment charges related to certain equity-method investments (see Note 17 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk):

	Years Ended December 31,
	2016		2015
	(Millions)
Williams Partners
Appalachia Midstream Investments	$	294	$	562
DBJV	59		503
Laurel Mountain	50		45
UEOM	—		241
Ranch Westex	24		—
Other	3		8
	$	430	$	1,359

Equity earnings (losses)

Equity earnings (losses) in 2015 includes a loss of $19 million associated with WPZ’s share of underlying property impairments at certain of the Appalachia Midstream Investments. This loss is reported within the Williams Partners segment.

Equity earnings (losses) in 2014 includes:

• 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;

• 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.

Other investing income (loss) – net

In 2016, we recognized a $27 million gain from the sale of an equity-method investment interest in a gathering system that was part of the Appalachia Midstream Investments within the Williams Partners segment.

Other investing income (loss) – net also includes $36 million, $27 million, and $41 million of interest income for 2016, 2015 and 2014, respectively, associated with a receivable related to the sale of certain former Venezuela assets. Due to changes in circumstances that led to late payments and increased uncertainty regarding the recovery of the receivable, we began accounting for the receivable under a cost recovery model in first quarter 2015. Subsequently,

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The Williams Companies, Inc.

Notes to Consolidated Financial Statements – (Continued)

we received payments greater than the remaining carrying amount of the receivable, which resulted in the recognition of interest income.

Investments

	Ownership Interest at December 31, 2016	December 31,
		2016		2015
		(Millions)
Equity-method investments:
Appalachia Midstream Investments	(1)	$	2,062	$	2,464
UEOM	62%	1,448		1,525
DBJV	50%	988		977
Discovery	60%	572		602
OPPL	50%	430		445
Caiman II	58%	426		418
Laurel Mountain	69%	324		391
Gulfstream	50%	261		293
Other	Various	190		221
		$	6,701	$	7,336

___________

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

We have differences between the carrying value of our equity-method investments and the underlying equity in the net assets of the investees of $1.9 billion at December 31, 2016 and $2.4 billion at December 31, 2015. These differences primarily relate to our investments in Appalachian Midstream Investments, DBJV, and UEOM resulting from property, plant, and equipment, as well as customer-based intangible assets and goodwill.

Purchases of and contributions to equity-method investments

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

	Years Ended December 31,
	2016		2015		2014
	(Millions)
DBJV	$	105	$	57	$	20
Appalachia Midstream Investments	28		93		84
Caiman II	22		—		175
UEOM	—		357		57
Discovery	—		35		106
Other	22		53		40
	$	177	$	595	$	482

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Notes to Consolidated Financial Statements – (Continued)

Dividends and distributions

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

	Years Ended December 31,
	2016		2015		2014
	(Millions)
Appalachia Midstream Investments	$	211	$	219	$	130
Discovery	141		116		36
Gulfstream	100		88		81
UEOM	92		42		—
OPPL	69		45		27
Caiman II	40		33		13
DBJV	39		33		—
Laurel Mountain	28		31		39
ACMP	—		—		64
Other	22		26		50
	$	742	$	633	$	440

In addition, on September 24, 2015, WPZ received a special distribution of $396 million from Gulfstream reflecting its proportional share of the proceeds from new debt issued by Gulfstream. The new debt was issued to refinance Gulfstream’s debt maturities. Subsequently, WPZ contributed $248 million and $148 million to Gulfstream for its proportional share of amounts necessary to fund debt maturities of $500 million due on November 1, 2015, and $300 million due on June 1, 2016, respectively.

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

	December 31,
	2016			2015
	(Millions)
Assets (liabilities):
Current assets	$	508		$	773
Noncurrent assets	9,695			9,549
Current liabilities	(412		)	(633		)
Noncurrent liabilities	(1,484		)	(1,450		)

	Years Ended December 31,
	2016		2015		2014
	(Millions)
Gross revenue	$	1,883	$	1,707	$	1,623
Operating income	799		690		534
Net income	726		611		460

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Notes to Consolidated Financial Statements – (Continued)

Note 7 – Other Income and Expenses

The following table presents certain gains or losses reflected in Other (income) expense – net within Costs and expenses in the Consolidated Statement of Operations:

	Years Ended December 31,
	2016			2015			2014
	(Millions)
Williams Partners
Loss on sale of Canadian operations (Note 3)	$	34		$	—		$	—
Amortization of regulatory assets associated with asset retirement obligations	33			33			33
Accrual of regulatory liability related to overcollection of certain employee expenses	25			20			14
Project development costs related to Constitution (Note 4)	28			—			—
Net foreign currency exchange (gains) losses (1)	10			(10		)	(3		)
Contingency gain settlement (2)	—			—			(154		)
Net gain related to partial acreage dedication release	—			—			(12		)
Gain on asset retirement	(11		)	—			—
Loss related to sale of certain assets	—			—			10
Other
Loss on sale of Canadian operations (Note 3)	32			—			—
Gain on sale of unused pipe	(10		)	—			—

________________

(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.

ACMP Acquisition, Merger, and Transition

Certain ACMP acquisition, merger, and transition costs included in the Consolidated Statement of Operations are as follows:

• Selling, general, and administrative expensesincludes $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 expensesincludes $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 expensesincludes $12 million in 2015 and $15 million in 2014 primarily related to employee transition costs within the Williams Partners segment.

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

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Additional Items

Certain additional items included in the Consolidated Statement of Operations are as follows:

• Service revenuesincludes $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 feesin the Barnett Shale and Mid-Continent regions within the Williams Partners segment.

• Selling, general, and administrative expensesand 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.

Note 8 – Provision (Benefit) for Income Taxes

The Provision (benefit) for income taxes includes:

	Years Ended December 31,
	2016			2015			2014
	(Millions)
Current:
Federal	$	—		$	—		$	(9	)
State	2			(7		)	2
Foreign	(1		)	(55		)	10
	1			(62		)	3
Deferred:
Federal	(6		)	(317		)	1,108
State	61			(25		)	119
Foreign	(81		)	5			19
	(26		)	(337		)	1,246
Provision (benefit) for income taxes	$	(25	)	$	(399	)	$	1,249

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Notes to Consolidated Financial Statements – (Continued)

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

	Years Ended December 31,
	2016			2015			2014
	(Millions)
Provision (benefit) at statutory rate	$	(131	)	$	(600	)	$	1,255
Increases (decreases) in taxes resulting from:
Impact of nontaxable noncontrolling interests	(22		)	263			(75		)
State income taxes (net of federal benefit)	3			(21		)	82
State deferred income tax rate change	43			—			—
Foreign operations – net (Including tax effect of Canadian Sale)	78			8			(11		)
Taxes on undistributed earnings of foreign subsidiaries – net	—			—			(37		)
Translation adjustment of certain unrecognized tax benefits	(1		)	(71		)	—
Other – net	5			22			35
Provision (benefit) for income taxes	$	(25	)	$	(399	)	$	1,249

Income (loss) from continuing operations before income taxes includes $885 million of foreign loss in 2016, and $20 million and $102 million of foreign income in 2015 and 2014, respectively.

Foreign operations – net (Including tax effect of Canadian Sale) increased in 2016 due to a valuation allowance associated with impairments and losses on the sale of our Canadian operations (see Note 3 – Divestiture) and the reversal of anticipatory foreign tax credits, partially offset by the tax effect of the impairments associated with our Canadian disposition.

The Translation adjustment of certain unrecognized tax benefits in 2016 and 2015 reflects the impact of changes in foreign currency exchange rates on the remeasurement of a foreign currency denominated unrecognized tax benefit, including associated penalties and interest.

The 2015 federal and state income tax provisions include the tax effect of a $2.7 billion impairment loss associated with certain goodwill, equity-method investments, and other assets. (See Note 17 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk.) The 2014 federal and state income tax provisions include the tax effect of a $2.5 billion gain associated with remeasuring our equity-method investment to fair value as a result of the ACMP Acquisition. (See Note 2 – Acquisitions.)

Taxes on undistributed earnings of foreign subsidiaries - net decreased in 2014 due to revisions of our estimate of the undistributed earnings, partially offset by an increase of tax expense, which decreased our share of the foreign tax credit due to the Canada Dropdown.

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

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Notes to Consolidated Financial Statements – (Continued)

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

	December 31,
	2016		2015
	(Millions)
Deferred income tax liabilities:
Property, plant, and equipment	$	—	$	4
Investments	5,300		5,272
Other	29		15
Total deferred income tax liabilities	5,329		5,291
Deferred income tax assets:
Accrued liabilities	145		150
Minimum tax credits	139		139
Foreign tax credit	140		193
Federal loss carryovers	651		485
State losses and credits	313		296
Other	37		42
Total deferred income tax assets	1,425		1,305
Less valuation allowance	334		190
Net deferred income tax assets	1,091		1,115
Overall net deferred income tax liabilities	$	4,238	$	4,176

The valuation allowance at December 31, 2016 and 2015 serves to reduce the available deferred income tax assets to an amount that will, more likely than not, be realized. We consider all available positive and negative evidence, including projected future taxable income and management’s estimate of future reversals of existing taxable temporary differences, and have determined that a portion of our deferred income tax assets related to State losses and credits and Federal loss carryovers may not be realized. The change in Valuation allowance is partially due to this evaluation. The amounts presented in the table above are, with respect to state items, before any federal benefit. The change from prior year for the State losses and creditsis primarily due to increases in losses and credits generated in the current and prior years less losses and/or credits utilized in the current year. We have loss and credit carryovers in multiple state taxing jurisdictions. These attributes generally expire between 2017 and 2036 with some carryovers having indefinite carryforward periods. Federal loss carryovers includes the tax effect of a capital loss carryover of $364 million, incurred with the sale of our Canadian operations, which, if unused, will expire in 2021. The Valuation allowance change from prior year is primarily due to a valuation allowance on the deferred tax asset associated with this capital loss carryover. We reasonably anticipate that this valuation allowance could be released in the near future due to tax impacts of the potential monetization of certain assets as previously announced by management. The federal tax Minimum tax credits of $139 million currently has no expiration date. Foreign tax credit of $140 million is expected to be utilized prior to expiration in 2026.

Federal net operating loss carryovers and charitable contribution carryovers of $1.6 billion at the end of 2016 are expected to be utilized by us prior to expiration between 2018 and 2036. Employee share-based compensation attributable to the exercise of stock options and vesting of restricted stock is deductible by us for tax purposes. To the extent these tax deductions exceed the previously accrued deferred income tax benefit for these items, the additional tax benefit is not recognized until the deduction reduces current income taxes payable. Since the additional tax benefit does not reduce our current income taxes payable for 2014 through 2016, these tax benefits are not included in our Federal loss carryovers deferred income tax assets. The additional tax benefits deductible for tax purposes but not included in our Federal loss carryovers deferred income tax assets were $38 million through 2016.

Cash payments for income taxes (net of refunds) were $5 million and $29 million in 2016 and 2014, respectively. Cash refunds for income taxes (net of payments and discontinued operations) were $136 million in 2015.

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The Williams Companies, Inc.

