The Williams Companies, Inc. (WMB) 10-K 22 Feb 18 2017 FY Annual report Financial data

Document and Entity Information

Document and Entity Information - USD ($)	12 Months Ended
	Dec. 31, 2017	Feb. 19, 2018	Jun. 30, 2017
Document and Entity Information [Abstract]
Entity Registrant Name	Williams Companies Inc
Entity Central Index Key	107,263
Document Type	10-K
Document Period End Date	Dec. 31, 2017
Amendment Flag	false
Document Fiscal Year Focus	2,017
Document Fiscal Period Focus	FY
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Entity Common Stock, Shares Outstanding		827,327,336
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Public Float			$ 24,993,673,967

Consolidated Statement of Opera

Consolidated Statement of Operations - USD ($) shares in Thousands, $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016		Dec. 31, 2015
Revenues:
Service revenues	$ 5,312	$ 5,171		$ 5,164
Product sales	2,719	2,328		2,196
Total revenues	8,031	7,499		7,360
Costs and expenses:
Product costs	2,300	1,725		1,779
Operating and maintenance expenses	1,585	1,580		1,655
Depreciation and amortization expenses	1,736	1,763		1,738
Selling, general, and administrative expenses	608	723		741
Impairment of goodwill (Note 16)	0	0		1,098
Impairment of certain assets (Note 16)	1,248	873		209
Gain on sale of Geismar Interest (Note 2)	(1,095)	0		0
Regulatory Charges In Operating Expense Resulting From Tax Reform	674	0		0
Insurance recoveries – Geismar Incident	(9)	(7)		(126)
Other (income) expense – net	80	142		40
Total costs and expenses	7,127	6,799		7,134
Operating income (loss)	904	700		226
Equity earnings (losses)	434	397		335
Impairment of equity-method investments (Note 16)	0	(430)		(1,359)
Other investing income (loss) – net	282	63		27
Interest incurred	(1,116)	(1,217)		(1,118)
Interest capitalized	33	38		74
Other income (expense) – net	(2)	74		102
Income (loss) before income taxes	535	(375)		(1,713)
Provision (benefit) for income taxes	(1,974)	(25)		(399)
Net income (loss)	2,509	(350)		(1,314)
Less: Net income (loss) attributable to noncontrolling interests	335	74		(743)
Amounts attributable to The Williams Companies, Inc.:
Net income (loss) attributable to The Williams Companies, Inc.	$ 2,174	$ (424)		$ (571)
Basic earnings (loss) per common share:
Net income (loss)	$ 2.63	$ (0.57)		$ (0.76)
Weighted-average shares (thousands)	826,177	750,673		749,271
Diluted earnings (loss) per common share:
Net income (loss)	$ 2.62	$ (0.57)		$ (0.76)
Weighted-average shares (thousands)	828,518	750,673	[1]	749,271	[1]
[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.

Consolidated Statement of Compr

Consolidated Statement of Comprehensive Income (Loss) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Comprehensive income (loss):
Net income (loss)	$ 2,509	$ (350)	$ (1,314)
Cash flow hedging activities:
Net unrealized gain (loss) from derivative instruments, net of taxes of $2, ($1), and $0 in 2017, 2016, and 2015, respectively	(9)	4	6
Reclassifications into earnings of net derivative instruments (gain) loss, net of taxes of ($1) in 2017, and $1 in 2016 and 2015	6	(2)	(6)
Foreign currency translation activities:
Foreign currency translation adjustments, net of taxes of $0, ($37), and $31 in 2017, 2016, and 2015, respectively	1	50	(204)
Reclassification into earnings upon sale of foreign entities, net of taxes of ($36) in 2016	0	119	0
Pension and other postretirement benefits:
Amortization of prior service cost (credit) included in net periodic benefit cost (credit), net of taxes of $2, $2, and $3 in 2017, 2016, and 2015, respectively	(3)	(4)	(3)
Net actuarial gain (loss) arising during the year, net of taxes of ($15), $8, and ($5) in 2017, 2016 and 2015, respectively (Note 9)	44	(15)	8
Amortization of actuarial (gain) loss and net actuarial loss from settlements included in net periodic benefit cost (credit), net of taxes of ($37), ($12), and ($18) in 2017, 2016, and 2015, respectively	61	20	28
Other comprehensive income (loss)	100	172	(171)
Comprehensive income (loss)	2,609	(178)	(1,485)
Less: Comprehensive income (loss) attributable to noncontrolling interests	334	143	(813)
Comprehensive Income (loss) attributable to The Williams Companies, Inc.	$ 2,275	$ (321)	$ (672)

Consolidated Statement of Comp4

Consolidated Statement of Comprehensive Income (Loss) (Parenthetical) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Cash flow hedging activities:
Other Comprehensive Income, Net Unrealized Gain (Loss) from Derivatives, Tax	$ 2	$ (1)	$ 0
Other Comprehensive Income Loss, Reclassification into Earnings of Net Derivative Instruments (Gain) Loss, Tax	(1)	1	1
Foreign currency translation activities:
Other Comprehensive Income (Loss), Foreign Currency Translation Adjustment, Tax	0	(37)	31
Other Comprehensive Income (Loss), Foreign Currency Translation Reclassification into Earnings upon Sale, Tax	0	(36)	0
Pension and other postretirement benefits:
Other Comprehensive Income, Amortization Of Defined Benefit Plan Net Prior Service Cost (Credit) In Net Periodic Benefit Cost (Credit), Tax	2	2	3
Other Comprehensive Income (Loss), Defined Benefit Plan, Net Actuarial Gain (Loss) Arising During Period, Tax	(15)	8	(5)
Other Comprehensive Income Loss, Reclassification Pension And Other Postretirement Benefit Plans Net Gain Loss Included In Net Periodic Benefit Cost (Credit), Tax	$ (37)	$ (12)	$ (18)

Consolidated Balance Sheet

Consolidated Balance Sheet - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016
Current assets:
Cash and cash equivalents	$ 899	$ 170
Trade accounts and other receivables (net of allowance of $9 at December 31, 2017 and $6 at December 31, 2016)	976	938
Inventories	113	138
Other current assets and deferred charges	191	216
Total current assets	2,179	1,462
Investments	6,552	6,701
Property, plant, and equipment – net	28,211	28,428
Intangible assets – net of accumulated amortization	8,791	9,663
Regulatory assets, deferred charges, and other	619	581
Total assets	46,352	46,835
Current liabilities:
Accounts payable	978	623
Accrued liabilities	1,167	1,448
Commercial paper	0	93
Long-term debt due within one year	501	785
Total current liabilities	2,646	2,949
Long-term debt	20,434	22,624
Deferred income tax liabilities	3,147	4,238
Regulatory liabilities, deferred income, and other	3,950	2,978
Contingent liabilities and commitments (Note 17)
Stockholders’ equity:
Common stock (960 million shares authorized at $1 par value; 861 million shares issued at December 31, 2017 and 785 million shares issued at December 31, 2016)	861	785
Capital in excess of par value	18,508	14,887
Retained deficit	(8,434)	(9,649)
Accumulated other comprehensive income (loss)	(238)	(339)
Treasury stock, at cost (35 million shares of common stock)	(1,041)	(1,041)
Total stockholders’ equity	9,656	4,643
Noncontrolling interests in consolidated subsidiaries	6,519	9,403
Total equity	16,175	14,046
Total liabilities and equity	$ 46,352	$ 46,835

Consolidated Balance Sheet (Par

Consolidated Balance Sheet (Parenthetical) - USD ($) shares in Millions, $ in Millions	Dec. 31, 2017	Dec. 31, 2016
Stockholders’ equity:
Common stock, shares authorized	960	960
Common stock, par value per share	$ 1	$ 1
Common Stock, shares issued	861	785
Treasury stock, shares of common stock	35	35
Allowance for trade accounts and other receivables	$ 9	$ 6

Consolidated Statement of Chang

Consolidated Statement of Changes in Equity - USD ($) $ in Millions	Total	Common Stock	Capital in Excess of Par Value	Retained Deficit	Accumulated Other Comprehensive Income (Loss)	Treasury Stock	Total Stockholders' Equity	Noncontrolling Interests
Beginning balance at Dec. 31, 2014	$ 20,172	$ 782	$ 14,925	$ (5,548)	$ (341)	$ (1,041)	$ 8,777	$ 11,395
Net income (loss)	(1,314)	0	0	(571)	0	0	(571)	(743)
Other comprehensive income (loss)	(171)	0	0	0	(101)	0	(101)	(70)
Cash dividends – common stock (Note 14)	(1,836)	0	0	(1,836)	0	0	(1,836)	0
Dividends and distributions to noncontrolling interests	(942)	0	0	0	0	0	0	(942)
Stock-based compensation and related common stock issuances, net of tax	30	2	28	0	0	0	30	0
Sales of limited partner units of Williams Partners L.P.	59	0	0	0	0	0	0	59
Changes in ownership of consolidated subsidiaries, net	94	0	(160)	0	0	0	(160)	254
Contributions from noncontrolling interests	111	0	0	0	0	0	0	111
Other	22	0	14	(5)	0	0	9	13
Net increase (decrease) in equity	(3,947)	2	(118)	(2,412)	(101)	0	(2,629)	(1,318)
Ending balance at Dec. 31, 2015	16,225	784	14,807	(7,960)	(442)	(1,041)	6,148	10,077
Net income (loss)	(350)	0	0	(424)	0	0	(424)	74
Other comprehensive income (loss)	172	0	0	0	103	0	103	69
Cash dividends – common stock (Note 14)	(1,261)	0	0	(1,261)	0	0	(1,261)	0
Dividends and distributions to noncontrolling interests	(940)	0	0	0	0	0	0	(940)
Stock-based compensation and related common stock issuances, net of tax	57	1	56	0	0	0	57	0
Sales of limited partner units of Williams Partners L.P.	114	0	0	0	0	0	0	114
Changes in ownership of consolidated subsidiaries, net	(6)	0	12	0	0	0	12	(18)
Contributions from noncontrolling interests	29	0	0	0	0	0	0	29
Other	6	0	12	(4)	0	0	8	(2)
Net increase (decrease) in equity	(2,179)	1	80	(1,689)	103	0	(1,505)	(674)
Ending balance at Dec. 31, 2016	14,046	785	14,887	(9,649)	(339)	(1,041)	4,643	9,403
Net income (loss)	2,509	0	0	2,174	0	0	2,174	335
Other comprehensive income (loss)	100	0	0	0	101	0	101	(1)
Issuance of common stock (Note 14)	2,118	75	2,043	0	0	0	2,118	0
Cash dividends – common stock (Note 14)	(992)	0	0	(992)	0	0	(992)	0
Dividends and distributions to noncontrolling interests	(883)	0	0	0	0	0	0	(883)
Stock-based compensation and related common stock issuances, net of tax	74	1	73	0	0	0	74	0
Adoption of ASU 2016-09 (Note 1)	37	0	1	36	0	0	37	0
Sales of limited partner units of Williams Partners L.P.	61	0	0	0	0	0	0	61
Changes in ownership of consolidated subsidiaries, net	(910)	0	1,497	0	0	0	1,497	(2,407)
Contributions from noncontrolling interests	17	0	0	0	0	0	0	17
Other	(2)	0	7	(3)	0	0	4	(6)
Net increase (decrease) in equity	2,129	76	3,621	1,215	101	0	5,013	(2,884)
Ending balance at Dec. 31, 2017	$ 16,175	$ 861	$ 18,508	$ (8,434)	$ (238)	$ (1,041)	$ 9,656	$ 6,519