Notes to Consolidated Financial Statements – (Continued)

As of December 31, 2016, we had approximately $50 million of unrecognized tax benefits. If recognized, income tax expense would be reduced by $49 million and $51 million for 2016 and 2015, respectively, including the effect of these changes on other tax attributes, with state income tax amounts included net of federal tax effect. A reconciliation of the beginning and ending amount of unrecognized tax benefits is as follows:

	2016			2015
	(Millions)
Balance at beginning of period	$	55		$	89
Additions for tax positions of prior years	—			2
Reductions for tax positions of prior years	(4		)	—
Changes due to currency translation	(1		)	(36		)
Balance at end of period	$	50		$	55

We recognize related interest and penalties as a component of Provision (benefit) for income taxes. Total interest and penalties recognized as part of income tax provision were expenses of $300 thousand and $8 million for 2016 and 2014, respectively, and a benefit of $22 million for 2015, including a $35 million benefit due to currency fluctuation. Approximately $3 million and $2 million of interest and penalties primarily relating to uncertain tax positions have been accrued as of December 31, 2016 and 2015, respectively. Changes due to currency translation in 2015 reflects the unrecognized tax benefit portion of the previously described impact of changes in foreign currency exchange rates on the remeasurement of a foreign currency denominated balance.

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

Consolidated U.S Federal income tax returns are open to Internal Revenue Service (IRS) examination for years after 2010. As of December 31, 2016, examinations of tax returns for 2011 through 2013 are currently in process. We do not expect material changes in our financial position resulting from these examinations. The statute of limitations for most states expires one year after expiration of the IRS statute. Generally, tax returns for our Canadian entities are open to audit for tax years after 2011. Tax years 2013 and 2014 are currently under examination. We have indemnified the purchaser of our Canadian operations for any adjustments to Canadian tax returns for periods prior to the sale of our Canadian operations in September 2016.

In November 2015, the FASB issued ASU 2015-17 “Income Taxes (Topic 740): Balance Sheet Classification of Deferred Taxes” (ASU 2015-17). The standard requires that deferred income tax liabilities and assets, along with any related valuation allowance, be presented as noncurrent in a classified statement of financial position. The standard is effective for interim and annual periods beginning after December 15, 2016 and early adoption is permitted. We have elected to early adopt ASU 2015-17 prospectively as of December 31, 2016. TheConsolidated Balance Sheetas of December 31, 2015 was not retrospectively adjusted.

On September 13, 2013, the IRS issued final regulations providing guidance on the treatment of amounts paid to acquire, produce, or improve tangible property. On August 18, 2014, the IRS issued final regulations providing guidance on the dispositions of such property. The implementation date for these regulations was January 1, 2014. The IRS is expected to issue additional procedural guidance regarding how the requirements may be implemented for the gas transmission and distribution industry. Pending the issuance of this additional procedural guidance from the IRS, we cannot at this time estimate the impact of implementing the regulations for our gas transmission business, although we anticipate that it will result in an immaterial balance sheet only impact.

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The Williams Companies, Inc.

Notes to Consolidated Financial Statements – (Continued)

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

	Years Ended December 31,
	2016			2015			2014
	(Dollars in millions, except per-share amounts; shares in thousands)
Income (loss) from continuing operations attributable to The Williams Companies, Inc. available to common stockholders for basic and diluted earnings (loss) per common share	$	(424	)	$	(571	)	$	2,110
Basic weighted-average shares	750,673			749,271			719,325
Effect of dilutive securities:
Nonvested restricted stock units	—			—			2,234
Stock options	—			—			2,064
Convertible debentures	—			—			18
Diluted weighted-average shares (1)	750,673			749,271			723,641
Earnings (loss) per common share from continuing operations:
Basic	$	(.57	)	$	(.76	)	$	2.93
Diluted	$	(.57	)	$	(.76	)	$	2.91

(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.

Note 10 – Employee Benefit Plans

We have noncontributory defined benefit pension plans in which all eligible employees participate. Currently, eligible employees earn benefits primarily based on a cash balance formula. Various other formulas, as defined in the plan documents, are utilized to calculate the retirement benefits for plan participants not covered by the cash balance formula. At the time of retirement, participants may elect, to the extent they are eligible for the various options, to receive annuity payments, a lump sum payment, or a combination of a lump sum and annuity payments. In addition to our pension plans, we currently provide subsidized retiree medical and life insurance benefits (other postretirement benefits) to certain eligible participants. Generally, employees hired after December 31, 1991, are not eligible for the subsidized retiree medical benefits, except for participants that were employees or retirees of Transco Energy Company on December 31, 1995, and other miscellaneous defined participant groups. Subsidized retiree medical benefits for eligible participants age 65 and older are paid through contributions to health reimbursement accounts. Subsidized retiree medical benefits for eligible participants under age 65 are provided through a self-insured medical plan sponsored by us. The self-insured retiree medical plan provides for retiree contributions and contains other cost-sharing features such as deductibles, co-payments, and co-insurance. The accounting for these plans anticipates estimated future increases to our contribution levels to the health reimbursement accounts for participants age 65 and older, as well as future cost-sharing that is consistent with our expressed intent to increase the retiree contribution level generally in line with health care cost increases for participants under age 65.

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The Williams Companies, Inc.

Notes to Consolidated Financial Statements – (Continued)

Funded Status

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

	Pension Benefits						Other Postretirement Benefits
	2016			2015			2016			2015
	(Millions)
Change in benefit obligation:
Benefit obligation at beginning of year	$	1,464		$	1,544		$	202		$	233
Service cost	54			59			1			2
Interest cost	62			58			8			9
Plan participants’ contributions	—			—			2			2
Benefits paid	(130		)	(101		)	(15		)	(13		)
Actuarial loss (gain)	20			(91		)	(1		)	(31		)
Settlements	(4		)	(5		)	—			—
Net increase (decrease) in benefit obligation	2			(80		)	(5		)	(31		)
Benefit obligation at end of year	1,466			1,464			197			202
Change in plan assets:
Fair value of plan assets at beginning of year	1,241			1,293			201			208
Actual return on plan assets	82			(11		)	13			(1		)
Employer contributions	65			65			7			5
Plan participants’ contributions	—			—			2			2
Benefits paid	(130		)	(101		)	(15		)	(13		)
Settlements	(4		)	(5		)	—			—
Net increase (decrease) in fair value of plan assets	13			(52		)	7			(7		)
Fair value of plan assets at end of year	1,254			1,241			208			201
Funded status — overfunded (underfunded)	$	(212	)	$	(223	)	$	11		$	(1	)
Accumulated benefit obligation	$	1,440		$	1,432

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

	December 31,
	2016			2015
	(Millions)
Underfunded pension plans:
Current liabilities	$	(2	)	$	(2	)
Noncurrent liabilities	(210		)	(221		)
Overfunded (underfunded) other postretirement benefit plans:
Current liabilities	(7		)	(7		)
Noncurrent assets (liabilities)	18			6

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

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The Williams Companies, Inc.

Notes to Consolidated Financial Statements – (Continued)

The pension plans’ benefit obligation Actuarial loss (gain) of $20 million in 2016 is primarily due to the impact of a decrease in the discount rates utilized to calculate the benefit obligation. The pension plans’ benefit obligation Actuarial loss (gain)of$(91) million in 2015 is primarily due to the impact of a decrease in the assumed future interest crediting rate for the cash balance pension formula and an increase in the discount rates utilized to calculate the benefit obligation.

The 2015 benefit obligation Actuarial loss (gain) of $(31) million for our other postretirement benefit plans is primarily due to an increase in the discount rate used to calculate the benefit obligation, tax law changes, and other assumption changes.

At December 31, 2016 and 2015, all of our pension plans had a projected benefit obligation and accumulated benefit obligation in excess of plan assets.

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

	Pension Benefits						Other Postretirement Benefits
	2016			2015			2016			2015
	(Millions)
Amounts included in Accumulated other comprehensive income (loss):
Prior service credit	$	—		$	—		$	5		$	11
Net actuarial loss	(535		)	(544		)	(18		)	(18		)
Amounts included in regulatory liabilities associated with Transco and Northwest Pipeline:
Prior service credit	N/A			N/A			$	10		$	19
Net actuarial gain	N/A			N/A			8			6

In addition to the regulatory liabilities included in the previous table, differences in the amount of actuarially determined Net periodic benefit cost for our other postretirement benefit plans and the other postretirement benefit costs recovered in rates for Transco and Northwest Pipeline are deferred as a regulatory asset or liability. We have regulatory liabilities of $94 million at December 31, 2016 and $78 million at December 31, 2015, related to these deferrals. Additionally, Transco recognizes a regulatory liability for rate collections in excess of its amount funded to the tax-qualified pension plans. At December 31, 2016 and 2015, these regulatory liabilities were $21 million and $8 million, respectively. These pension and other postretirement plans amounts will be reflected in future rates based on the rate structures of these gas pipelines.

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The Williams Companies, Inc.

Notes to Consolidated Financial Statements – (Continued)

Net Periodic Benefit Cost

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

	Pension Benefits									Other Postretirement  Benefits
	2016			2015			2014			2016			2015			2014
	(Millions)
Components of net periodic benefit cost:
Service cost	$	54		$	59		$	40		$	1		$	2		$	2
Interest cost	62			58			62			8			9			10
Expected return on plan assets	(85		)	(75		)	(76		)	(12		)	(12		)	(12		)
Amortization of prior service credit	—			—			—			(15		)	(17		)	(20		)
Amortization of net actuarial loss	30			42			39			—			2			—
Net actuarial (gain) loss from settlements and curtailments	2			2			1			—			—			(1		)
Reclassification to regulatory liability	—			—			—			4			3			4
Net periodic benefit cost	$	63		$	86		$	66		$	(14	)	$	(13	)	$	(17	)

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

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

	Pension Benefits								Other Postretirement  Benefits
	2016			2015		2014			2016			2015			2014
	(Millions)
Other changes in plan assets and benefit obligations recognized in Other comprehensive income (loss):
Net actuarial gain (loss)	$	(23	)	$	5	$	(142	)	$	—		$	8		$	(18	)
Prior service (cost) credit	—			—		—			—			—			(1		)
Amortization of prior service credit	—			—		—			(6		)	(6		)	(8		)
Amortization of net actuarial loss	30			42		39			—			2			—
Loss from settlements and curtailments	2			2		1			—			—			1
Other changes in plan assets and benefit obligations recognized in Other comprehensive income (loss)	$	9		$	49	$	(102	)	$	(6	)	$	4		$	(26	)

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

	2016			2015			2014
	(Millions)
Other changes in plan assets and benefit obligations recognized in regulatory (assets) liabilities:
Net actuarial gain (loss)	$	2		$	10		$	(2	)
Amortization of prior service credit	(9		)	(11		)	(12		)

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The Williams Companies, Inc.

Notes to Consolidated Financial Statements – (Continued)

Pre-tax amounts expected to be amortized in Net periodic benefit cost in 2017 are as follows:

	Pension Benefits		Other Postretirement Benefits
	(Millions)
Amounts included in Accumulated other comprehensive income (loss):
Prior service credit	$	—	$	(5	)
Net actuarial loss	28		—
Amounts included in regulatory liabilities associated with Transco and Northwest Pipeline:
Prior service credit	N/A		$	(8	)
Net actuarial loss	N/A		—

Key Assumptions

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

	Pension Benefits				Other Postretirement Benefits
	2016		2015		2016		2015
Discount rate	4.17	%	4.38	%	4.27	%	4.50	%
Rate of compensation increase	4.87		4.88		N/A		N/A

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

	Pension Benefits						Other Postretirement  Benefits
	2016		2015		2014		2016		2015		2014
Discount rate	4.37	%	3.96	%	4.68	%	4.50	%	4.12	%	4.80	%
Expected long-term rate of return on plan assets	6.85		6.38		6.85		6.11		5.70		6.11
Rate of compensation increase	4.88		4.62		4.56		N/A		N/A		N/A

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

The assumed health care cost trend rate for 2017 is 7.5 percent. This rate decreases to 4.5 percent by 2025. A one-percentage-point change in assumed health care cost trend rates would have the following effects:

	Point increase		Point decrease
	(Millions)
Effect on total of service and interest cost components	$	—	$	—
Effect on other postretirement benefit obligation	6		(5		)

Plan Assets

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

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The Williams Companies, Inc.

Notes to Consolidated Financial Statements – (Continued)

approximately 38 percent of the other postretirement benefit plan assets are subject to income tax; therefore, certain investments are managed in a tax efficient manner.

The investment policy for the pension plans includes a general target asset allocation at December 31, 2016 of 60 percent equity securities and 40 percent fixed income securities. The target allocation includes the investments in equity and fixed income mutual funds and commingled investment funds. The investment policy allows for a broad range of asset allocations that permit the plans to de-risk in response to changes in the plans’ funded status.

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

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

The following securities and transactions are not authorized: unregistered securities, commodities or commodity contracts, short sales or margin transactions, or other leveraging strategies. Investment strategies using direct investments in derivative securities require approval and, historically, have not been used; however, these instruments may be used in mutual funds and commingled investment funds held by the plans’ trusts. Additionally, real estate equity, natural resource property, venture capital, leveraged buyouts, and other high-return, high-risk investments are generally restricted.

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

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The Williams Companies, Inc.

Notes to Consolidated Financial Statements – (Continued)

The fair values of our pension plan assets at December 31, 2016 and 2015 by asset class are as follows:

	2016
	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total
	(Millions)
Pension assets:
Cash management fund	$	14	$	—	$	—	$	14
Equity securities:
U.S. large cap	87		—		—		87
U.S. small cap	77		—		—		77
Fixed income securities (1):
U.S. Treasury securities	68		—		—		68
Government and municipal bonds	—		10		—		10
Mortgage and asset-backed securities	—		80		—		80
Corporate bonds	—		148		—		148
Insurance company investment contracts and other	—		5		—		5
	$	246	$	243	$	—	489
Commingled investment funds measured at net asset value practical expedient (3):
Equities — U.S. large cap							369
Equities — International small cap							27
Equities — International emerging markets							50
Equities — International developed markets							149
Fixed income — U.S. long duration							88
Fixed income — Corporate bonds							82
Total assets at fair value at December 31, 2016							$	1,254

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The Williams Companies, Inc.

Notes to Consolidated Financial Statements – (Continued)

	2015
	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total
	(Millions)
Pension assets:
Cash management fund	$	8	$	—	$	—	$	8
Equity securities:
U.S. large cap	83		—		—		83
U.S. small cap	64		—		—		64
Fixed income securities (1):
U.S. Treasury securities	65		—		—		65
Government and municipal bonds	—		8		—		8
Mortgage and asset-backed securities	—		87		—		87
Corporate bonds	—		145		—		145
Insurance company investment contracts and other	—		5		—		5
	$	220	$	245	$	—	465
Commingled investment funds measured at net asset value practical expedient (3):
Equities — U.S. large cap							367
Equities — International small cap							27
Equities — International emerging markets							50
Equities — International developed markets							153
Fixed income — U.S. long duration							95
Fixed income — Corporate bonds							84
Total assets at fair value at December 31, 2015							$	1,241

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The Williams Companies, Inc.

Notes to Consolidated Financial Statements – (Continued)

The fair values of our other postretirement benefits plan assets at December 31, 2016 and 2015 by asset class are as follows:

	2016
	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total
	(Millions)
Other postretirement benefit assets:
Cash management funds	$	11	$	—	$	—	$	11
Equity securities:
U.S. large cap	24		—		—		24
U.S. small cap	15		—		—		15
International developed markets large cap growth	—		5		—		5
Fixed income securities (2):
U.S. Treasury securities	7		—		—		7
Government and municipal bonds	—		1		—		1
Mortgage and asset-backed securities	—		8		—		8
Corporate bonds	—		15		—		15
Mutual fund — Municipal bonds	42		—		—		42
	$	99	$	29	$	—	128
Commingled investment funds measured at net asset value practical expedient (3):
Equities — U.S. large cap							38
Equities — International small cap							3
Equities — International emerging markets							5
Equities — International developed markets							16
Fixed income — U.S. long duration							9
Fixed income — Corporate bonds							9
Total assets at fair value at December 31, 2016							$	208

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The Williams Companies, Inc.

Notes to Consolidated Financial Statements – (Continued)

	2015
	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total
	(Millions)
Other postretirement benefit assets:
Cash management funds	$	11	$	—	$	—	$	11
Equity securities:
U.S. large cap	37		—		—		37
U.S. small cap	20		—		—		20
International developed markets large cap growth	1		9		—		10
Emerging markets growth	—		1		—		1
Fixed income securities (2):
U.S. Treasury securities	7		—		—		7
Government and municipal bonds	—		12		—		12
Mortgage and asset-backed securities	—		9		—		9
Corporate bonds	—		15		—		15
	$	76	$	46	$	—	122
Commingled investment funds measured at net asset value practical expedient (3):
Equities — U.S. large cap							37
Equities — International small cap							3
Equities — International emerging markets							5
Equities — International developed markets							16
Fixed income — U.S. long duration							10
Fixed income — Corporate bonds							8
Total assets at fair value at December 31, 2015							$	201

____________

(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.

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

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

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

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

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

The investment contracts with insurance companies are valued at fair value by discounting the cash flow of a bond using a yield to maturity based on an investment grade index or comparable index with a similar maturity value, maturity period, and nominal coupon rate.

There have been no significant changes in the preceding valuation methodologies used at December 31, 2016 and 2015. Additionally, there were no transfers or reclassifications of investments between Level 1 and Level 2 from December 2015 to December 2016. If transfers between levels had occurred, the transfers would have been recognized as of the end of the period.

Plan Benefit Payments and Employer Contributions

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

	Pension Benefits		Other Postretirement Benefits
	(Millions)
2017	$	99	$	13
2018	103		13
2019	103		13
2020	106		13
2021	111		13
2022-2026	562		62

In 2017, we expect to contribute approximately $60 million to our tax-qualified pension plans and approximately $2 million to our nonqualified pension plans, for a total of approximately $62 million, and approximately $7 million to our other postretirement benefit plans.

Defined Contribution Plans

We also maintain defined contribution plans for the benefit of substantially all of our employees. Generally, plan participants may contribute a portion of their compensation on a pre-tax and after-tax basis in accordance with the plans’ guidelines. We match employees’ contributions up to certain limits. Our matching contributions charged to expense were $36 million in 2016, $39 million in 2015, and $39 million in 2014.

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Note 11 – Property, Plant, and Equipment

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

	Estimated Useful Life  (1) (Years)	Depreciation Rates (1) (%)	December 31,
			2016			2015
			(Millions)
Nonregulated:
Natural gas gathering and processing facilities	5 - 40		$	20,413		$	20,789
Construction in progress	Not applicable		412			1,366
Other	2 - 45		2,202			2,170
Regulated:
Natural gas transmission facilities		1.20 - 6.97	12,692			12,189
Construction in progress	Not applicable	Not applicable	1,603			941
Other	5 - 45	1.35 - 33.33	1,590			1,584
Total property, plant, and equipment, at cost			38,912			39,039
Accumulated depreciation and amortization			(10,484		)	(9,460		)
Property, plant, and equipment — net			$	28,428		$	29,579

__________

(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.

Depreciation and amortization expense forProperty, plant, and equipment – net was $1,407 million, $1,382 million, and $967 million in 2016, 2015, and 2014, respectively.

Regulated Property, plant, and equipment – net includes approximately $665 million and $706 million at December 31, 2016 and 2015, respectively, related to amounts in excess of the original cost of the regulated facilities within our gas pipeline businesses as a result of our prior acquisitions. This amount is being amortized over 40 years using the straight-line amortization method. Current FERC policy does not permit recovery through rates for amounts in excess of original cost of construction.

Asset Retirement Obligations

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

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The following table presents the significant changes to our ARO, of which $801 million and $858 million are included in Regulatory liabilities, deferred income, and other with the remaining current portion in Accrued liabilities at December 31, 2016 and 2015, respectively.

	December 31,
	2016			2015
	(Millions)
Beginning balance	$	915		$	831
Liabilities incurred	24			42
Liabilities settled	(8		)	(3		)
Accretion expense	69			60
Revisions (1)	(138		)	(15		)
Ending balance	$	862		$	915

___________

(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.

The funds Transco collects through a portion of its rates to fund its ARO are deposited into an external trust account dedicated to funding its ARO (ARO Trust). (See Note 17 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk.) Under its current rate settlement, Transco’s annual funding obligation is approximately $36 million, with installments to be deposited monthly.

Note 12 – Goodwill and Other Intangible Assets

Goodwill

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

	Williams Partners
	(Millions)
December 31, 2014	$	1,120
Purchase accounting adjustment	25
Impairment	(1,098		)
December 31, 2015	$	47
December 31, 2016	$	47

Our goodwill is not subject to amortization, but is evaluated at least annually for impairment or more frequently if impairment indicators are present. We did not identify or recognize any impairments to goodwill in connection with our annual evaluation of goodwill for impairment (performed as of October 1) during the years ended December 31, 2016 and 2014. During 2015, we performed an interim assessment and an annual assessment as of September 30, 2015 and October 1, 2015, respectively, of certain goodwill within the Williams Partners segment. The estimated fair value of the reporting units evaluated exceeded their carrying amounts, and thus no impairment was identified. We performed an additional goodwill impairment evaluation as of December 31, 2015, of the goodwill recorded within the Williams Partners segment. As a result of this evaluation, we recorded goodwill impairment charges totaling $1.098 billion. (See Note 17 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk.)

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Other Intangible Assets

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

	2016					2015
	Gross Carrying Amount		Accumulated Amortization			Gross Carrying Amount		Accumulated Amortization
	(Millions)
Contractual customer relationships	$	10,635	$	(1,019	)	$	10,633	$	(663	)

Other intangible assets primarily relate to gas gathering, processing, and fractionation contractual customer relationships recognized in the ACMP and Eagle Ford acquisitions (see Note 2 – Acquisitions) as well as previous acquisitions. Other intangible assets are being amortized on a straight-line basis over an initial period of 30 years which represents a portion of the term over which the contractual customer relationships are expected to contribute to our cash flows.

We expense costs incurred to renew or extend the terms of our gas gathering, processing, and fractionation contracts with customers. Based on the estimated future revenues during the contract periods (as estimated at the time of the respective acquisition), the weighted-average periods prior to the next renewal or extension of the contractual customer relationships associated with the ACMP and Eagle Ford acquisitions were approximately 17 years and 10 years, respectively. Although a significant portion of the expected future cash flows associated with these contractual customer relationships are dependent on our ability to renew or extend the arrangements beyond the initial contract periods, these expected future cash flows are significantly influenced by the scope and pace of our producer customers’ drilling programs. Once producer customers’ wells are connected to our gathering infrastructure, their likelihood of switching to another provider before the wells are abandoned is reduced due to the significant capital investment required.

The amortization expense related to other intangible assets was $356 million, $353 million, and $209 million in 2016, 2015, and 2014, respectively. The estimated amortization expense for each of the next five succeeding fiscal years is approximately $356 million.

Note 13 – Accrued Liabilities

	December 31,
	2016		2015
	(Millions)
Deferred income	$	338	$	94
Interest on debt	310		284
Employee costs	223		215
Refundable deposits	160		—
Special distribution repayable to Gulfstream (See Note 6 - Investing Activities)	—		149
Asset retirement obligations	61		57
Other, including other loss contingencies	356		279
	$	1,448	$	1,078

Deferred income in 2016 includes cash proceeds associated with restructuring certain gas gathering contracts in the Barnett Shale and Mid-Continent regions. (See Note 1 – General, Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies.)