Consolidated Statement of Cash

Consolidated Statement of Cash Flows - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
OPERATING ACTIVITIES:
Net income (loss)	$ 2,509	$ (350)	$ (1,314)
Adjustments to reconcile to net cash provided (used) by operating activities:
Depreciation and amortization	1,736	1,763	1,738
Provision (benefit) for deferred income taxes	(2,012)	(26)	(337)
Net (gain) loss on disposition of equity-method investments	(269)	(27)	0
Impairment of goodwill	0	0	1,098
Impairment of equity-method investments	0	430	1,359
Impairment of and net (gain) loss on sale of assets and businesses	1,249	918	215
Gain on sale of Geismar Interest (Note 2)	(1,095)	0	0
Amortization of stock-based awards	78	73	82
Regulatory charges resulting from Tax Reform (Note 1)	776	0	0
Cash provided (used) by changes in current assets and liabilities:
Accounts and notes receivable	(88)	82	39
Inventories	8	(25)	105
Other current assets and deferred charges	(21)	(4)	4
Accounts payable	118	35	(88)
Accrued liabilities	(92)	512	54
Other, including changes in noncurrent assets and liabilities	(341)	299	(247)
Net cash provided (used) by operating activities	2,556	3,680	2,708
FINANCING ACTIVITIES:
Proceeds from (payments of) commercial paper – net	(93)	(409)	(306)
Proceeds from long-term debt	3,333	6,528	9,772
Payments of long-term debt	(5,925)	(7,091)	(6,516)
Proceeds from issuance of common stock	2,131	9	27
Proceeds from sale of limited partner units of consolidated partnership	0	114	59
Dividends paid	(992)	(1,261)	(1,836)
Dividends and distributions paid to noncontrolling interests	(822)	(940)	(942)
Contributions from noncontrolling interests	17	29	111
Payments for debt issuance costs	(17)	(9)	(35)
Special distribution from Gulfstream	0	0	396
Contribution to Gulfstream for repayment of debt	0	(148)	(248)
Other – net	(92)	(16)	(31)
Net cash provided (used) by financing activities	(2,460)	(3,194)	451
INVESTING ACTIVITIES:
Capital expenditures (1)	(2,399)	(2,051)	(3,167)
Dispositions – net	(41)	30	3
Contributions in aid of construction	426	218	87
Proceeds from sale of businesses, net of cash divested	2,067	1,020	0
Proceeds from dispositions of equity-method investments	200	34	0
Purchases of businesses, net of cash acquired	0	0	(112)
Purchases of and contributions to equity-method investments	(132)	(177)	(595)
Distributions from unconsolidated affiliates in excess of cumulative earnings	529	472	404
Other – net	(17)	38	81
Net cash provided (used) by investing activities	633	(416)	(3,299)
Increase (decrease) in cash and cash equivalents	729	70	(140)
Cash and cash equivalents at beginning of year	170	100	240
Cash and cash equivalents at end of year	899	170	100
(1) Increases to property, plant, and equipment	(2,662)	(1,912)	(3,024)
Changes in related accounts payable and accrued liabilities	263	(139)	(143)
Capital expenditures (1)	$ (2,399)	$ (2,051)	$ (3,167)

General, Description of Busines

General, Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies	12 Months Ended
	Dec. 31, 2017
Organization, Consolidation and Presentation of Financial Statements [Abstract]
General, Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies [Text Block]	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 entered into 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 noneconomic interest in exchange for 289 million newly issued WPZ common units. Pursuant to this agreement, we also purchased approximately 277 thousand WPZ common units for $10 million . Additionally, we purchased approximately 59 million common units of WPZ at a price of $36.08586 per unit in a private placement transaction, funded with proceeds from our equity offering (see Note 14 – Stockholders' Equity ). According to the terms of this agreement, concurrent with WPZ’s quarterly distributions in February 2017 and May 2017, we paid additional consideration totaling $56 million to WPZ for these units. Subsequent to these transactions and as of December 31, 2017, 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. 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 developing a pipeline project (see Note 3 – Variable Interest Entities ) . 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 (see Note 2 – Acquisitions and Divestitures ). 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 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 66 percent interest in multiple gathering systems in the Marcellus Shale ( Appalachia Midstream Investments ), as well as our previously owned 50 percent equity-method investment in the Delaware basin gas gathering system (DBJV) in the Mid-Continent region (see Note 5 – Investing Activities ). The midstream businesses also 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, we completed the sale of our Canadian operations. (See Note 2 – Acquisitions and Divestitures .) Other Other is comprised of business activities that are not operating segments, as well as corporate operations. Other also includes 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 2 – Acquisitions and Divestitures .) Basis of Presentation Consolidated master limited partnership As of December 31, 2017 , we owned approximately 74 percent of the interests in WPZ, a variable interest entity (VIE) (see Note 3 – Variable Interest Entities ). Pursuant to WPZ’s distribution reinvestment program, 1,606,448 common units were issued to the public during 2017 associated with reinvested distributions of $61 million . These common unit issuances, the Financial Repositioning, 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 $2.407 billion , and increasing Capital in excess of par value by $1.497 billion and Deferred income tax liabilities by $910 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 13 – 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 may monetize assets that are not core to our strategy which could result in 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. Our 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; • 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 us 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; • Measurement of regulatory liabilities; • Measurement of deferred income tax assets and liabilities. These estimates are discussed further throughout these notes. Regulatory accounting Transco and Northwest Pipeline are regulated by the Federal Energy Regulatory Commission (FERC). Their rates, which are established by the FERC, are designed to recover the costs of providing the regulated services, and their competitive environment makes it probable that such rates can be charged and collected. Therefore, we have determined that it is appropriate under Accounting Standards Codification (ASC) Topic 980, “Regulated Operations,” to account for and report regulatory assets and liabilities related to these operations consistent with the economic effect of the way in which their rates are established. Accounting for these operations that are regulated can differ from the accounting requirements for nonregulated operations. For example, for regulated operations, allowance for funds used during construction (AFUDC) represents the estimated cost of debt and equity funds applicable to utility plant in the process of construction and is capitalized as a cost of property, plant, and equipment because it constitutes an actual cost of construction under established regulatory practices; nonregulated operations are only allowed to capitalize the cost of debt funds related to construction activities, while a component for equity is prohibited. The components of our regulatory assets and liabilities relate to the effects of deferred taxes on equity funds used during construction, asset retirement obligations, fuel cost differentials, levelized incremental depreciation, negative salvage, pension and other postretirement benefits, and rate allowances for deferred income taxes at a historically higher federal income tax rate. In December 2017, the Tax Cuts and Jobs Act was enacted, which, among other things, reduced the federal corporate income tax rate from 35 percent to 21 percent (Tax Reform) (see Note 7 – Provision (Benefit) for Income Taxes ). In accordance with ASC 980-740-25-2, Transco and Northwest Pipeline have recognized regulatory liabilities to reflect the probable return to customers through future rates of the future decrease in income taxes payable associated with Tax Reform. These liabilities represent an obligation to return amounts directly to our customers. While a majority of our customers have entered into tariff rates based on our cost-of-service proceedings and related rate base therein, certain other contracts with customers reflect contractually-based rates that are designed to recover the cost of providing those services, including an allowance for income taxes, with no expected future rate adjustment for the term of those contracts. This relative mix of contracts for services was considered in determining the probable amount to be returned to customers through future rates. The regulatory liabilities were recorded in December 2017 through regulatory charges to operating income totaling $674 million . The timing and actual amount of such return will be subject to future negotiations regarding this matter and many other elements of cost-of-service rate proceedings, including other costs of providing service. Certain of our equity-method investees recorded similar regulatory liabilities, for which our Equity earnings (losses) in the Consolidated Statement of Operations have been reduced by $11 million related to our proportionate share of the associated regulatory charges. Our regulatory assets associated with the effects of deferred taxes on equity funds used during construction were also impacted by Tax Reform and were reduced by $102 million in December 2017 through a charge to Other income (expense) – net below Operating income (loss) in the Consolidated Statement of Operations (see Note 6 – Other Income and Expenses ). This amount, along with the previously described charges for establishing the regulatory liabilities resulting from Tax Reform, is reported within Regulatory charges resulting from Tax Reform within the Consolidated Statement of Cash Flows . Our current and noncurrent regulatory asset and liability balances for the years ended December 31, 2017 and 2016 are as follows: December 31, 2017 2016 (Millions) Current assets reported within Other current assets and deferred charges $ 102 $ 91 Noncurrent assets reported within Regulatory assets, deferred charges, and other 376 387 Total regulated assets $ 478 $ 478 Current liabilities reported within Accrued liabilities $ 18 $ 11 Noncurrent liabilities reported within Regulatory liabilities, deferred income, and other 1,250 498 Total regulated liabilities $ 1,268 $ 509 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 net realizable value. The cost of inventories is primarily determined using the average-cost method. Property, plant, and equipment Property, plant, and equipment is initially recorded at cost. We base the carrying value of these assets on estimates, assumptions, and judgments relative to capitalized costs, useful lives, and salvage values. As regulated entities, Northwest Pipeline and Transco provide for depreciation using the straight-line method at FERC-prescribed rates. Depreciation for nonregulated entities is provided primarily on the straight-line method over estimated useful lives, except for certain offshore facilities that apply an accelerated depreciation method. Gains or losses from the ordinary sale or retirement of property, plant, and equipment for regulated pipelines are credited or charged to accumulated depreciation. Other gains or losses are recorded in Other (income) expense – net included in Operating income (loss) in the Consolidated Statement of Operations . Ordinary maintenance and repair costs are generally expensed as incurred. Costs of major renewals and replacements are capitalized as property, plant, and equipment. We record a liability and increase the basis in the underlying asset for the present value of each expected future 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 we expect to recover these amounts in future rates. We measure changes in the liability due to passage of time by applying an interest rate to the liability balance. This amount is recognized as an increase in the carrying amount of the liability and as a corresponding accretion expense included in Operating and maintenance expenses in the Consolidated Statement of Operations , except for regulated entities, for which the liability is offset by a regulatory asset. The regulatory asset is amortized commensurate with our collection of those costs in rates. Measurements of AROs include, as a component of future expected costs, an estimate of the price that a third party would demand, and could expect to receive, for bearing the uncertainties inherent in the obligations, sometimes referred to as a market-risk premium. Goodwill Goodwill included within Intangible assets – net of accumulated amortization in the Consolidated Balance Sheet represents the excess of the consideration, plus the fair value of any noncontrolling interest or any previously held equity interest, over the fair value of the net assets acquired. It is not subject to amortization but is evaluated annually as of October 1 for impairment or more frequently if impairment indicators are present that would indicate it is more likely than not that the fair value of the reporting unit is less than its carrying amount. Generally, the evaluation of goodwill for impairment involves a two-step quantitative test, although under certain circumstances an initial qualitative evaluation may be sufficient to conclude goodwill is not impaired. If a quantitative assessment is performed, 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 estimate of fair value. Effective October 1, 2017, we early adopted Accounting Standards Update (ASU) 2017-04 “Intangibles - Goodwill and Other (Topic 350): Simplifying the Test for Goodwill Impairment” (ASU 2017-04), which removed the computation of the implied fair value of goodwill from the measurement process. Other intangible assets Our identifiable intangible assets included within Intangible assets – net of accumulated amortization in the Consolidated Balance Sheet are primarily related to gas gathering, processing, and fractionation contractual customer relationships. Our intangible assets are amortized on a straight-line basis over the period in which these assets contribute to our cash flows. We evaluate these assets for changes in the expected remaining useful lives and would reflect any changes prospectively through amortization over the revised remaining useful life. Impairment of property, plant, and equipment, other identifiable intangible assets, and investments We evaluate our property, plant, and equipment and other identifiable intangible assets for impairment when events or changes in circumstances indicate, in our judgment, that the carrying value of such assets may not be recoverable. When an indicator of impairment has occurred, we compare our estimate of undiscounted future cash flows attributable to the assets to the carrying value of the assets to determine whether an impairment has occurred and we may apply a probability-weighted approach to consider the likelihood of different cash flow assumptions and possible outcomes including selling in the near term or holding for the remaining estimated useful life. If an impairment of the carrying value has occurred, we determine the amount of the impairment recognized in the financial statements by estimating the fair value of the assets and recording a loss for the amount that the carrying value exceeds the estimated fair value. This evaluation is performed at the lowest level for which separately identifiable cash flows exist. For assets identified to be disposed of in the future and considered held for sale, we compare the carrying value to the estimated fair value less the cost to sell to determine if recognition of an impairment is required. Until the assets are disposed of, the estimated fair value, which includes estimated cash flows from operations until the assumed date of sale, is recalculated when related events or circumstances change. We evaluate our investments for impairment when events or changes in circumstances indicate, in our judgment, that the carrying value of such investments may have experienced an other-than-temporary decline in value. When evidence of loss in value has occurred, we compare our estimate of fair value of the investment to the carrying value of the investment to determine whether an impairment has occurred. If the estimated fair value is less than the carrying value and we consider the decline in value to be other-than-temporary, the excess of the carrying value over the fair value is recognized in the consolidated financial statements as an impairment charge. Judgments and assumptions are inherent in our estimate of undiscounted future cash flows and an asset’s or investment’s fair value. Additionally, judgment is used to determine the probability of sale with respect to assets considered for disposal. 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 income is reflected within Accrued liabilities and Regulatory liabilities, deferred income, and other on the Consolidated Balance Sheet . (See Note 12 – Accrued Liabilities .) WPZ received an aggregate amount of $240 million in three equal installments as certain milestones of Transco’s Hillabee Expansion Project were met related to an agreement to resolve several matters in relation to the project. (See Note 12 – Accrued Liabilities .) During the third quarter of 2017, WPZ received the final installment and placed the project into service. As a result of placing the project into service, WPZ reclassified the refundable deposits to deferred income and expects to recognize income associated with these receipts over the term of an underlying contract. 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 income and are being amortized into income. 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 13 – 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. 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 16 – 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 costs in 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 us. For commodity derivatives that are not designated in a hedging relationship, and for which we have not elected the normal purchases and normal sales exception, we report changes in fair value currently in Product sales or Product costs in the Consolidated Statement of Operations . Certain gains and losses on derivative instruments included in the Consolidated Statement of Operations are netted together to a single net gain or loss, while other gains and losses are reported on a gross basis. Gains and losses recorded on a net basis include unrealized gains and losses on all derivatives that are not designated as hedges and for which we have not elected the normal purchases and normal sales exception. Realized gains and losses on derivatives that require physical delivery, as well as natural gas derivatives for NGL processing activities and which are not held for trading purposes nor were entered into as a pre-contemplated buy/sell arrangement, are recorded on a gross basis. Revenue recognition Revenues As a result of the ratemaking process, certain revenues collected by us may be subject to refunds upon the

Acquisitions and Divestitures

Acquisitions and Divestitures	12 Months Ended
	Dec. 31, 2017
Business Combinations [Abstract]
Acquisitions and Divestitures [Text Block]	Note 2 – Acquisitions and Divestitures 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 . Sale of Geismar Interest In July 2017, WPZ completed the sale of Williams Olefins, L.L.C., a wholly owned subsidiary which owned our 88.5 percent undivided interest in the Geismar, Louisiana, olefins plant (Geismar Interest) for total consideration of $2.084 billion in cash. We received a final working capital adjustment of $12 million in October 2017. Upon closing of the sale, WPZ entered into a long-term supply and transportation agreement with the purchaser to provide feedstock to the plant via its Bayou Ethane pipeline system. The assets and liabilities of the Geismar olefins plant were designated as held for sale within the Williams Partners segment during the first quarter of 2017. As a result of this sale, we recorded a gain of $1.095 billion in the third quarter of 2017. Following this sale, the cash proceeds were used to repay WPZ’s $850 million term loan. Proceeds have also been funding a portion of the capital and investment expenditures that are a part of WPZ’s growth portfolio. The following table presents the results of operations for the Geismar Interest, excluding the gain noted above: Years Ended December 31, 2017 2016 (Millions) Income (loss) before income taxes of the Geismar Interest $ 26 $ 141 Income (loss) before income taxes of the Geismar Interest attributable to The Williams Companies, Inc. 19 85 Sale of Canadian Operations In September 2016, we completed the sale of subsidiaries conducting Canadian operations, including subsidiaries of WPZ, (such subsidiaries, the Canadian disposal group). Consideration received 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 16 – 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. The following table presents the results of operations for the Canadian disposal group, excluding the impairment and loss noted above: Years Ended December 31, 2017 2016 (Millions) Income (loss) before income taxes of Canadian disposal group $ — $ (98 ) Income (loss) before income taxes of Canadian disposal group attributable to The Williams Companies, Inc. — (95 )

Variable Interest Entities

Variable Interest Entities	12 Months Ended
	Dec. 31, 2017
Variable Interest Entity Disclosures [Abstract]
Variable Interest Entities [Text Block]	Note 3 – Variable Interest Entities WPZ We own a 74 percent interest in WPZ, a master limited partnership that is a VIE due to the limited partners’ lack of substantive voting rights, such as either participating rights or kick-out rights that can be exercised with a simple majority of the vote of the limited partners. We are the primary beneficiary of WPZ because we have the power, through our general partner interest, to direct the activities that most significantly impact WPZ’s economic performance. 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, 2017 2016 Classification (Millions) Assets (liabilities): Cash and cash equivalents $ 881 $ 145 Cash and cash equivalents Trade accounts and other receivables – net 972 925 Trade accounts and other receivables Inventories 113 138 Inventories Other current assets 176 205 Other current assets and deferred charges Investments 6,552 6,701 Investments Property, plant, and equipment – net 27,912 28,021 Property, plant, and equipment – net Intangible assets – net 8,790 9,662 Intangible assets – net of accumulated amortization Regulatory assets, deferred charges, and other noncurrent assets 507 467 Regulatory assets, deferred charges, and other Accounts payable (957 ) (589 ) Accounts payable Accrued liabilities including current asset retirement obligations (857 ) (1,122 ) Accrued liabilities Commercial paper — (93 ) Commercial paper Long-term debt due within one year (501 ) (785 ) Long-term debt due within one year Long-term debt (15,996 ) (17,685 ) Long-term debt Deferred income tax liabilities (16 ) (20 ) Deferred income tax liabilities Noncurrent asset retirement obligations (944 ) (798 ) Regulatory liabilities, deferred income, and other Long-term deferred income (1,119 ) (1,048 ) Regulatory liabilities, deferred income, and other Regulatory liabilities and other (1,690 ) (812 ) 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 percent interest 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 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 operator of 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 cost of the project is estimated to be approximately $740 million , which would be funded with capital contributions from WPZ and the other equity partners on a proportional basis. In December 2014, Constitution received approval from the Federal Energy Regulatory Commission (FERC) to construct and operate its proposed pipeline. However, in April 2016, the New York State Department of Environmental Conservation (NYSDEC) denied the necessary water quality certification under Section 401 of the Clean Water Act for the New York portion of the pipeline. In May 2016, Constitution appealed the NYSDEC’s denial of the Section 401 certification to the United States Court of Appeals for the Second Circuit, and in August 2017 the court issued a decision denying in part and dismissing in part Constitution’s appeal. The court expressly declined to rule on Constitution’s argument that the delay in the NYSDEC’s decision on Constitution’s Section 401 application constitutes a waiver of the certification requirement. The court determined that it lacked jurisdiction to address that contention, and found that jurisdiction over the waiver issue lies exclusively with the United States Court of Appeals for the District of Columbia Circuit. As to the denial itself, the court determined that NYSDEC’s action was not arbitrary or capricious. Constitution filed a petition for rehearing with the Second Circuit Court of Appeals, but in October the court denied our petition. In October 2017, WPZ filed a petition for declaratory order requesting the FERC to find that, by operation of law, the Section 401 certification requirement for the New York State portion of Constitution’s pipeline project was waived due to the failure by the NYSDEC to act on Constitution’s Section 401 application within a reasonable period of time as required by the express terms of such statute. In January 2018, the FERC denied WPZ’s petition, finding that Section 401 provides that a state waives certification only when it does not act on an application within one year from the date of the application. The project’s sponsors remain committed to the project, and, in that regard, we are pursuing two separate and independent paths in order to overturn the NYSDEC’s denial of the Section 401 certification. In January 2018, we filed a petition with the United States Supreme Court to review the decision of the Second Circuit Court of Appeals that upheld the merits of the NYSDEC’s denial of the Section 401 certification. And, in February 2018, we filed a request with the FERC for rehearing of its finding that the NYSDEC did not waive the Section 401 certification requirement. If the FERC denies such request, we will file a petition for review with the D.C. Circuit Court of Appeals. We estimate that the target in-service date for the project would be approximately 10 to 12 months following any court or FERC decision that the NYSDEC denial order was improper or that the NYSDEC waived the Section 401 certification requirement. 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, 2017, and are included within Property, plant, and equipment – net in 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.