Refundable deposits in 2016 includes receipts related to an agreement to resolve several matters in relation to Transco’s Hillabee Expansion Project. In accordance with the agreement, the member–sponsors of Sabal Trail will pay WPZ an aggregate amount of $240 million in three equal installments as certain milestones of the project are met, of

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which $160 million was received in 2016. WPZ expects to recognize income associated with these receipts over the term of an underlying contract once the project is in service.

Note 14 – Debt, Banking Arrangements, and Leases

Long-Term Debt

	December 31,
	2016		2015
	(Millions)
Unsecured:
Transco:
6.4% Notes due 2016 (1)	$	—	$	200
6.05% Notes due 2018	250		250
7.08% Debentures due 2026	8		8
7.25% Debentures due 2026	200		200
7.85% Notes due 2026	1,000		—
5.4% Notes due 2041	375		375
4.45% Notes due 2042	400		400
Northwest Pipeline:
7% Notes due 2016	—		175
5.95% Notes due 2017	185		185
6.05% Notes due 2018	250		250
7.125% Debentures due 2025	85		85
WPZ:
7.25% Notes due 2017	600		600
5.25% Notes due 2020	1,500		1,500
4.125% Notes due 2020	600		600
4% Notes due 2021	500		500
3.6% Notes due 2022	1,250		1,250
3.35% Notes due 2022	750		750
6.125% Notes due 2022	750		750
4.5% Notes due 2023	600		600
4.875% Notes due 2023	1,400		1,400
4.3% Notes due 2024	1,000		1,000
4.875% Notes due 2024	750		750
3.9% Notes due 2025	750		750
4% Notes due 2025	750		750
6.3% Notes due 2040	1,250		1,250
5.8% Notes due 2043	400		400
5.4% Notes due 2044	500		500
4.9% Notes due 2045	500		500
5.1% Notes due 2045	1,000		1,000
Term Loan, variable interest rate, due 2018	850		850
Credit facility loans	—		1,310
WMB:
7.875% Notes due 2021	371		371
3.7% Notes due 2023	850		850
4.55% Notes due 2024	1,250		1,250
7.5% Debentures due 2031	339		339

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	December 31,
	2016			2015
	(Millions)
7.75% Notes due 2031	252			252
8.75% Notes due 2032	445			445
5.75% Notes due 2044	650			650
Various — 5.5% to 10.25% Notes and Debentures due 2019 to 2033	55			55
Credit facility loans	775			650
Capital lease obligations	—			1
Debt issuance costs	(119		)	(123		)
Net unamortized debt premium (discount)	88			110
Total long-term debt, including current portion	23,409			23,988
Long-term debt due within one year	(785		)	(176		)
Long-term debt	$	22,624		$	23,812

___________

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

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

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

	December 31, 2016
	(Millions)
2017	$	785
2018	1,350
2019	32
2020	2,896
2021	871

Issuances and retirements

WPZ retired $600 million of 7.25 percent senior unsecured notes that matured on February 1, 2017.

Northwest Pipeline retired $175 million of 7 percent senior unsecured notes that matured on June 15, 2016.

Transco retired $200 million of 6.4 percent senior unsecured notes that matured on April 15, 2016.

On January 22, 2016, Transco issued $1 billion of 7.85 percent senior unsecured notes due 2026 to investors in a private debt placement. In January 2017, Transco completed an exchange of these notes for substantially identical new notes that are registered under the Securities Act of 1933, as amended. Transco used the net proceeds to repay debt and to fund capital expenditures.

In December 2015, WPZ borrowed $850 million on a variable interest rate loan with certain lenders due 2018. At December 31, 2016, the interest rate was 2.50 percent. WPZ used the proceeds for working capital, capital expenditures, and for general partnership purposes.

On April 15, 2015, WPZ paid $783 million, including a redemption premium, to early retire $750 million of 5.875 percent senior notes due 2021 with a carrying value of $797 million.

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On March 3, 2015, WPZ completed a public offering of $1.25 billion of 3.6 percent senior unsecured notes due 2022, $750 million of 4 percent senior unsecured notes due 2025, and $1 billion of 5.1 percent senior unsecured notes due 2045. WPZ used the net proceeds to repay amounts outstanding under its commercial paper program and credit facility, to fund capital expenditures, and for general partnership purposes.

WPZ retired $750 million of 3.8 percent senior unsecured notes that matured on February 15, 2015.

Credit Facilities

	December 31, 2016
	Available		Outstanding
	(Millions)
WMB
Long-term credit facility	$	1,500	$	775
Letters of credit under certain bilateral bank agreements			13
WPZ
Long-term credit facility (1)	3,500		—
Letters of credit under certain bilateral bank agreements			1

________________

(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.

WMB long-term credit facility

On February 2, 2015, we entered into the Second Amended and Restated Credit Agreement. The aggregate commitments available remained at $1.5 billion, with up to an additional $500 million increase in aggregate commitments available under certain circumstances. The maturity date of the credit facility was extended to February 2, 2020. However, we may request up to two extensions of the maturity date each for an additional one year period to allow a maturity date as late as February 2, 2022, under certain circumstances. The agreement also allows for swing line loans up to an aggregate amount of $50 million, subject to available capacity under the credit facility, and the letters of credit up to $675 million.

The agreements governing the credit facilities contain the following terms and conditions:

• Various covenants may limit, among other things, a borrower’s and its material subsidiaries’ ability to grant certain liens supporting indebtedness, merge or consolidate, sell all or substantially all of its assets, 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.

• 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.

Significant financial covenants under the agreement require the ratio of debt to EBITDA (each as defined in the credit agreement) be no greater than 5 to 1, except for 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.

We are in compliance with these financial covenants as measured at December 31, 2016.

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As of February 20, 2017, $235 million is outstanding under our long-term credit facility.

WPZ long-term credit facilities

Prior to their merger both WPZ and ACMP had separate credit facilities that terminated on February 2, 2015.

On February 2, 2015, WPZ along with Transco, Northwest Pipeline, the lenders named therein, and an administrative agent entered into the Second Amended & Restated Credit Agreement with aggregate commitments available of $3.5 billion, with up to an additional $500 million increase in aggregate commitments available under certain circumstances. The maturity date of the credit facility is February 2, 2020. However, the co-borrowers may request up to two extensions of the maturity date each for an additional one year period to allow a maturity date as late as February 2, 2022, under certain circumstances. The agreement allows for swing line loans up to an aggregate amount of $150 million, subject to available capacity under the credit facility, and letters of credit commitments of $1.125 billion. Transco and Northwest Pipeline are each able to borrow up to $500 million under this credit facility to the extent not otherwise utilized by the other co-borrowers. On December 18, 2015, WPZ along with Transco, Northwest Pipeline, the lenders named therein and an administrative agent entered into the Amendment No. 1 to Second Amended & Restated Credit Agreement modifying the thresholds specified in the covenant related to the maximum ratio of WPZ’s debt to EBITDA.

The agreement governing this credit facility contains the following terms and conditions:

• Various covenants may limit, among other things, a borrower’s and its material subsidiaries’ ability to grant certain liens supporting indebtedness, merge or consolidate, sell all or substantially all of its assets, 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.

Significant financial covenants under the agreement require the ratio of debt to EBITDA, each as defined in the credit facility, be no greater than:

• 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 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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The ratio of debt to capitalization (defined as net worth plus debt) must be no greater than 65 percent for each Transco and Northwest Pipeline. WPZ is in compliance with these financial covenants as measured at December 31, 2016.

As of February 20, 2017, there are no amounts outstanding under the long-term credit facility.

WPZ short-term credit facilities

On August 26, 2015, WPZ entered into a $1.0 billion short-term credit facility. On December 23, 2015, WPZ’s short-term credit facility capacity decreased to $150 million in conjunction with entering into the $850 million term loan. The $150 million short-term credit facility is no longer available as it expired August 24, 2016.

Commercial Paper Program

On February 2, 2015, WPZ amended and restated the commercial paper program for the ACMP Merger and to allow a maximum outstanding amount of unsecured commercial paper notes of $3 billion. The maturities of the commercial paper notes vary but may not exceed 397 days from the date of issuance. The commercial paper notes are sold under customary terms in the commercial paper market and are issued at a discount from par, or, alternatively, are sold at par and bear varying interest rates on a fixed or floating basis. Proceeds from these notes are used for general partnership purposes, including funding capital expenditures, working capital, and partnership distributions. We classify WPZ’s commercial paper outstanding in Current liabilities in the Consolidated Balance Sheet, as the outstanding notes at December 31, 2016 and December 31, 2015, have maturity dates less than three months from the date of issuance. At December 31, 2016, WPZ had $93 million in Commercial paper outstanding at a weighted-average interest rate of 1.06 percent and at December 31, 2015, WPZ had $499 million in Commercial paper outstanding at a weighted-average interest rate of 0.92 percent.

Cash Payments for Interest (Net of Amounts Capitalized)

Cash payments for interest (net of amounts capitalized)were $1.152 billion in 2016, $1.023 billion in 2015, and $681 million in 2014.

Restricted Net Assets of Subsidiaries

We have considered the guidance in the Securities and Exchange Commission’s Regulation S-X related to restricted net assets of subsidiaries. In accordance with Rule 4-08(e) of Regulation S-X, we have determined that certain net assets of our subsidiaries are considered restricted under this guidance and exceed 25 percent of our consolidated net assets. As of December 31, 2016, substantially all of these restricted net assets relate to the net assets of WPZ, which are technically considered restricted under this accounting rule due to terms within WPZ’s partnership agreement that govern the partnerships’ assets. Our interest in WPZ’s net assets that are considered to be restricted at December 31, 2016, was $13 billion.

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Leases-Lessee

The future minimum annual rentals under noncancelable operating leases, are payable as follows:

	December 31, 2016
	(Millions)
2017	$	62
2018	58
2019	51
2020	46
2021	35
Thereafter	90
Total	$	342

Total rent expense was $64 million in 2016, $69 million in 2015, and $62 million in 2014 and primarily included in Operating and maintenance expenses and Selling, general, and administrative expenses in the Consolidated Statement of Operations.

Other

On January 25, 2017, WPZ announced that it will redeem all of its $750 million6.125 percent senior notes due 2022 on February 23, 2017.

Note 15 – Stockholders' Equity

Cash dividends declared per common share were $1.68, $2.45, and $1.9575 for 2016, 2015, and 2014, respectively. On February 20, 2017, our board of directors approved a regular quarterly dividend of $0.30 per share payable on March 27, 2017.

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

On June 23, 2014, we issued 61 million shares of common stock in a public offering at a price of $57.00 per share. That amount includes 8 million shares purchased pursuant to the full exercise of the underwriter’s option to purchase additional shares. The net proceeds of $3.378 billion were used in July 2014 to finance a portion of the ACMP Acquisition. (See Note 2 - Acquisitions.)