Related Party Transactions

Related Party Transactions	12 Months Ended
	Dec. 31, 2017
Related Party Transactions [Abstract]
Related Party Transactions [Text Block]	Note 4 – Related Party Transactions Transactions with Equity-Method Investees We have purchases from our equity-method investees included in Product costs in the Consolidated Statement of Operations of $226 million , $180 million , and $187 million for the years ended 2017, 2016, and 2015, respectively. We have $20 million and $19 million included in Accounts payable in the Consolidated Balance Sheet with our equity-method investees at December 31, 2017 and 2016, 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 $67 million , $66 million , and $64 million for the years ended 2017, 2016, and 2015, respectively. 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 and $111 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 and 2015, respectively.

Investing Activities

Investing Activities	12 Months Ended
	Dec. 31, 2017
Investments [Abstract]
Investing Activities [Text Block]	Note 5 – Investing Activities Impairment of equity-method investments The following table presents other-than-temporary impairment charges related to certain equity-method investments (see Note 16 – 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 Acquisition of Additional Interests in Appalachia Midstream Investments During the first quarter of 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, WPZ has 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 (Ranch Westex) for $45 million . These transactions resulted in a total gain of $269 million reflected in Other investing income (loss) – net in the Consolidated Statement of Operations. The fair value of the increased interests in the Appalachia Midstream Investments received as consideration was estimated to be $1.1 billion using an income approach based on expected cash flows and an appropriate discount rate (a Level 3 measurement within the fair value hierarchy). The determination of estimated future cash flows involved significant assumptions regarding gathering volumes, rates, and related capital spending. A 9.5 percent discount rate was utilized and reflected our estimate of the cost of capital as impacted by market conditions and risks associated with the underlying business. Acquisition of Additional Interest in UEOM 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. 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. 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. Other investing income (loss) – net also includes $36 million and $27 million of interest income for 2016 and 2015, 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, 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, 2017 December 31, 2017 2016 (Millions) Equity-method investments: Appalachia Midstream Investments (1) $ 3,104 $ 2,062 UEOM 62% 1,383 1,448 Discovery 60% 534 572 Caiman II 58% 429 426 OPPL 50% 422 430 Laurel Mountain 69% 309 324 Gulfstream 50% 244 261 DBJV — — 988 Other Various 127 190 $ 6,552 $ 6,701 ___________ (1) Includes equity-method investments in multiple gathering systems in the Marcellus Shale with an approximate average 66 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 $1.8 billion at December 31, 2017 and $1.9 billion at December 31, 2016. For 2017 these differences primarily relate to our investments in Appalachia Midstream Investments and UEOM resulting from property, plant, and equipment, as well as customer-based intangible assets and goodwill. For 2016, the difference also includes DBJV. 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, 2017 2016 2015 (Millions) Appalachia Midstream Investments $ 70 $ 28 $ 93 DBJV 32 105 57 Caiman II 24 22 — Discovery 1 — 35 UEOM — — 357 Other 5 22 53 $ 132 $ 177 $ 595 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, 2017 2016 2015 (Millions) Appalachia Midstream Investments $ 270 $ 211 $ 219 Discovery 127 141 116 Gulfstream 92 100 88 UEOM 80 92 42 OPPL 68 69 45 Caiman II 49 40 33 DBJV 39 39 33 Laurel Mountain 32 28 31 Other 27 22 26 $ 784 $ 742 $ 633 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, 2017 2016 (Millions) Assets (liabilities): Current assets $ 447 $ 508 Noncurrent assets 9,181 9,695 Current liabilities (295 ) (412 ) Noncurrent liabilities (1,538 ) (1,484 ) Years Ended December 31, 2017 2016 2015 (Millions) Gross revenue $ 1,961 $ 1,883 $ 1,707 Operating income 871 799 690 Net income 806 726 611

Other Income and Expenses

Other Income and Expenses	12 Months Ended
	Dec. 31, 2017
Other Income and Expenses [Abstract]
Other Income and Expenses [Text Block]	Note 6 – 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, 2017 2016 2015 (Millions) Williams Partners Loss on sale of Canadian operations (Note 2) $ 4 $ 34 $ — Amortization of regulatory assets associated with asset retirement obligations 33 33 33 Accrual of regulatory liability related to overcollection of certain employee expenses 22 25 20 Project development costs related to Constitution (Note 3) 16 28 — Gains on contract settlements and terminations (15 ) — — Gain on sale of Refinery Grade Propylene Splitter (12 ) — — Net foreign currency exchange (gains) losses (1) — 10 (10 ) Gain on asset retirement — (11 ) — Other Loss on sale of Canadian operations (Note 2) 1 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 2 – Acquisitions and Divestitures ). 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 expenses includes $26 million in 2015 primarily related to professional advisory fees within the Williams Partners segment. • Selling, general, and administrative expenses includes $32 million in 2015 of general corporate expenses associated with integration and realignment of resources within the Other segment. • Operating and maintenance expenses includes $12 million in 2015 primarily related to employee transition costs within the Williams Partners segment. Additional Items Certain additional items included in the Consolidated Statement of Operations are as follows: • Service revenues includes $66 million , $58 million , and $239 million recognized in the fourth quarter of 2017, 2016, and 2015, respectively, from minimum volume commitment fees in the Barnett Shale and Mid-Continent regions within the Williams Partners segment. • Service revenues for the year ended December 31, 2016, includes $173 million associated with the amortization of deferred income related to the restructuring of certain gas gathering contracts in the Barnett Shale and Mid-Continent regions within the Williams Partners segment. • Service revenues were reduced by $15 million for the year ended December 31, 2016, related to potential refunds associated with a ruling received in certain rate case litigation within the Williams Partners segment. • Selling, general, and administrative expenses includes $9 million and $47 million for the years ended December 31, 2017 and 2016, respectively, of costs associated with our evaluation of strategic alternatives within the Other segment. Selling, general, and administrative expenses also includes $61 million for the year ended December 31, 2016, of project development costs related to a proposed propane dehydrogenation facility in Alberta, Canada within the Other segment. Beginning in the first quarter of 2016, these costs did not qualify for capitalization. • Selling, general, and administrative expenses and Operating and maintenance expenses includes $22 million in severance and other related costs for the year ended December 31, 2017, for the Williams Partners segment. The year ended December 31, 2016, included $42 million in severance and other related costs associated with an approximate 10 percent reduction in workforce in the first quarter of 2016, primarily within the Williams Partners segment. • Selling, general, and administrative expenses and Operating and maintenance expenses includes $35 million of settlement charge expense in 2017 related to the program to pay out certain deferred vested pension benefits within the Williams Partners segment (see Note 9 – Employee Benefit Plans ). • Other income (expense) – net below Operating income (loss) includes $71 million , $66 million , and $77 million for equity AFUDC for the years ended December 31, 2017, 2016, and 2015, respectively. Other income (expense) – net below Operating income (loss) also includes $52 million , $23 million and $18 million for the years ended December 31, 2017, 2016 and 2015, respectively, of income associated with regulatory assets related to the effects of deferred taxes on equity funds used during construction. • Other income (expense) – net below Operating income (loss) includes a $102 million charge for the year ended December 31, 2017, for regulatory assets associated with the effects of deferred taxes on equity funds used during construction as a result of Tax Reform comprised of $39 million within the Williams Partners segment and $63 million within the Other segment (see Note 1 – General, Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies ). • Other income (expense) – net below Operating income (loss) includes $35 million of settlement charge expense in 2017 related to the program to pay out certain deferred vested pension benefits (see Note 9 – Employee Benefit Plans ). • Other income (expense) – net below Operating income (loss) for the year ended December 31, 2017, includes a net gain of $30 million associated with the February 23, 2017, early retirement of $750 million of 6.125 percent senior unsecured notes that were due in 2022 and a net loss of $3 million associated with the July 3, 2017, early retirement of of $1.4 billion of 4.875 percent senior unsecured notes that were due in 2023. The net gain for the February 23, 2017, early retirement within the Other segment reflects $53 million of unamortized premium, partially offset by $23 million in premiums paid. The net loss for the July 3, 2017, early retirement within the Other segment reflects $51 million of unamortized premium, offset by $54 million in premiums paid (see Note 13 – Debt, Banking Arrangements, and Leases ).

Provision (Benefit) for Income

Provision (Benefit) for Income Taxes	12 Months Ended
	Dec. 31, 2017
Income Tax Disclosure [Abstract]
Provision (Benefit) for Income Taxes [Text Block]	Note 7 – Provision (Benefit) for Income Taxes The Provision (benefit) for income taxes includes: Years Ended December 31, 2017 2016 2015 (Millions) Current: Federal $ 15 $ — $ — State 23 2 (7 ) Foreign — (1 ) (55 ) 38 1 (62 ) Deferred: Federal (2,004 ) (6 ) (317 ) State (8 ) 61 (25 ) Foreign — (81 ) 5 (2,012 ) (26 ) (337 ) Provision (benefit) for income taxes $ (1,974 ) $ (25 ) $ (399 ) Reconciliations from the Provision (benefit) at statutory rate to recorded Provision (benefit) for income taxes are as follows: Years Ended December 31, 2017 2016 2015 (Millions) Provision (benefit) at statutory rate $ 187 $ (131 ) $ (600 ) Increases (decreases) in taxes resulting from: Impact of nontaxable noncontrolling interests (117 ) (22 ) 263 Federal Tax Reform rate change (1,932 ) — — State income taxes (net of federal benefit) (17 ) 3 (21 ) State deferred income tax rate change 26 43 — Foreign operations – net (including tax effect of Canadian Sale) (127 ) 78 8 Translation adjustment of certain unrecognized tax benefits — (1 ) (71 ) Other – net 6 5 22 Provision (benefit) for income taxes $ (1,974 ) $ (25 ) $ (399 ) Income (loss) before income taxes includes $7 million and $885 million of foreign loss in 2017 and 2016, respectively, and $20 million of foreign income in 2015. 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 2 – Acquisitions and Divestitures ) and the reversal of anticipatory foreign tax credits, partially offset by the tax effect of the impairments associated with our Canadian disposition. On December 22, 2017, Tax Reform was enacted. Most of the provisions of Tax Reform are not effective until after January 1, 2018. However, the deferred tax impact of reducing the U.S. corporate tax rate from 35 percent to 21 percent is recognized in the period of enactment. This remeasurement resulted in a reduction of our deferred tax liabilities of approximately $1.9 billion , with a corresponding net adjustment to Provision (benefit) for income taxes . Under the guidance provided by Securities and Exchange Commission Staff Accounting Bulletin No. 118, Income Tax Accounting Implications of the Tax Cuts and Jobs Act, we are recording provisional adjustments related to the impact of Tax Reform, including items such as direct expensing of assets placed into service after September 27, 2017. We anticipate that additional guidance from the Internal Revenue Service (IRS) will be released to guide us in determining what assets are eligible for direct expensing in 2017. We are also recording provisional adjustments for valuation allowances associated with State losses and credits (see following table), since, at this time, we cannot assess the impact that the interest expense disallowance will have on our estimated future taxable income. We are not reducing our Minimum tax credit (see following table) for sequestration until we receive further guidance on that matter. 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 16 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk .) 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 . Significant components of Deferred income tax liabilities and Deferred income tax assets are as follows: December 31, 2017 2016 (Millions) Deferred income tax liabilities: Investments $ 3,565 $ 5,300 Other 19 29 Total deferred income tax liabilities 3,584 5,329 Deferred income tax assets: Accrued liabilities 53 145 Minimum tax credit 155 139 Foreign tax credit 140 140 Federal loss carryovers — 651 State losses and credits 283 313 Other 30 37 Total deferred income tax assets 661 1,425 Less valuation allowance 224 334 Net deferred income tax assets 437 1,091 Overall net deferred income tax liabilities $ 3,147 $ 4,238 As of December 31, 2017, Overall net deferred income tax liabilities reflects the 21 percent federal rate change as established by Tax Reform. We consider all amounts recorded related to Tax Reform to be reasonable estimates. The amounts recorded are provisional as our interpretation, assessment, and presentation of the impact of the tax law change may be further clarified with additional guidance from regulatory, tax, and accounting authorities. Should additional guidance be provided by these authorities or other sources, we will review the provisional amounts and adjust as appropriate. The valuation allowance at December 31, 2017 and 2016 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 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 credits is 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 2018 and 2037 with some carryovers having indefinite carryforward periods. The Valuation allowance change from prior year is primarily due to releasing a $127 million valuation allowance on a deferred tax asset associated with a capital loss carryover. Under Tax Reform, the federal Minimum tax credit of $155 million will be refunded/utilized no later than 2021. Foreign tax credit carryforwards of $ 140 million are expected to be utilized prior to their expiration between 2024 and 2027. Federal deferred income tax assets related to our net operating loss carryovers and charitable contribution carryovers at the end of 2017 are fully offset by our unrecognized tax positions in the table below. Cash payments for income taxes (net of refunds) were $28 million and $5 million in 2017 and 2016, respectively. Cash refunds for income taxes (net of payments and discontinued operations) were $136 million in 2015. As of December 31, 2017 , we had approximately $50 million of unrecognized tax benefits. If recognized, income tax expense would be reduced by $50 million and $49 million for 2017 and 2016, 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: 2017 2016 (Millions) Balance at beginning of period $ 50 $ 55 Reductions for tax positions of prior years — (4 ) Changes due to currency translation — (1 ) Balance at end of period $ 50 $ 50 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 benefits of $400 thousand and $22 million for 2017 and 2015, respectively, and expenses of $300 thousand for 2016. Approximately $2 million and $3 million of interest and penalties primarily relating to uncertain tax positions have been accrued as of December 31, 2017 and 2016 , respectively. 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 IRS examination for years after 2010. As of December 31, 2017, examinations of tax returns for 2011 through 2013 are currently in process. We do not expect material changes in our financial position resulting from these examinations. The statute of limitations for most states expires one year after expiration of the IRS statute. Generally, tax returns for our previously owned Canadian entities are open to audit for tax years after 2012. Tax years 2013 and 2014 are currently under examination. We have indemnified the purchaser for any adjustments to Canadian tax returns for periods prior to the sale of our Canadian operations in September 2016. 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.

Earnings (Loss) Per Common Shar

Earnings (Loss) Per Common Share	12 Months Ended
	Dec. 31, 2017
Earnings Per Share [Abstract]
Earnings (Loss) Per Common Share [Text Block]	Note 8 – Earnings (Loss) Per Common Share Years Ended December 31, 2017 2016 2015 (Dollars in millions, except per-share amounts; shares in thousands) Net income (loss) attributable to The Williams Companies, Inc. available to common stockholders for basic and diluted earnings (loss) per common share $ 2,174 $ (424 ) $ (571 ) Basic weighted-average shares 826,177 750,673 749,271 Effect of dilutive securities: Nonvested restricted stock units 1,704 — — Stock options 637 — — Diluted weighted-average shares (1) 828,518 750,673 749,271 Earnings (loss) per common share: Basic $ 2.63 $ (.57 ) $ (.76 ) Diluted $ 2.62 $ (.57 ) $ (.76 ) ________________ (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.