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AOCI

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

	Cash Flow Hedges			Foreign Currency Translation			Pension and Other Post Retirement Benefits			Total
	(Millions)
Balance at December 31, 2015	$	(1	)	$	(103	)	$	(338	)	$	(442	)
Other comprehensive income (loss) before reclassifications	2			25			(15		)	12
Amounts reclassified from accumulated othercomprehensive income (loss)	(1		)	76			16			91
Other comprehensive income (loss)	1			101			1			103
Balance at December 31, 2016	$	—		$	(2	)	$	(337	)	$	(339	)

Reclassifications out of AOCI are presented in the following table by component for the year ended December 31, 2016:

Component	Reclassifications			Classification
	(Millions)
Cash flow hedges:
Energy commodity contracts	$	(3	)	Product sales
Total cash flow hedges	(3		)
Pension and other postretirement benefits:
Amortization of prior service cost (credit) included in net periodic benefit cost	(6		)	Note 10 – Employee Benefit Plans
Amortization of actuarial (gain) loss included in net periodic benefit cost	32			Note 10 – Employee Benefit Plans
Total pension and other postretirement benefits	26
Foreign currency translation:
Reclassification of cumulative foreign currency translation adjustment upon sale of foreign entities	155			Other (income) expense - net
Total before tax	178
Income tax benefit	(45		)	Provision (benefit) for income taxes
Net of income tax	133
Noncontrolling interest	(42		)	Net income (loss) attributable to noncontrolling interests
Reclassifications during the period	$	91

Note 16 – Equity-Based Compensation

Williams’ Plan Information

On May 17, 2007, our stockholders approved The Williams Companies, Inc. 2007 Incentive Plan (the Plan) that provides common-stock-based awards to both employees and nonmanagement directors and reserved 19 million new shares for issuance. On May 20, 2010 and May 22, 2014, our stockholders approved amendments and restatements of the Plan to increase by 11 million and 10 million, respectively, the number of new shares authorized for making awards under the Plan, among other changes. The Plan permits the granting of various types of awards including, but not limited

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to, restricted stock units and stock options. At December 31, 2016, 27 million shares of our common stock were reserved for issuance pursuant to existing and future stock awards, of which 17 million shares were available for future grants.

Additionally, on May 17, 2007, our stockholders approved an Employee Stock Purchase Plan (ESPP) which authorized up to 2 million new shares of our common stock to be available for sale under the ESPP. On May 22, 2014, our stockholders approved an amendment and restatement of the ESPP to increase by 1.6 million the number of new shares authorized for sale under the ESPP. The ESPP enables eligible participants to purchase our common stock through payroll deductions not exceeding an annual amount of $15,000 per participant. The ESPP provides for offering periods during which shares may be purchased and continues until the earliest of (1) the Board of Directors terminates the ESPP, (2) the sale of all shares available under the ESPP, or (3) the tenth anniversary of the date the amended and restated ESPP was approved by the stockholders. Offering periods are from January through June and from July through December. Generally, all employees are eligible to participate in the ESPP, with the exception of executives and international employees. The number of shares eligible for an employee to purchase during each offering period is limited to 750 shares. The purchase price of the stock is 85 percent of the lower closing price of either the first or the last day of the offering period. The ESPP requires a one-year holding period before the stock can be sold. The plan was suspended during the period from January 1, 2016 to August 31, 2016, and was reinstated effective September 1, 2016. Employees purchased111 thousand shares at an average price of $23.93 per share during the period from September 1, 2016 to December 31, 2016. Approximately 1.4 million shares were available for purchase under the ESPP at December 31, 2016.

Operating and maintenance expenses and Selling, general and administrative expenses include equity-based compensation expense for the years ended December 31, 2016, 2015, and 2014 of $53 million, $56 million, and $44 million, respectively. Income tax benefit recognized related to the stock-based compensation expense for the years ended December 31, 2016, 2015, and 2014 was $20 million, $21 million, and $17 million, respectively. Measured but unrecognized stock-based compensation expense at December 31, 2016, was $67 million, which does not include the effect of estimated forfeitures of $2 million. Unrecognized stock-based compensation expense is comprised of $5 million related to stock options and $62 million related to restricted stock units. These amounts are expected to be recognized over a weighted-average period of 1.9 years.

Stock Options

Stock options are valued at the date of award, which does not precede the approval date. The purchase price per share for stock options may not be less than the market price of the underlying stock on the date of grant. Stock options generally become exercisable over a three-year period from the date of grant. Stock options generally expire ten years after the grant.

The following summary reflects stock option activity and related information for the year ended December 31, 2016:

Stock Options	Options		Weighted- Average Exercise Price		Aggregate Intrinsic Value
	(Millions)				(Millions)
Outstanding at December 31, 2015	5.7		$	31.51
Granted	0.9		$	24.99
Exercised	(0.3	)	$	17.84
Cancelled	(0.1	)	$	24.04
Outstanding at December 31, 2016	6.2		$	31.32	$	28
Exercisable at December 31, 2016	5.0		$	29.75	$	23

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

	Years Ended December 31,
	2016		2015		2014
	(Millions)
Total intrinsic value of options exercised	$	2	$	37	$	48
Tax benefits realized on options exercised	$	1	$	13	$	18
Cash received from the exercise of options	$	4	$	20	$	31

The weighted-average remaining contractual life for stock options outstanding and exercisable at December 31, 2016, was 5.5 years and 4.2 years, respectively.

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

	2016			2015			2014
Weighted-average grant date fair value of options for our common stock granted during the year, per share	$	7.90		$	7.61		$	7.50
Weighted-average assumptions:
Dividend yield	3.2		%	4.8		%	4.2		%
Volatility	44.7		%	27.8		%	28.0		%
Risk-free interest rate	1.2		%	1.8		%	2.2		%
Expected life (years)	6.0			6.0			6.5

The 2016 expected dividend yield is based on the 2016 dividend forecast and the grant-date market price of our stock. Expected volatility is based on the average of our peer group 10-year historical volatility adjusted by a ratio of our implied volatility to the adjusted average of our peer group’s implied volatility. The adjustment is made because the difference in implied volatility between our peer group and us may indicate that we are expected to be more volatile than our peer group average. The risk-free interest rate is based on the U.S. Treasury Constant Maturity rates as of the grant date. The expected life of the option is based on historical exercise behavior and expected future experience.

Nonvested Restricted Stock Units

The following summary reflects nonvested restricted stock unit activity and related information for the year ended December 31, 2016:

Restricted Stock Units Outstanding	Shares		Weighted- Average Fair Value (1)
	(Millions)
Nonvested at December 31, 2015	3.4		$	39.38
Granted	1.5		$	26.51
Forfeited	(0.1	)	$	38.18
Vested	(0.9	)	$	35.49
Nonvested at December 31, 2016	3.9		$	35.19

______________

(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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Value of Restricted Stock Units	2016		2015		2014
Weighted-average grant date fair value of restricted stock units granted during the year, per share	$	26.51	$	40.15	$	42.79
Total fair value of restricted stock units vested during the year ($’s in millions)	$	32	$	42	$	27

Performance-based restricted stock units granted under the Plan represent40 percent of nonvested restricted stock units outstanding at December 31, 2016. These grants may be earned at the end of the vesting period based on actual performance against a performance target. Based on the extent to which certain financial targets are achieved, vested shares may range from zero percent to 500 percent of the original grant amount.

WPZ’s Plan Information

During 2014, certain employees of ACMP’s general partner received equity-based compensation through ACMP’s equity-based compensation program. The fair value of the awards issued was based on the fair market value of the common units on the date of grant. This value is being amortized over the vesting period, which is one to four years from the date of grant. These awards were converted to WPZ equity-based awards in accordance with the terms of the ACMP Merger. No additional grants of restricted common units were awarded through WPZ’s equity-based compensation programs in 2016 or 2015, and no additional grants are expected in the future. Equity-based compensation expense of $20 million, $29 million, and $11 million related to WPZ’s equity-based compensation program is included in Operating and maintenance expenses andSelling, general, and administrative expenses for the years ended December 31, 2016, 2015, and 2014, respectively. As of December 31, 2016, there was $11 million of unrecognized compensation expense attributable to the outstanding awards, which does not include the effect of estimated forfeitures of $1 million. These amounts are expected to be recognized over a weighted average period of 1.2 years.

The following summary reflects nonvested WPZ restricted common unit activity and related information for the year ended December 31, 2016:

Restricted Common Units Outstanding	Units		Weighted- Average Fair Value
	(Millions)
Nonvested at December 31, 2015	1.2		$	55.93
Forfeited	(0.1	)	$	52.85
Vested	(0.5	)	$	59.09
Nonvested at December 31, 2016	0.6		$	52.97

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Note 17 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk

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

							Fair Value Measurements Using
	Carrying Amount			Fair Value			Quoted Prices In Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)
	(Millions)
Assets (liabilities) at December 31, 2016:
Measured on a recurring basis:
ARO Trust investments	$	96		$	96		$	96	$	—		$	—
Energy derivatives assets designated as hedging instruments	2			2			—		2			—
Energy derivatives assets not designated as hedging instruments	1			1			—		—			1
Energy derivatives liabilities not designated as hedging instruments	(6		)	(6		)	—		—			(6		)
Additional disclosures:
Other receivables	15			15			15		—			—
Long-term debt, including current portion	(23,409		)	(24,090		)	—		(24,090		)	—
Guarantees	(44		)	(30		)	—		(14		)	(16		)
Assets (liabilities) at December 31, 2015:
Measured on a recurring basis:
ARO Trust investments	$	67		$	67		$	67	$	—		$	—
Energy derivatives assets not designated as hedging instruments	5			5			—		3			2
Energy derivatives liabilities not designated as hedging instruments	(2		)	(2		)	—		—			(2		)
Additional disclosures:
Other receivables	12			30			10		2			18
Long-term debt, including current portion (1)	(23,987		)	(19,606		)	—		(19,606		)	—
Guarantee	(29		)	(16		)	—		(16		)	—

___________

(1) Excludes capital leases.

Fair Value Methods

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

Assets and liabilities measured at fair value on a recurring basis

ARO Trust investments: Transco deposits a portion of its collected rates, pursuant to its rate case settlement, into an external trust that is specifically designated to fund future asset retirement obligations. The ARO Trust invests in a

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portfolio of actively traded mutual funds that are measured at fair value on a recurring basis based on quoted prices in an active market, is classified as available-for-sale, and is reported in Regulatory assets, deferred charges, and other in the Consolidated Balance Sheet. Both realized and unrealized gains and losses are ultimately recorded as regulatory assets or liabilities.

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

Reclassifications of fair value between Level 1, Level 2, and Level 3 of the fair value hierarchy, if applicable, are made at the end of each quarter. No transfers between Level 1 and Level 2 occurred during the years ended December 31, 2016 or 2015.

Additional fair value disclosures

Other receivables: Other receivables primarily consist of margin deposits, which are reported in Other current assets and deferred charges in the Consolidated Balance Sheet. The disclosed fair value of our margin deposits is considered to approximate the carrying value generally due to the short-term nature of these items.

Other receivables also include a receivable related to the sale of certain former Venezuela assets. The disclosed fair value of this receivable is determined by an income approach. We calculated the net present value of a probability-weighted set of cash flows utilizing assumptions based on contractual terms, historical payment patterns by the counterparty, future probabilities of default, our likelihood of using arbitration if the counterparty does not perform, and discount rates. We determined the fair value of the receivable to be $18 million at December 31, 2015. We received two payments in 2016. The carrying value of this receivable iszero at December 31, 2016 and December 31, 2015.

Long-term debt: The disclosed fair value of our long-term debt is determined by a market approach using broker quoted indicative period-end bond prices. The quoted prices are based on observable transactions in less active markets for our debt or similar instruments.

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

To estimate the disclosed fair value of the WilTel guarantee, an estimated default rate is applied to the sum of the future contractual lease payments using an income approach. The estimated default rate is determined by obtaining the average cumulative issuer-weighted corporate default rate based on the credit rating of WilTel’s current owner and the term of the underlying obligation. The default rate is published by Moody’s Investors Service. The carrying value of the WilTel guarantee is reported in Accrued liabilities in the Consolidated Balance Sheet. The maximum potential undiscounted exposure is approximately $32 million at December 31, 2016. Our exposure declines systematically through the remaining term of WilTel’s obligation.