Employee Benefit Plans

Employee Benefit Plans	12 Months Ended
	Dec. 31, 2017
Retirement Benefits [Abstract]
Employee Benefit Plans [Text Block]	Note 9 – 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 annuity and lump-sum payments. In addition to our pension plans, we currently provide subsidized retiree medical and life insurance benefits (other postretirement benefits) to certain eligible participants. Generally, employees hired after December 31, 1991, are not eligible for the subsidized retiree medical benefits, except for participants that were employees or retirees of Transco Energy Company on December 31, 1995, 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. In September 2017, we initiated a program to pay out certain deferred vested pension benefits to reduce investment risk, cash funding volatility, and administrative costs. In December 2017, the lump-sum payments were made and the annuity payments were commenced in relation to this program. As a result of these lump-sum payments, as well as lump-sum benefit payments made throughout 2017, settlement accounting was required. We settled $ 261 million in liabilities of our pension plans and recognized a pre-tax, non-cash settlement charge of $ 71 million , of which $35 million is reported in Other income (expense) – net below Operating income (loss) in the Consolidated Statement of Operations (see Note 6 – Other Income and Expenses ). These amounts are included within the subsequent tables of changes in benefit obligations and plan assets, net periodic benefit cost (credit), and other changes in plan assets and benefit obligations recognized in other comprehensive income (loss) before taxes. 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 2017 2016 2017 2016 (Millions) Change in benefit obligation: Benefit obligation at beginning of year $ 1,466 $ 1,464 $ 197 $ 202 Service cost 50 54 1 1 Interest cost 59 62 8 8 Plan participants’ contributions — — 3 2 Benefits paid (35 ) (130 ) (14 ) (15 ) Actuarial loss (gain) 40 20 11 (1 ) Settlements (261 ) (4 ) — — Net increase (decrease) in benefit obligation (147 ) 2 9 (5 ) Benefit obligation at end of year 1,319 1,466 206 197 Change in plan assets: Fair value of plan assets at beginning of year 1,254 1,241 208 201 Actual return on plan assets 184 82 25 13 Employer contributions 85 65 5 7 Plan participants’ contributions — — 3 2 Benefits paid (35 ) (130 ) (14 ) (15 ) Settlements (261 ) (4 ) — — Net increase (decrease) in fair value of plan assets (27 ) 13 19 7 Fair value of plan assets at end of year 1,227 1,254 227 208 Funded status — overfunded (underfunded) $ (92 ) $ (212 ) $ 21 $ 11 Accumulated benefit obligation $ 1,294 $ 1,440 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, 2017 2016 (Millions) Underfunded pension plans: Current liabilities $ (2 ) $ (2 ) Noncurrent liabilities (90 ) (210 ) Overfunded (underfunded) other postretirement benefit plans: Current liabilities (6 ) (7 ) Noncurrent assets (liabilities) 27 18 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. The pension plans’ benefit obligation Actuarial loss (gain) of $ 40 million in 2017 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 $20 million in 2016 is primarily due to the impact of a decrease in the discount rates utilized to calculate the benefit obligation. The 2017 benefit obligation Actuarial loss (gain) of $ 11 million for our other postretirement benefit plans is primarily due to a decrease in the discount rate used to calculate the benefit obligation. At December 31, 2017 and 2016 , 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 (credit) at December 31 are as follows: Pension Benefits Other Postretirement Benefits 2017 2016 2017 2016 (Millions) Amounts included in Accumulated other comprehensive income (loss) : Prior service credit $ — $ — $ — $ 5 Net actuarial loss (375 ) (535 ) (21 ) (18 ) Amounts included in regulatory liabilities associated with Transco and Northwest Pipeline: Prior service credit N/A N/A $ 2 $ 10 Net actuarial gain N/A N/A 14 8 In addition to the regulatory liabilities included in the previous table, differences in the amount of actuarially determined Net periodic benefit cost (credit) for our other postretirement benefit 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 $108 million at December 31, 2017 and $94 million at December 31, 2016 , 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, 2017 and 2016 , these regulatory liabilities were $33 million and $21 million , respectively. These pension and other postretirement plans amounts will be reflected in future rates based on the rate structures of these gas pipelines. Net Periodic Benefit Cost (Credit) Net periodic benefit cost (credit) for the years ended December 31 consist of the following: Pension Benefits Other Postretirement Benefits 2017 2016 2015 2017 2016 2015 (Millions) Components of net periodic benefit cost (credit): Service cost $ 50 $ 54 $ 59 $ 1 $ 1 $ 2 Interest cost 59 62 58 8 8 9 Expected return on plan assets (82 ) (85 ) (75 ) (11 ) (12 ) (12 ) Amortization of prior service credit — — — (13 ) (15 ) (17 ) Amortization of net actuarial loss 27 30 42 — — 2 Net actuarial loss from settlements 71 2 2 — — — Reclassification to regulatory liability — — — 3 4 3 Net periodic benefit cost (credit) $ 125 $ 63 $ 86 $ (12 ) $ (14 ) $ (13 ) Items Recognized in Other Comprehensive Income (Loss) and Regulatory Assets and Liabilities Other changes in plan assets and benefit obligations recognized in Other comprehensive income (loss) before taxes for the years ended December 31 consist of the following: Pension Benefits Other Postretirement Benefits 2017 2016 2015 2017 2016 2015 (Millions) Other changes in plan assets and benefit obligations recognized in Other comprehensive income (loss) : Net actuarial gain (loss) $ 62 $ (23 ) $ 5 $ (3 ) $ — $ 8 Amortization of prior service credit — — — (5 ) (6 ) (6 ) Amortization of net actuarial loss 27 30 42 — — 2 Net actuarial loss from settlements 71 2 2 — — — Other changes in plan assets and benefit obligations recognized in Other comprehensive income (loss) $ 160 $ 9 $ 49 $ (8 ) $ (6 ) $ 4 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 and liabilities. Amounts recognized in regulatory assets and liabilities for the years ended December 31 consist of the following: 2017 2016 2015 (Millions) Other changes in plan assets and benefit obligations recognized in regulatory (assets) and liabilities: Net actuarial gain (loss) $ 6 $ 2 $ 10 Amortization of prior service credit (8 ) (9 ) (11 ) Pre-tax amounts expected to be amortized in Net periodic benefit cost (credit) in 2018 are as follows: Pension Benefits Other Postretirement Benefits (Millions) Amounts included in Accumulated other comprehensive income (loss) : Prior service credit $ — $ (1 ) Net actuarial loss 23 — Amounts included in regulatory liabilities associated with Transco and Northwest Pipeline: Prior service credit N/A $ (2 ) 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 2017 2016 2017 2016 Discount rate 3.66 % 4.17 % 3.71 % 4.27 % Rate of compensation increase 4.93 4.87 N/A N/A The weighted-average assumptions utilized to determine Net periodic benefit cost (credit) for the years ended December 31 are as follows: Pension Benefits Other Postretirement Benefits 2017 2016 2015 2017 2016 2015 Discount rate 4.17 % 4.37 % 3.96 % 4.27 % 4.50 % 4.12 % Expected long-term rate of return on plan assets 6.45 6.85 6.38 5.53 6.11 5.70 Rate of compensation increase 4.87 4.88 4.62 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 2018 is 8.0 percent. This rate decreases to 4.5 percent by 2026 . 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 5 (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 approximately 37 percent of the other postretirement benefit plan assets are subject to income tax; therefore, certain investments are managed in a tax efficient manner. The investment policy for the pension plans includes a general target asset allocation at December 31, 2017 , of 46 percent equity securities and 54 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. The fair values of our pension plan assets at December 31, 2017 and 2016 by asset class are as follows: 2017 Quoted Prices Significant Significant Total (Millions) Pension assets: Cash management fund $ 17 $ — $ — $ 17 Equity securities: U.S. large cap 62 — — 62 U.S. small cap 54 — — 54 Fixed income securities (1): U.S. Treasury securities 103 — — 103 Government and municipal bonds — 15 — 15 Mortgage and asset-backed securities — 47 — 47 Corporate bonds — 158 — 158 Insurance company investment contracts and other — 5 — 5 $ 236 $ 225 $ — 461 Commingled investment funds measured at net asset value practical expedient (2): Equities — U.S. large cap 265 Equities — International small cap 26 Equities — International emerging markets 41 Equities — International developed markets 110 Fixed income — U.S. long duration 205 Fixed income — Corporate bonds 119 Total assets at fair value at December 31, 2017 $ 1,227 2016 Quoted Prices Significant Significant 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 (2): 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 The fair values of our other postretirement benefits plan assets at December 31, 2017 and 2016 by asset class are as follows: 2017 Quoted Prices Significant Significant Total (Millions) Other postretirement benefit assets: Cash management funds $ 11 $ — $ — $ 11 Equity securities: U.S. large cap 25 — — 25 U.S. small cap 14 — — 14 International developed markets large cap growth — 6 — 6 Fixed income securities (1): U.S. Treasury securities 12 — — 12 Government and municipal bonds — 2 — 2 Mortgage and asset-backed securities — 5 — 5 Corporate bonds — 19 — 19 Mutual fund — Municipal bonds 43 — — 43 $ 105 $ 32 $ — 137 Commingled investment funds measured at net asset value practical expedient (2): Equities — U.S. large cap 31 Equities — International small cap 3 Equities — International emerging markets 5 Equities — International developed markets 13 Fixed income — U.S. long duration 24 Fixed income — Corporate bonds 14 Total assets at fair value at December 31, 2017 $ 227 2016 Quoted Prices Significant Significant 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 (1): 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 (2): 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 ____________ (1) The weighted-average credit quality rating of the fixed income security portfolio is investment grade with a weighted-average duration of approximately 12 years for 2017 and 8 years for 2016 . (2) The stated intents of the funds vary based on each commingled fund’s investment objective. These objectives generally include strategies to replicate or outperform various market indices. Certain standard withdrawal restrictions generally apply, which may include redemption notification period restrictions ranging from 10 to 30 days. Additionally, the fund managers retain the right to restrict withdrawals from and/or purchases into the funds so as not to disadvantage other investors in the funds. Generally, the funds also reserve the right to make all or a portion of the redemption in-kind rather than in cash or a combination of cash and in-kind. The fair value measurement level within the fair value hierarchy is based on the lowest level of any input that is significant to the fair value measurement of an asset. Shares of the cash management funds and mutual funds are valued at fair value based on published market prices as of the close of business on the last business day of the year, which represents the net asset values of the shares held. The fair values of equity securities traded on U.S. exchanges are derived from quoted market prices as of the close of business on the last business day of the year. The fair values of equity securities traded on foreign exchanges are also derived from quoted market prices as of the close of business on an active foreign exchange on the last business day of the year. However, the valuation requires translation of the foreign currency to U.S. dollars and this translation is considered an observable input to the valuation. The fair values of all commingled investment funds are determined based on the net asset values per unit of each of the funds. The net asset values per unit represent the aggregate values of the funds’ assets at fair value less liabilities, divided by the number of units outstanding. The fair values of fixed income securities, except U.S. Treasury securities, are determined using pricing models. These pricing models incorporate observable inputs such as benchmark yields, reported trades, broker/dealer quotes, and issuer spreads for similar securities to determine fair value. The U.S. Treasury securities are valued at fair value based on closing prices on the last business day of the year reported in the active market in which the security is traded. There have been no significant changes in the preceding valuation methodologies used at December 31, 2017 and 2016 . Additionally, there were no transfers or reclassifications of investments between Level 1 and Level 2 from December 2016 to December 2017 . 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) 2018 $ 91 $ 13 2019 90 13 2020 92 14 2021 96 13 2022 96 13 2023-2027 486 60 In 2018 , we expect to contribute approximately $80 million to our tax-qualified pension plans and approximately $5 million to our nonqualified pension plans, for a total of approximately $85 million , and approximately $6 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 $34 million in 2017 , $36 million in 2016 , and $39 million in 2015 .

Property, Plant, and Equipment

Property, Plant, and Equipment	12 Months Ended
	Dec. 31, 2017
Property, Plant and Equipment [Abstract]
Property, Plant, and Equipment [Text Block]	Note 10 – 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, 2017 2016 (Millions) Nonregulated: Natural gas gathering and processing facilities (2) 5 - 40 $ 18,440 $ 19,523 Construction in progress Not applicable 566 412 Other (2) 2 - 45 2,776 3,092 Regulated: Natural gas transmission facilities 1.20 - 6.97 14,460 12,692 Construction in progress Not applicable Not applicable 1,637 1,603 Other 5 - 45 1.35 - 33.33 1,634 1,590 Total property, plant, and equipment, at cost 39,513 38,912 Accumulated depreciation and amortization (11,302 ) (10,484 ) Property, plant, and equipment — net $ 28,211 $ 28,428 __________ (1) Estimated useful life and depreciation rates are presented as of December 31, 2017 . Depreciation rates and estimated useful lives for regulated assets are prescribed by the FERC. (2) The 2016 presentation has been changed to reflect $890 million of right-of-way assets previously presented in Natural gas gathering and processing facilities , now in Other . Depreciation and amortization expense for Property, plant, and equipment – net was $1.389 billion , $1.407 billion , and $1.382 billion in 2017 , 2016 , and 2015 , respectively. Regulated Property, plant, and equipment – net includes approximately $626 million and $665 million at December 31, 2017 and 2016 , 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. The following table presents the significant changes to our ARO, of which $946 million and $801 million are included in Regulatory liabilities, deferred income, and other with the remaining current portion in Accrued liabilities at December 31, 2017 and 2016 , respectively. December 31, 2017 2016 (Millions) Beginning balance $ 862 $ 915 Liabilities incurred 33 24 Liabilities settled (16 ) (8 ) Accretion expense (1) 141 69 Revisions (2) (22 ) (138 ) Ending balance $ 998 $ 862 ___________ (1) The increase in accretion expense for 2017 includes an adjustment associated with obligations identified from certain Transco land agreements. (2) Several factors are considered in the annual review process, including inflation rates, current estimates for removal cost, market risk premiums, discount rates, and the estimated remaining useful life of the assets. The 2017 revisions reflect changes in removal cost estimates and decreases in the estimated remaining useful life of certain assets and discount rates used in the annual review process. 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 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 16 – 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.

Goodwill and Other Intangible A

Goodwill and Other Intangible Assets	12 Months Ended
	Dec. 31, 2017
Goodwill and Intangible Assets Disclosure [Abstract]
Goodwill and Other Intangible Assets [Text Block]	Note 11 – Goodwill and Other Intangible Assets Goodwill At December 31, 2017, 2016, and 2015, our Consolidated Balance Sheet includes $47 million of goodwill in Intangible assets – net of accumulated amortization , reported in the Williams Partners segment. 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, 2017 and 2016. 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 16 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk .) 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: 2017 2016 Gross Carrying Amount Accumulated Amortization Gross Carrying Amount Accumulated Amortization (Millions) Contractual customer relationships $ 10,027 $ (1,283 ) $ 10,635 $ (1,019 ) Other intangible assets primarily relate to gas gathering, processing, and fractionation contractual customer relationships recognized in acquisitions including ACMP and Eagle Ford (see Note 2 – Acquisitions and Divestitures ). The decrease in the gross carrying amount of other intangible assets during 2017 is primarily related to the impairment of certain gathering operations in the Mid-Continent and Marcellus South regions (see Note 16 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk ). The write-off of accumulated amortization related to the impaired assets is the primary reason for the difference between the change in accumulated amortization during 2017 indicated above and the amortization expense for 2017 noted below. 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 acquisition), the weighted-average period prior to the next renewal or extension of the contractual customer relationships associated with the Eagle Ford acquisition was approximately 10 years . Although a significant portion of the expected future cash flows associated with these contractual customer relationships are dependent on our ability to renew or extend the arrangements beyond the initial contract periods, these expected future cash flows are significantly influenced by the scope and pace of our producer customers’ drilling programs. Once producer customers’ wells are connected to our gathering infrastructure, their likelihood of switching to another provider before the wells are abandoned is reduced due to the significant capital investment required. The amortization expense related to other intangible assets was $347 million , $356 million , and $353 million in 2017 , 2016 , and 2015 , respectively. The estimated amortization expense for each of the next five succeeding fiscal years is approximately $337 million.