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

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We are required by our revolving credit agreements to indemnify lenders for certain taxes required to be withheld from payments due to the lenders and for certain tax payments made by the lenders. The maximum potential amount of future payments under these indemnifications is based on the related borrowings and such future payments cannot currently be determined. These indemnifications generally continue indefinitely unless limited by the underlying tax regulations and have no carrying value. We have never been called upon to perform under these indemnifications and have no current expectation of a future claim.

Nonrecurring fair value measurements

We performed an interim assessment of the goodwill associated with our former Central and Northeast G&P reporting units as of September 30, 2015, and the annual assessment of goodwill associated with our Northeast G&P and West reporting units as of October 1, 2015. No impairment charges were required following these evaluations.

During the fourth quarter of 2015, we observed a significant decline in the market values of WPZ and comparable midstream companies within the industry. This served to reduce our estimate of enterprise value and increased our estimates of discount rates. As a result, we performed an impairment assessment as of December 31, 2015, of the goodwill associated with these reporting units, all within the Williams Partners segment.

We estimated the fair value of each reporting unit based on an income approach utilizing discount rates specific to the underlying businesses of each reporting unit. These discount rates considered variables unique to each business area, including equity yields of comparable midstream businesses, expectations for future growth, and customer performance considerations. Weighted-average discount rates utilized ranged from approximately 10 percent to 13 percent across the three reporting units.

As a result of the increases in discount rates during the fourth quarter of 2015, coupled with certain reductions in estimated future cash flows determined during the same period, the fair values of the Central and Northeast G&P reporting units were determined to be below their respective carrying values. For these measurements, the book basis of each reporting unit was reduced by the associated deferred tax liabilities. We then calculated the implied fair value of goodwill by performing a hypothetical application of the acquisition method wherein the estimated fair value was allocated to the underlying assets and liabilities of each reporting unit. As a result of these Level 3 measurements, we determined that the previously recorded goodwill associated with each reporting unit was fully impaired, resulting in a fourth-quarter 2015 noncash charge of $1,098 million, reflected in Impairment of goodwill in the Consolidated Statement of Operations. For the West reporting unit, the estimated fair value exceeded the carrying value and no impairment was recorded.

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The following table presents impairments of assets and investments associated with certain nonrecurring fair value measurements within Level 3 of the fair value hierarchy.

						Impairments
						Years Ended December 31,
	Classification	Segment	Date of Measurement	Fair Value		2016		2015		2014
				(Millions)
Surplus equipment (1)	Property, plant, and equipment – net	Williams Partners	June 30, 2014	$	46					$	17
Surplus equipment (1)	Property, plant, and equipment – net	Williams Partners	December 31, 2014	32						13
Surplus equipment (1)	Property, plant, and equipment – net	Williams Partners	June 30, 2015	17				$	20
Surplus equipment (1)	Assets held for sale	Williams Partners	December 31, 2014	1						12
Previously capitalized project development costs (2)	Property, plant, and equipment – net	Williams Partners	December 31, 2015	13				94
Previously capitalized project development costs (3)	Property, plant, and equipment – net	Other	December 31, 2015	40				64
Canadian operations (4)	Assets held for sale	Williams Partners	June 30, 2016	924		$	341
Canadian operations (4)	Assets held for sale	Other	June 30, 2016	206		406
Certain gathering operations (5)	Property, plant, and equipment – net	Williams Partners	June 30, 2016	18		48
Certain idle assets	Property, plant, and equipment – net	Other	December 31, 2016	73		8
Level 3 fair value measurements of certain assets						803		178		42
Other impairments and write-downs (6)						70		31		10
Impairment of certain assets						$	873	$	209	$	52
Equity-method investments (7)	Investments	Williams Partners	September 30, 2015	$	1,203			$	461
Equity-method investments (8)	Investments	Williams Partners	December 31, 2015	4,017				890
Equity-method investments (9)	Investments	Williams Partners	March 31, 2016	1,294		$	109
Equity-method investments (10)	Investments	Williams Partners	December 31, 2016	1,295		318
Other equity-method investment	Investments	Williams Partners	December 31, 2015	58				8
Other equity-method investment	Investments	Williams Partners	March 31, 2016	—		3
Impairment of equity-method investments						$	430	$	1,359

______________

(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 rates. The determination of estimated future cash flows involved significant assumptions regarding gathering

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volumes, rates, and related capital spending. The discount rate utilized for the Appalachia Midstream Investments evaluation was 10.2 percent and reflected our 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.

Concentration of Credit Risk

Cash equivalents

Our cash equivalents are primarily invested in funds with high-quality, short-term securities and instruments that are issued or guaranteed by the U.S. government.

Trade accounts and other receivables

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

	December 31,
	2016		2015
	(Millions)
NGLs, natural gas, and related products and services	$	736	$	823
Transportation of natural gas and related products	187		202
Other	15		16
Total	$	938	$	1,041

Customers include producers, distribution companies, industrial users, gas marketers, and pipelines primarily located in the continental United States. As a general policy, collateral is not required for receivables, but customers’ financial condition and credit worthiness are evaluated regularly. Based upon this evaluation, we may obtain collateral to support receivables. As of December 31, 2016 and 2015, Chesapeake Energy Corporation, and its affiliates (Chesapeake), a customer within our Williams Partners segment, accounted for $133 million and $364 million, respectively, of the consolidated Trade accounts and other receivables balances.

Revenues

In 2016 and 2015, Chesapeake accounted for 14 percent and 18 percent, respectively, of our consolidated revenues.

Note 18 – Contingent Liabilities and Commitments

Reporting of Natural Gas-Related Information to Trade Publications

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

In the individual action, filed by Farmland Industries Inc. (Farmland), the court issued an order on May 24, 2016, granting one of our co-defendant’s motion for summary judgment as to Farmland’s claims. On January 5, 2017, the court extended such ruling to us, entering final judgment in our favor. Farmland has appealed.

Because of the uncertainty around the remaining pending unresolved issues, including an insufficient description of the purported classes and other related matters, we cannot reasonably estimate a range of potential exposure at this time. However, it is reasonably possible that the ultimate resolution of these actions and our related indemnification

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obligation could result in a potential loss that may be material to our results of operations. In connection with this indemnification, we have an accrued liability balance associated with this matter, and as a result, have exposure to future developments in this matter.

Geismar Incident

On June 13, 2013, an explosion and fire occurred at our Geismar olefins plant and rendered the facility temporarily inoperable (Geismar Incident). As a result, there were two fatalities and numerous individuals (including employees and contractors) reported injuries. We are addressing the following contingent liabilities in connection with the Geismar Incident.

On October 21, 2013, the U.S. Environmental Protection Agency (EPA) issued an Inspection Report pursuant to the Clean Air Act’s Risk Management Program following its inspection of the facility on June 24 through June 28, 2013. The report notes the EPA’s preliminary determinations about the facility’s documentation regarding process safety, process hazard analysis, as well as operating procedures, employee training, and other matters. On June 16, 2014, we received a request for information related to the Geismar Incident from the EPA under Section 114 of the Clean Air Act to which we responded on August 13, 2014. The EPA could issue penalties pertaining to final determinations.

Multiple lawsuits, including class actions for alleged offsite impacts, property damage, customer claims, and personal injury, have been filed against us. To date, we have settled certain of the personal injury claims for an aggregate immaterial amount that we have recovered from our insurers. The first two trials, for nine plaintiffs claiming personal injury, were held in Louisiana state court in Iberville Parish, Louisiana in September and November 2016. The juries returned adverse verdicts against us, our subsidiary Williams Olefins, LLC, and other defendants. The defendants, including us, intend to appeal the verdicts. Trial dates for additional plaintiffs are scheduled in April 2017 and August 2017. We believe it is probable that additional losses will be incurred on some lawsuits, while for others we believe it is only reasonably possible that losses will be incurred. However, due to ongoing litigation involving defenses to liability, the number of individual plaintiffs, limited information as to the nature and extent of all plaintiffs’ damages, and the ultimate outcome of all appeals, we are unable to reliably estimate any such losses at this time. We believe that it is probable that any ultimate losses incurred will be covered by our general liability insurance policy, which has an aggregate limit of $610 million applicable to this event and retention (deductible) of $2 million per occurrence.

Alaska Refinery Contamination Litigation

In 2010, James West filed a class action lawsuit in state court in Fairbanks, Alaska on behalf of individual property owners whose water contained sulfolane contamination allegedly emanating from the Flint Hills Oil Refinery in North Pole, Alaska. The suit named our subsidiary, Williams Alaska Petroleum Inc. (WAPI), and Flint Hills Resources Alaska, LLC (FHRA), a subsidiary of Koch Industries, Inc., as defendants. We owned and operated the refinery until 2004 when we sold it to FHRA. We and FHRA made claims under the pollution liability insurance policy issued in connection with the sale of the North Pole refinery to FHRA. We and FHRA also filed claims against each other seeking, among other things, contractual indemnification alleging that the other party caused the sulfolane contamination.

In 2011, we and FHRA settled the James West claim. We and FHRA subsequently filed motions for summary judgment on the other’s claims. On July 8, 2014, the court dismissed all FHRA’s claims and entered judgment for us. On August 6, 2014, FHRA appealed the court’s decision to the Alaska Supreme Court, which heard oral arguments in October of 2015, and issued a decision on August 26, 2016. The Alaska Supreme Court affirmed dismissal of FHRA’s equitable claims and statutory claims for damages related to sulfolane located on the refinery property. The Alaska Supreme Court remanded FHRA’s claims against us for contractual indemnification and statutory claims for damages related to off-site sulfolane for further resolution by the trial court. We currently estimate that our reasonably possible loss exposure in this matter could range from an insignificant amount up to $32 million, although uncertainties inherent in the litigation process, expert evaluations, and jury dynamics might cause our exposure to exceed that amount.

On March 6, 2014, the State of Alaska filed suit against FHRA, WAPI, and us in state court in Fairbanks seeking injunctive relief and damages in connection with sulfolane contamination of the water supply near the Flint Hills Oil

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Refinery in North Pole, Alaska. On May 5, 2014, FHRA filed cross-claims against us in the State of Alaska suit. FHRA also seeks injunctive relief and damages.

On November 26, 2014, the City of North Pole (North Pole) filed suit in Alaska state court in Fairbanks against FHRA, WAPI, and us alleging nuisance and violations of municipal and state statutes based upon the same alleged sulfolane contamination of the water supply. North Pole claims an unspecified amount of past and future damages as well as punitive damages against WAPI. FHRA filed cross-claims against us.

In October of 2015, the court consolidated the State of Alaska and North Pole cases. On February 29, 2016, we and WAPI filed Amended Answers in the consolidated cases. Both we and WAPI asserted counter claims against both the State of Alaska and North Pole, and cross claims against FHRA. A trial is scheduled to commence May 30, 2017. All or a portion of the exposure in this consolidated State of Alaska and North Pole action may duplicate exposure in the James West case. As such, on February 9, 2017, the remanded claims in the James West case were consolidated into the State of Alaska and North Pole action. Due to the ongoing assessment of the level and extent of sulfolane contamination, the lack of an articulated cleanup level for sulfolane, and the lack of a concrete remedial proposal and cost estimate, we are unable to estimate a range of exposure for the consolidated action at this time.

Independent of the litigation matter described in the preceding paragraphs, in 2013, the Alaska Department of Environmental Conservation indicated that it views FHRA and us as responsible parties, and that it intended to enter a compliance order to address the environmental remediation of sulfolane and other possible contaminants including cleanup work outside the refinery’s boundaries. Due to the ongoing assessment of the level and extent of sulfolane contamination and the ultimate cost of remediation and division of costs among the potentially responsible parties, we are unable to estimate a range of exposure at this time.