Accrued Liabilities

Accrued Liabilities	12 Months Ended
	Dec. 31, 2017
Accrued Liabilities, Current [Abstract]
Accrued Liabilities [Text Block]	Note 12 – Accrued Liabilities December 31, 2017 2016 (Millions) Deferred income $ 361 $ 338 Interest on debt 267 310 Employee costs 202 223 Refundable deposits — 160 Property taxes 63 55 Asset retirement obligations 53 61 Other, including other loss contingencies 221 301 $ 1,167 $ 1,448 Deferred income 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 paid WPZ an aggregate amount of $240 million in three equal installments as certain milestones of the project were met. During the third quarter of 2017 WPZ received the final installment and placed the project into service. As a result of placing the project into service, WPZ reclassified the Refundable deposits to Accrued liabilities and Regulatory liabilities, deferred income, and other and expects to recognize income associated with these receipts over the term of an underlying contract.

Debt, Banking Arrangements, and

Debt, Banking Arrangements, and Leases	12 Months Ended
	Dec. 31, 2017
Debt Disclosure [Abstract]
Debt, Banking Arrangements, and Leases [Text Block]	Note 13 – Debt, Banking Arrangements, and Leases Long-Term Debt December 31, 2017 2016 (Millions) Transco: 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 1,000 5.4% Notes due 2041 375 375 4.45% Notes due 2042 400 400 Other financing obligation 231 — Northwest Pipeline: 5.95% Notes due 2017 — 185 6.05% Notes due 2018 250 250 7.125% Debentures due 2025 85 85 4% Notes due 2027 250 — WPZ: 7.25% Notes due 2017 — 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 4.5% Notes due 2023 600 600 4.875% Notes due 2023 — 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 3.75% Notes due 2027 1,450 — 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 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 7.75% Notes due 2031 252 252 8.75% Notes due 2032 445 445 5.75% Notes due 2044 650 650 Various — 7.625% to 10.25% Notes and Debentures due 2019 to 2027 55 55 Credit facility loans 270 775 Debt issuance costs (122 ) (119 ) Net unamortized debt premium (discount) (24 ) 88 Total long-term debt, including current portion 20,935 23,409 Long-term debt due within one year (501 ) (785 ) Long-term debt $ 20,434 $ 22,624 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) and debt issuance costs, for each of the next five years: December 31, 2017 (Millions) 2018 $ 502 2019 33 2020 2,123 2021 1,143 2022 2,003 Issuances and retirements On July 6, 2017, WPZ repaid its $850 million variable interest rate term loan that was due December 2018 using proceeds from the sale of its Geismar Interest. On June 5, 2017, WPZ issued $1.45 billion of 3.75 percent senior unsecured notes due 2027. WPZ used the proceeds for general partnership purposes, primarily the July 3, 2017, repayment of $1.4 billion of 4.875 percent senior unsecured notes that were due in 2023. 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, and for general corporate purposes. As part of the issuance, Northwest Pipeline entered into a registration rights agreement with the initial purchasers of the unsecured notes. Under the terms of the agreement, Northwest Pipeline was obligated to file and consummate a registration statement for an offer to exchange the notes for a new issue of substantially identical notes registered under the Securities Act of 1933, as amended, within 365 days from closing and to use commercially reasonable efforts to complete the exchange offer. Northwest Pipeline has filed the registration statement, which became effective in January 2018. The exchange offer is expected to be completed in the first quarter of 2018. On February 23, 2017, using 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. 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. Other financing obligation During the construction of Transco’s Dalton expansion project, WPZ received funding from a partner for its proportionate share of construction costs related to its undivided ownership interest in the project. Amounts received were recorded within noncurrent liabilities and 100 percent of the costs associated with construction were capitalized on our Consolidated Balance Sheet. Upon placing the project in service during the third quarter of 2017, WPZ began leasing this partner’s undivided interest in the lateral, including the associated pipeline capacity, and reclassified approximately $237 million of funding previously received from its partner from noncurrent liabilities to debt to reflect the financing obligation payable to its partner over an expected term of 35 years . Credit Facilities December 31, 2017 Available Outstanding (Millions) WMB Long-term credit facility $ 1,500 $ 270 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. In November 2017, the maturity date of the credit facility was extended to February 2, 2021. However, we may request an additional extension of the maturity date for a 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 the London Interbank Offered Rate (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, 2017. As of February 20, 2018, there are no amounts outstanding under our long-term credit facility. WPZ long-term credit facilities 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. In November 2017, the maturity date of the credit facility was extended to February 2, 2021. However, the co-borrowers may request an additional extension of the maturity date for a 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. 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 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 5.00 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. 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, 2017. As of February 20, 2018, there are no amounts outstanding under the WPZ long-term credit facility. 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. At December 31, 2017 , WPZ had no Commercial paper outstanding. At December 31, 2016 , WPZ had $93 million of Commercial paper outstanding at a weighted-average interest rate of 1.06 percent , which was classified in Current liabilities in the Consolidated Balance Sheet , as the outstanding notes had maturity dates less than three months from the date of issuance. Cash Payments for Interest (Net of Amounts Capitalized) Cash payments for interest (net of amounts capitalized) were $1.110 billion in 2017, $1.152 billion in 2016, and $1.023 billion in 2015. 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, 2017, 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, 2017, was $16 billion . Leases-Lessee The future minimum annual rentals under noncancelable operating leases, are payable as follows: December 31, 2017 (Millions) 2018 $ 43 2019 41 2020 33 2021 33 2022 29 Thereafter 137 Total $ 316 Total rent expense was $62 million in 2017, $64 million in 2016, and $69 million in 2015 and primarily included in Operating and maintenance expenses and Selling, general, and administrative expenses in the Consolidated Statement of Operations .

Stockholders' Equity

Stockholders' Equity	12 Months Ended
	Dec. 31, 2017
Stockholders' Equity Note [Abstract]
Stockholders' Equity [Text Block]	Note 14 – Stockholders' Equity Cash dividends declared per common share were $1.20 , $1.68 , and $2.45 for 2017 , 2016 , and 2015 , respectively. On February 21, 2018, our board of directors approved a regular quarterly dividend of $0.34 per share payable on March 26, 2018. In January 2017, we issued 65 million shares of common stock in a public offering at a price of $29.00 per share. In February 2017, we issued 9.75 million shares of common stock pursuant to the full exercise of the underwriter’s option to purchase additional shares. The net proceeds of approximately $2.1 billion were used to purchase newly issued common units in WPZ as part of our Financial Repositioning. (See Note 1 – General, Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies .) AOCI The following table presents the changes in AOCI by component, net of income taxes: Cash Flow Hedges Foreign Currency Translation Pension and Other Post Retirement Benefits Total (Millions) Balance at December 31, 2016 $ — $ (2 ) $ (337 ) $ (339 ) Other comprehensive income (loss) before reclassifications (6 ) 1 44 39 Amounts reclassified from accumulated other comprehensive income (loss) 4 — 58 62 Other comprehensive income (loss) (2 ) 1 102 101 Balance at December 31, 2017 $ (2 ) $ (1 ) $ (235 ) $ (238 ) Reclassifications out of AOCI are presented in the following table by component for the year ended December 31, 2017 : Component Reclassifications Classification (Millions) Cash flow hedges: Energy commodity contracts $ 7 Product sales and Product costs Pension and other postretirement benefits: Amortization of prior service cost (credit) included in net periodic benefit cost (credit) (5 ) Note 9 – Employee Benefit Plans Amortization of actuarial (gain) loss and net actuarial loss from settlements included in net periodic benefit cost (credit) 98 Note 9 – Employee Benefit Plans Total before tax 100 Income tax benefit (36 ) Provision (benefit) for income taxes Net of income tax 64 Noncontrolling interest (2 ) Net income (loss) attributable to noncontrolling interests Reclassifications during the period $ 62