Royalty Matters

Certain of our customers, including one major customer, have been named in various lawsuits alleging underpayment of royalties and claiming, among other things, violations of anti-trust laws and the Racketeer Influenced and Corrupt Organizations Act. We have also been named as a defendant in certain of these cases in Texas, Pennsylvania, and Ohio based on allegations that we improperly participated with that major customer in causing the alleged royalty underpayments. We have also received subpoenas from the United States Department of Justice and the Pennsylvania Attorney General requesting documents relating to the agreements between us and our major customer and calculations of the major customer’s royalty payments. On December 9, 2015, the Pennsylvania Attorney General filed a civil suit against one of our major customers and us alleging breaches of the Pennsylvania Unfair Trade Practices and Consumer Protection Law, and on February 8, 2016, the Pennsylvania Attorney General filed an amended complaint in such civil suit, which omitted us as a party. We believe that the claims asserted are subject to indemnity obligations owed to us by that major customer. Our customer and plaintiffs in the Texas cases reached a settlement, and therefore all claims asserted (or possibly asserted) by any such plaintiffs against us in the Texas cases have been fully dismissed with prejudice. On February 7, 2017, the plaintiffs in the Ohio case voluntarily dismissed the case without prejudice. Due to the preliminary status of the remaining cases, we are unable to estimate a range of potential loss at this time.

Shareholder Litigation

Between October 2015 and December 2015, purported shareholders of us filed six putative class action lawsuits in the Delaware Court of Chancery that were consolidated into a single suit on January 13, 2016. This consolidated putative class action lawsuit relates to our terminated merger with Energy Transfer Equity, L.P. (Energy Transfer). The complaint asserts various claims against the individual members of our Board of Directors, including that they breached their fiduciary duties by agreeing to sell us through an allegedly unfair process and for an allegedly unfair price and by allegedly failing to disclose allegedly material information about the merger. The complaint seeks, among other things, an injunction against the merger and an award of costs and attorneys’ fees. On March 22, 2016, the court granted the parties’ proposed order in the consolidated action to stay the proceedings pending the close of the transaction with Energy Transfer. The plaintiffs have not filed an amended complaint.

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A purported shareholder filed a separate class action lawsuit in the Delaware Court of Chancery on January 15, 2016. The putative class action complaint alleged that the individual members of our Board of Directors breached their fiduciary duties by, among other things, agreeing to the WPZ Merger Agreement, which purportedly reduced the merger consideration to have been received in the subsequently proposed but now terminated merger with Energy Transfer. The plaintiff filed a motion to voluntarily dismiss, which the court granted on January 13, 2017. On September 2, 2016, the same purported shareholder filed a derivative action claiming that the members of our Board of Directors breached their fiduciary duties by executing the WPZ Merger Agreement as a defensive measure against Energy Transfer. On September 28, 2016, we requested the court dismiss this action also.

On March 7, 2016, a purported unitholder of WPZ filed a putative class action on behalf of certain purchasers of WPZ units in U.S. District Court in Oklahoma. The action names as defendants us, WPZ, Williams Partners GP LLC, Alan S. Armstrong, and Donald R. Chappel and alleges violations of certain federal securities laws for failure to disclose Energy Transfer’s intention to pursue a purchase of us conditioned on us not closing the WPZ Merger Agreement when announcing the WPZ Merger Agreement. The complaint seeks, among other things, damages and an award of costs and attorneys’ fees. The plaintiff filed an amended complaint on August 31, 2016. On October 17, 2016, we requested the court dismiss the action. We cannot reasonably estimate a range of potential loss at this time.

Litigation against Energy Transfer and related parties

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

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

The Court of Chancery coordinated the Special Offering and Tax Opinion suits. On May 20, 2016, the Energy Transfer defendants filed amended affirmative defenses and verified counterclaims in the Special Offering and Tax Opinion suits, alleging certain breaches of the Merger Agreement by us and seeking, among other things, a declaration that we were not entitled to specific performance, that Energy Transfer could terminate the ETC Merger, and that Energy Transfer is entitled to a $1.48 billion termination fee. On June 24, 2016, following a two-day trial, the court issued a Memorandum Opinion and Order denying our requested relief in the Tax Opinion suit. The court did not rule on the substance of our claims related to the Special Offering or on the substance of Energy Transfer’s counterclaims. On June 27, 2016, we filed an appeal of the court’s decision with the Supreme Court of Delaware, seeking reversal and remand to pursue damages. The appeal has been fully briefed for consideration by the Supreme Court of Delaware, and oral argument occurred on January 11, 2017.

On September 16, 2016, we filed an amended complaint with the Court of Chancery seeking damages for breaches of the Merger Agreement by defendants.  On September 23, 2016, Energy Transfer filed a second amended and supplemental affirmative defenses and verified counterclaim with the Court of Chancery seeking, among other things, payment of the $1.48 billion termination fee due to our alleged breaches of the Merger Agreement. We filed a motion to dismiss Energy Transfer’s counterclaims, which was fully briefed on November 14, 2016, and oral argument occurred on November 30, 2016.

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Notes to Consolidated Financial Statements – (Continued)

Environmental Matters

We are a participant in certain environmental activities in various stages including assessment studies, cleanup operations, and remedial processes at certain sites, some of which we currently do not own. We are monitoring these sites in a coordinated effort with other potentially responsible parties, the EPA, and other governmental authorities. We are jointly and severally liable along with unrelated third parties in some of these activities and solely responsible in others. Certain of our subsidiaries have been identified as potentially responsible parties at various Superfund and state waste disposal sites. In addition, these subsidiaries have incurred, or are alleged to have incurred, various other hazardous materials removal or remediation obligations under environmental laws. As of December 31, 2016, we have accrued liabilities totaling $38 million for these matters, as discussed below. Our accrual reflects the most likely costs of cleanup, which are generally based on completed assessment studies, preliminary results of studies, or our experience with other similar cleanup operations. Certain assessment studies are still in process for which the ultimate outcome may yield significantly different estimates of most likely costs. Any incremental amount in excess of amounts currently accrued cannot be reasonably estimated at this time due to uncertainty about the actual number of contaminated sites ultimately identified, the actual amount and extent of contamination discovered, and the final cleanup standards mandated by the EPA and other governmental authorities.

The EPA and various state regulatory agencies routinely promulgate and propose new rules, and issue updated guidance to existing rules. More recent rules and rulemakings include, but are not limited to, rules for reciprocating internal combustion engine maximum achievable control technology, new air quality standards for one hour nitrogen dioxide emissions, and volatile organic compound and methane new source performance standards impacting design and operation of storage vessels, pressure valves, and compressors. On October 1, 2015, the EPA issued its new rule regarding National Ambient Air Quality Standards for ground-level ozone, setting a new standard of 70 parts per billion. We are monitoring the rule’s implementation and evaluating potential impacts to our operations. For these and other new regulations, we are unable to estimate the costs of asset additions or modifications necessary to comply due to uncertainty created by the various legal challenges to these regulations and the need for further specific regulatory guidance.

Continuing operations

Our interstate gas pipelines are involved in remediation activities related to certain facilities and locations for polychlorinated biphenyls, mercury, and other hazardous substances. These activities have involved the EPA and various state environmental authorities, resulting in our identification as a potentially responsible party at various Superfund waste sites. At December 31, 2016, we have accrued liabilities of $9 million for these costs. We expect that these costs will be recoverable through rates.

We also accrue environmental remediation costs for natural gas underground storage facilities, primarily related to soil and groundwater contamination. At December 31, 2016, we have accrued liabilities totaling $7 million for these costs.

Former operations, including operations classified as discontinued

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

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

• Former petroleum products and natural gas pipelines;

• Former petroleum refining facilities;

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• Former exploration and production and mining operations;

• Former electricity and natural gas marketing and trading operations.

At December 31, 2016, we have accrued environmental liabilities of $22 million related to these matters.

Other Divestiture Indemnifications

Pursuant to various purchase and sale agreements relating to divested businesses and assets, we have indemnified certain purchasers against liabilities that they may incur with respect to the businesses and assets acquired from us. The indemnities provided to the purchasers are customary in sale transactions and are contingent upon the purchasers incurring liabilities that are not otherwise recoverable from third parties. The indemnities generally relate to breach of warranties, tax, historic litigation, personal injury, property damage, environmental matters, right of way, and other representations that we have provided.

At December 31, 2016, other than as previously disclosed, we are not aware of any material claims against us involving the indemnities; thus, we do not expect any of the indemnities provided pursuant to the sales agreements to have a material impact on our future financial position. Any claim for indemnity brought against us in the future may have a material adverse effect on our results of operations in the period in which the claim is made.

In addition to the foregoing, various other proceedings are pending against us which are incidental to our operations.

Summary

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

Commitments

Commitments for construction and acquisition of property, plant, and equipment are approximately $244 million at December 31, 2016.

Note 19 – Segment Disclosures

We have one reportable segment, Williams Partners. All remaining business activities are included in Other. (See Note 1 – General, Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies.)

Our segment presentation of Williams Partners, which includes our consolidated master limited partnership, is reflective of the parent-level focus by our chief operating decision-maker, considering the resource allocation and governance provisions associated with the master limited partnership structure. This partnership maintains capital and cash management structures that are separate from ours. It is self-funding and maintains its own lines of bank credit and cash management accounts. These factors, coupled with different costs of capital from our other businesses, serve to differentiate the management of this entity as a whole.

Performance Measurement

We evaluate segment operating performance based upon Modified EBITDA (earnings before interest, taxes, depreciation, and amortization). This measure represents the basis of our internal financial reporting and is the primary performance measure used by our chief operating decision maker in measuring performance and allocating resources among our reportable segments.

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We define Modified EBITDA as follows:

•Net income (loss) before:

◦Income (loss) from discontinued operations;

◦Provision (benefit) for income taxes;

◦Interest incurred, net of interest capitalized;

◦Equity earnings (losses);

◦Gain on remeasurement of equity-method investment;

◦Impairment of equity-method investments;

◦Other investing income (loss) – net;

◦Impairment of goodwill;

◦Depreciation and amortization expenses;

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

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

The following geographic area data includes Revenues from external customers based on product shipment origin and Long-lived assets based upon physical location:

		United States		Canada		Total
		(Millions)
Revenues from external customers:
	2016	$	7,425	$	74	$	7,499
	2015	7,247		113		7,360
	2014	7,229		408		7,637
Long-lived assets:
	2016	$	38,091	$	—	$	38,091
	2015	38,016		1,580		39,596
	2014	38,290		1,364		39,654

Long-lived assets are comprised of property, plant, and equipment, goodwill, and other intangible assets.

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

	Williams Partners		Other		Eliminations			Total
	(Millions)
2016
Segment revenues:
Service revenues
External	$	5,140	$	31	$	—		$	5,171
Internal	33		19		(52		)	—
Total service revenues	5,173		50		(52		)	5,171
Product sales
External	2,318		10		—			2,328
Internal	—		16		(16		)	—
Total product sales	2,318		26		(16		)	2,328
Total revenues	$	7,491	$	76	$	(68	)	$	7,499
Other financial information:
Additions to long-lived assets	$	2,102	$	44	$	(1	)	$	2,145
Proportional Modified EBITDA of equity-method investments	754		—		—			754
2015
Segment revenues:
Service revenues
External	$	5,134	$	30	$	—		$	5,164
Internal	1		91		(92		)	—
Total service revenues	5,135		121		(92		)	5,164
Product sales
External	2,196		—		—			2,196
Internal	—		—		—			—
Total product sales	2,196		—		—			2,196
Total revenues	$	7,331	$	121	$	(92	)	$	7,360
Other financial information:
Additions to long-lived assets	$	2,960	$	388	$	(12	)	$	3,336
Proportional Modified EBITDA of equity-method investments	699		—		—			699
2014
Segment revenues:
Service revenues
External	$	3,887	$	229	$	—		$	4,116
Internal	1		19		(20		)	—
Total service revenues	3,888		248		(20		)	4,116
Product sales
External	3,521		—		—			3,521
Internal	—		—		—			—
Total product sales	3,521		—		—			3,521
Total revenues	$	7,409	$	248	$	(20	)	$	7,637
Other financial information:
Additions to long-lived assets (1)	$	20,413	$	345	$	(2	)	$	20,756
Proportional Modified EBITDA of equity-method investments	431		7		—			438

_______________

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

	Years Ended December 31,
	2016			2015			2014
	(Millions)
Modified EBITDA by segment:
Williams Partners	$	3,864		$	4,003		$	3,244
Other	(542		)	(112		)	(12		)
	3,322			3,891			3,232
Accretion expense associated with asset retirement obligations for nonregulated operations	(31		)	(28		)	(18		)
Depreciation and amortization expenses	(1,763		)	(1,738		)	(1,176		)
Impairment of goodwill	—			(1,098		)	—
Equity earnings (losses)	397			335			144
Gain on remeasurement of equity-method investment	—			—			2,544
Impairment of equity-method investments	(430		)	(1,359		)	—
Other investing income (loss) – net	63			27			43
Proportional Modified EBITDA of equity-method investments	(754		)	(699		)	(438		)
Interest expense	(1,179		)	(1,044		)	(747		)
(Provision) benefit for income taxes	25			399			(1,249		)
Income (loss) from discontinued operations, net of tax	—			—			4
Net income (loss)	$	(350	)	$	(1,314	)	$	2,339

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

	Total Assets						Equity-Method Investments
	December 31, 2016			December 31, 2015			December 31, 2016		December 31, 2015
	(Millions)
Williams Partners	$	46,265		$	47,870		$	6,701	$	7,336
Other	685			1,351			—		—
Eliminations	(115		)	(201		)	—		—
Total	$	46,835		$	49,020		$	6,701	$	7,336

Note 20 – Subsequent Events

Debt Items

As of May 24, 2017, there was no commercial paper outstanding and $175 million outstanding under our long-term credit facility.

Issuances and retirements

On April 3, 2017, Northwest Pipeline issued $250 million of 4.0 percent senior unsecured notes due 2027 to investors in a private debt placement. Northwest Pipeline used the net proceeds to retire $185 million of 5.95 percent senior unsecured notes that matured on April 15, 2017.

On February 23, 2017, utilizing proceeds received from the Financial Repositioning (see Note 1 – General, Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies), WPZ early retired $750 million of 6.125 percent senior unsecured notes that were due in 2022.

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Notes to Consolidated Financial Statements – (Continued)

Acquisition of Additional Interests in Appalachia Midstream Investments

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

Geismar Olefins Sale Agreement

On April 17, 2017, WPZ announced that it agreed to sell Williams Olefins, L.L.C., a wholly owned subsidiary which owns an interest in the Geismar, Louisiana, olefins plant for $2.1 billion in cash, subject to customary closing conditions and regulatory approvals. Upon closing of the sale, WPZ will enter into a long-term supply and transportation agreement with the purchaser to provide feedstock to the plant via its Bayou Ethane pipeline system. WPZ expects that the sale will close during the summer of 2017.

Dividends

We paid a cash dividend of $0.30 per common share on March 27, 2017.

On May 18, 2017, our Board of Directors declared a cash dividend of $0.30 per common share, payable on June 26, 2017, to holders of record at the close of business on June 9, 2017.

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Quarterly Financial Data

(Unaudited)

Summarized quarterly financial data are as follows:

	First Quarter			Second Quarter			Third Quarter			Fourth Quarter
	(Millions, except per-share amounts)
2016
Revenues	$	1,660		$	1,736		$	1,905		$	2,198
Product costs	318			401			461			545
Net income (loss)	(13		)	(505		)	131			37
Amounts attributable to The Williams Companies, Inc.:
Net income (loss)	(65		)	(405		)	61			(15		)
Basic and diluted earnings (loss) per common share	(.09		)	(.54		)	.08			(.02		)
2015
Revenues	$	1,716		$	1,839		$	1,799		$	2,006
Product costs	462			494			426			397
Net income (loss)	13			183			(173		)	(1,337		)
Amounts attributable to The Williams Companies, Inc.:
Net income (loss)	70			114			(40		)	(715		)
Basic and diluted earnings (loss) per common share:	.09			.15			(.05		)	(.95		)

The sum of earnings (loss) per share for the four quarters may not equal the total earnings (loss) per share for the year due to changes in the average number of common shares outstanding and rounding.

2016

Net income (loss) for fourth-quarter 2016 includes the following pretax items:

• $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 Expensesof 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).

Net income (loss) for second-quarter 2016 includes a $747 million impairment loss on Canadian assets (see Note 17 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk).

Net income (loss) for first-quarter 2016 includes a $112 million impairment loss on certain equity-method investments (see Note 17 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk).

2015

Net income (loss) for fourth-quarter 2015 includes the following pretax items:

• $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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(Unaudited)

• $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).

Net income (loss) for third-quarter 2015 includes a $461 million impairment loss on certain equity-method investments (see Note 17 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk).

Net income (loss) for second-quarter 2015 includes a $126 million gain associated with insurance recoveries related to the Geismar Incident.

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Schedule I — Condensed Financial Information of Registrant

Statement of Comprehensive Income (Loss) (Parent)

	Years Ended December 31,
	2016			2015			2014
	(Millions, except per-share amounts)
Equity in earnings of consolidated subsidiaries	$	522		$	232		$	1,799
Equity earnings (losses) from investment in Access Midstream Partners	—			—			(7		)
Interest incurred — external	(268		)	(255		)	(206		)
Interest incurred — affiliate	(568		)	(828		)	(797		)
Interest income — affiliate	—			6			10
Gain on remeasurement of equity-method investment	—			—			2,544
Other income (expense) — net	(53		)	(75		)	(13		)
Income (loss) from continuing operations before income taxes	(367		)	(920		)	3,330
Provision (benefit) for income taxes	57			(349		)	1,220
Income (loss) from continuing operations	(424		)	(571		)	2,110
Income (loss) from discontinued operations	—			—			4
Net income (loss)	$	(424	)	$	(571	)	$	2,114
Basic earnings (loss) per common share:
Income (loss) from continuing operations	$	(.57	)	$	(.76	)	$	2.93
Income (loss) from discontinued operations	—			—			.01
Net income (loss)	$	(.57	)	$	(.76	)	$	2.94
Weighted-average shares (thousands)	750,673			749,271			719,325
Diluted earnings (loss) per common share:
Income (loss) from continuing operations	$	(.57	)	$	(.76	)	$	2.91
Income (loss) from discontinued operations	—			—			.01
Net income (loss)	$	(.57	)	$	(.76	)	$	2.92
Weighted-average shares (thousands)	750,673			749,271			723,641
Other comprehensive income (loss):
Equity in other comprehensive income (loss) of consolidated subsidiaries	$	171		$	(204	)	$	(96	)
Other comprehensive income (loss) attributable to The Williams Companies, Inc.	1			33			(80		)
Other comprehensive income (loss)	172			(171		)	(176		)
Less: Other comprehensive income (loss) attributable to noncontrolling interests	69			(70		)	(19		)
Comprehensive income (loss) attributable to The Williams Companies, Inc.	$	(321	)	$	(672	)	$	1,957

See accompanying notes.

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Schedule I — Condensed Financial Information of Registrant – (Continued)

Balance Sheet (Parent)

	December 31,
	2016		2015
	(Millions)
ASSETS
Current assets:
Cash and cash equivalents	$	14	$	12
Other current assets and deferred charges	16		62
Total current assets	30		74
Investments in and advances to consolidated subsidiaries	22,359		30,927
Property, plant, and equipment — net	77		99
Other noncurrent assets	8		12
Total assets	$	22,474	$	31,112
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	27	$	27
Other current liabilities	169		163
Total current liabilities	196		190
Long-term debt	4,939		4,811
Notes payable — affiliates	8,171		15,506
Pension, other postretirement, and other noncurrent liabilities	287		336
Deferred income tax liabilities	4,238		4,121
Contingent liabilities and commitments
Equity:
Common stock	785		784
Other stockholders’ equity	3,858		5,364
Total stockholders’ equity	4,643		6,148
Total liabilities and stockholders’ equity	$	22,474	$	31,112

See accompanying notes.

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Schedule I — Condensed Financial Information of Registrant – (Continued)

Statement of Cash Flows (Parent)

	Years Ended December 31,
	2016			2015			2014
	(Millions)
NET CASH FLOWS PROVIDED (USED) BY OPERATING ACTIVITIES	$	(827	)	$	(1,181	)	$	(481	)
FINANCING ACTIVITIES:
Proceeds from long-term debt	2,280			2,097			2,935
Payments of long-term debt	(2,155		)	(1,817		)	(671		)
Changes in notes payable to affiliates	9			2,211			2,465
Tax benefit of stock-based awards	—			—			25
Proceeds from issuance of common stock	9			27			3,416
Dividends paid	(1,261		)	(1,836		)	(1,412		)
Other — net	(6		)	(30		)	(36		)
Net cash provided (used) by financing activities	(1,124		)	652			6,722
INVESTING ACTIVITIES:
Capital expenditures	(13		)	(29		)	(54		)
Purchase of Access Midstream Partners	—			—			(5,995		)
Changes in investments in and advances to consolidated subsidiaries	1,966			521			(450		)
Other — net	—			—			25
Net cash provided (used) by investing activities	1,953			492			(6,474		)
Increase (decrease) in cash and cash equivalents	2			(37		)	(233		)
Cash and cash equivalents at beginning of year	12			49			282
Cash and cash equivalents at end of year	$	14		$	12		$	49

See accompanying notes.

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Schedule I — Condensed Financial Information of Registrant – (Continued)

Notes to Financial Information (Parent)

Note 1. Guarantees

In addition to the guarantees disclosed in the accompanying consolidated financial statements in Item 8, we have financially guaranteed the performance of certain consolidated subsidiaries. The duration of these guarantees varies, and we estimate the maximum undiscounted potential future payment obligation related to these guarantees as of December 31, 2016, is approximately $305 million.

Note 2. Cash Dividends Received

We receive dividends and distributions either directly from our subsidiaries or indirectly through dividends received by subsidiaries and subsequent transfers of cash to us through our corporate cash management system. The total of such receipts ultimately related to dividends and distributions for the years ended December 31, 2016, 2015, and 2014 was approximately $1.7 billion, $1.8 billion, and $1.9 billion, respectively.

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The Williams Companies, Inc.

Schedule II — Valuation and Qualifying Accounts

			Additions
	Beginning Balance		Charged (Credited) To Costs and Expenses			Other		Deductions		Ending Balance
	(Millions)
2016
Allowance for doubtful accounts — accounts and notes receivable (1)	$	3	$	6		$	—	$	3	$	6
Deferred tax asset valuation allowance (1)	190		144			—		—		334
2015
Allowance for doubtful accounts — accounts and notes receivable (1)	—		3			—		—		3
Deferred tax asset valuation allowance (1)	206		(16		)	—		—		190
2014
Allowance for doubtful accounts — accounts and notes receivable (1)	—		—			—		—		—
Deferred tax asset valuation allowance (1)	181		25			—		—		206

__________

(1)    Deducted from related assets.

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