Equity-Based Compensation

Equity-Based Compensation	12 Months Ended
	Dec. 31, 2017
Share-based Compensation [Abstract]
Equity-Based Compensation [Text Block]	Note 15 – 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 to, restricted stock units and stock options. At December 31, 2017 , 26 million shares of our common stock were reserved for issuance pursuant to existing and future stock awards, of which 15 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. Employees purchased 272 thousand shares at an average price of $25.83 per share during 2017 . Approximately 1.1 million shares were available for purchase under the ESPP at December 31, 2017 . Operating and maintenance expenses and Selling, general, and administrative expenses include equity-based compensation expense for the years ended December 31, 2017 , 2016 , and 2015 of $70 million , $53 million , and $56 million , respectively. Income tax benefit recognized related to the stock-based compensation expense for the years ended December 31, 2017 , 2016 , and 2015 was $17 million , $20 million , and $21 million , respectively. Measured but unrecognized stock-based compensation expense at December 31, 2017 , was $61 million , comprised of $4 million related to stock options and $57 million related to restricted stock units. These amounts are expected to be recognized over a weighted-average period of 1.8 years. Stock Options The following summary reflects stock option activity and related information for the year ended December 31, 2017 : Stock Options Options Weighted- Average Exercise Price Aggregate Intrinsic Value (Millions) (Millions) Outstanding at December 31, 2016 6.2 $ 31.32 Granted 1.0 $ 28.85 Exercised (0.5 ) $ 21.33 Cancelled (0.1 ) $ 36.75 Outstanding at December 31, 2017 6.6 $ 31.53 $ 23 Exercisable at December 31, 2017 5.1 $ 31.85 $ 19 The following table summarizes additional information related to stock option activity during each of the last three years: Years Ended December 31, 2017 2016 2015 (Millions) Total intrinsic value of options exercised $ 4 $ 2 $ 37 Tax benefits realized on options exercised $ 1 $ 1 $ 13 Cash received from the exercise of options $ 7 $ 4 $ 20 The weighted-average remaining contractual life for stock options outstanding and exercisable at December 31, 2017 , was 5.0 years and 4.0 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: 2017 2016 2015 Weighted-average grant date fair value of options for our common stock granted during the year, per share $ 6.61 $ 7.90 $ 7.61 Weighted-average assumptions: Dividend yield 4.2 % 3.2 % 4.8 % Volatility 35.1 % 44.7 % 27.8 % Risk-free interest rate 2.1 % 1.2 % 1.8 % Expected life (years) 6.0 6.0 6.0 The 2017 expected dividend yield is based on the 2017 dividend forecast and the grant-date market price of our stock. Our expected future volatility is determined using the historical volatility of our stock and implied volatility on our traded options. Historical volatility is based on the blended 10 -year historical volatility of our stock and certain peer companies. The risk-free interest rate is based on the U.S. Treasury Constant Maturity rates as of the grant date. The expected life of the option is based on historical exercise behavior and expected future experience. Nonvested Restricted Stock Units The following summary reflects nonvested restricted stock unit activity and related information for the year ended December 31, 2017 : Restricted Stock Units Outstanding Shares Weighted- Average Fair Value (1) (Millions) Nonvested at December 31, 2016 3.9 $ 35.19 Granted 2.0 $ 29.47 Forfeited (0.8 ) $ 39.21 Vested (0.9 ) $ 38.30 Nonvested at December 31, 2017 4.2 $ 31.02 ______________ (1) Performance-based restricted stock units are valued utilizing a Monte Carlo valuation method using measures of total shareholder return. All other restricted stock units are valued at the grant-date market price. Restricted stock units generally vest after three years . Value of Restricted Stock Units 2017 2016 2015 Weighted-average grant date fair value of restricted stock units granted during the year, per share $ 29.47 $ 26.51 $ 40.15 Total fair value of restricted stock units vested during the year ($’s in millions) $ 33 $ 32 $ 42 Performance-based restricted stock units granted under the Plan represent 31 percent of nonvested restricted stock units outstanding at December 31, 2017 . These grants may be earned at the end of the vesting period based on actual performance against a performance target. Based on the extent to which certain financial targets are achieved, vested shares may range from zero percent to 200 percent of the original grant amount. WPZ’s Plan Information During 2014, certain employees of ACMP’s general partner received equity-based compensation through ACMP’s equity-based compensation program. 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, and no additional grants are expected in the future. Equity-based compensation expense of $8 million , $20 million , and $29 million related to WPZ’s equity-based compensation program is included in Operating and maintenance expenses and Selling, general, and administrative expenses for the years ended December 31, 2017 , 2016 , and 2015 , respectively. The total fair value of the restricted common units vested during 2017 , 2016, and 2015 was $24 million , $34 million , and $5 million , respectively. As of December 31, 2017 , there were 76 thousand nonvested units outstanding and $1 million of unrecognized compensation expense attributable to the outstanding awards which will be recognized in 2018.

Fair Value Measurements, Guaran

Fair Value Measurements, Guarantees, and Concentration of Credit Risk	12 Months Ended
	Dec. 31, 2017
Fair Value Disclosures [Abstract]
Fair Value Measurements, Guarantees, and Concentration of Credit Risk [Text Block]	Note 16 – 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, 2017: Measured on a recurring basis: ARO Trust investments $ 135 $ 135 $ 135 $ — $ — Energy derivatives liabilities designated as hedging instruments (3 ) (3 ) (2 ) (1 ) — Energy derivatives liabilities not designated as hedging instruments (3 ) (3 ) — — (3 ) Additional disclosures: Other receivables 7 7 7 — — Long-term debt, including current portion (20,935 ) (23,005 ) — (23,005 ) — Guarantees (43 ) (30 ) — (14 ) (16 ) 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 ) 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 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, 2017 or 2016 . Additional fair value disclosures Other receivables: Other receivables 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. Long-term debt, including current portion : The disclosed fair value of our long-term debt is determined primarily by a market approach using broker quoted indicative period-end bond prices. The quoted prices are based on observable transactions in less active markets for our debt or similar instruments. The fair value of the financing obligation associated with our Dalton lateral, which is included within long-term debt, was determined using an income approach (see Note 13 – Debt, Banking Arrangements, and Leases ). Guarantees : Guarantees primarily consist of a guarantee we have provided in the event of nonpayment by our previously owned communications subsidiary, Williams Communications Group (WilTel), on a lease performance obligation that extends through 2042. Guarantees also include an indemnification related to a disposed operation. To estimate the fair value of the WilTel guarantee, an estimated default rate is applied to the sum of the future contractual lease payments using an income approach. The estimated default rate is determined by obtaining the average cumulative issuer-weighted corporate default rate based on the credit rating of WilTel’s current owner and the term of the underlying obligation. The default rate is published by Moody’s Investors Service. The carrying value of the WilTel guarantee is reported in Accrued liabilities in the Consolidated Balance Sheet. The maximum potential undiscounted exposure is approximately $30 million at December 31, 2017 . Our exposure declines systematically through the remaining term of WilTel’s obligation. The fair value of the guarantee associated with the indemnification related to a disposed operation was estimated using an income approach that considered probability-weighted scenarios of potential levels of future performance. The terms of the indemnification do not limit the maximum potential future payments associated with the guarantee. The carrying value of this guarantee is reported in Regulatory liabilities, deferred income, and other in the Consolidated Balance Sheet. We are required by our revolving credit 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 former 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. 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 2017 2016 2015 (Millions) Certain gathering operations (1) Property, plant, and equipment – net and Intangible assets - net of accumulated amortization Williams Partners September 30, 2017 $ 439 $ 1,019 Certain gathering operations (2) Property, plant, and equipment – net and Intangible assets - net of accumulated amortization Williams Partners September 30, 2017 21 115 Certain NGL pipeline (3) Property, plant, and equipment – net Other September 30, 2017 32 68 Certain olefins pipeline project (4) Property, plant, and equipment – net Other June 30, 2017 18 23 Canadian operations (5) Assets held for sale Other June 30, 2016 206 $ 406 Canadian operations (5) Assets held for sale Williams Partners June 30, 2016 924 341 Certain gathering operations (6) 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 Previously capitalized project development costs (7) Property, plant, and equipment – net Williams Partners December 31, 2015 13 $ 94 Previously capitalized project development costs (8) Property, plant, and equipment – net Other December 31, 2015 40 64 Surplus equipment (9) Property, plant, and equipment – net Williams Partners June 30, 2015 17 20 Level 3 fair value measurements of certain assets 1,225 803 178 Other impairments and write-downs (10) 23 70 31 Impairment of certain assets $ 1,248 $ 873 $ 209 Impairments Years Ended December 31, Classification Segment Date of Measurement Fair Value 2017 2016 2015 (Millions) Equity-method investments (11) Investments Williams Partners December 31, 2016 $ 1,295 $ 318 Equity-method investments (12) Investments Williams Partners March 31, 2016 1,294 109 Other equity-method investment Investments Williams Partners March 31, 2016 — 3 Equity-method investments (13) Investments Williams Partners December 31, 2015 4,017 $ 890 Equity-method investments (14) Investments Williams Partners September 30, 2015 1,203 461 Other equity-method investment Investments Williams Partners December 31, 2015 58 8 Impairment of equity-method investments $ 430 $ 1,359 ______________ (1) Relates to certain gathering operations in the Mid-Continent region. During the third quarter of 2017, we received solicitations and engaged in negotiations for the sale of certain of these assets which led to our impairment evaluation. The estimated fair value was determined using an income approach and incorporated market inputs based on ongoing negotiations for a potential sale of a portion of the underlying assets. For the income approach, we utilized a discount rate of 10.2 percent , reflecting an estimated cost of capital and risks associated with the underlying assets. (2) Relates to certain gathering operations in the Marcellus South region resulting from an anticipated decline in future volumes following a third-quarter 2017 shut-in by the primary producer. The estimated fair value was determined by the income approach utilizing a discount rate of 11.1 percent , reflecting an estimated cost of capital and risks associated with the underlying assets. (3) Relates to an NGL pipeline near the Houston Ship Channel region which we anticipate will be underutilized for the foreseeable future. The estimated fair value was primarily determined by using a market approach based on our analysis of observable inputs in the principal market. (4) Relates primarily to project development costs associated with an olefins pipeline project in the Gulf Coast region, the likelihood of completion of which is now considered remote. The estimated fair value of the remaining pipe and equipment considered a market approach based on our analysis of observable inputs in the principal market, as well as an estimate of replacement cost. (5) 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 2 – Acquisitions and Divestitures ). (6) 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. (7) 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. (8) 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. (9) 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. (10) Reflects multiple individually insignificant impairments and write-downs of other certain assets that may no longer be in use or are surplus in nature for which the fair value was determined to be lower than the carrying value. (11) Relates to Williams Partners’ previously held interest in Ranch Westex and multiple Appalachia Midstream Investments currently held. The historical carrying value of these equity-method investments was initially recorded based on estimated fair value during the third quarter of 2014 in conjunction with the acquisition of ACMP. We estimated the fair value of these Appalachia Midstream Investments using an income approach based on expected future cash flows and appropriate discount rates. The determination of estimated future cash flows involved significant assumptions regarding gathering volumes, rates, and related capital spending. The discount rate utilized for the Appalachia Midstream Investments evaluation was 10.2 percent and reflected an estimated cost of capital as impacted by market conditions and risks associated with the underlying businesses. In addition to utilizing an income approach, we also considered a market approach for certain Appalachia Midstream Investments and Ranch Westex based on an agreement reached in February 2017 to exchange our interests in DBJV and Ranch Westex for additional interests in certain Appalachia Midstream Investments and cash. (See Note 5 – Investing Activities ). (12) Relates to Williams Partners’ previously held interest in DBJV and currently held equity-method investment in Laurel Mountain. Our carrying values in these equity-method investments had been written down to fair value at December 31, 2015. Our first-quarter 2016 analysis reflected higher discount rates for both of these equity-method investments, along with lower natural gas prices for Laurel Mountain. We estimated the fair value of these equity-method investments using an income approach based on expected future cash flows and appropriate discount rates. The determination of estimated future cash flows involved significant assumptions regarding gathering volumes and related capital spending. Discount rates utilized ranged from 13.0 percent to 13.3 percent and reflected increases in the estimated cost of capital, revised estimates of expected future cash flows, and risks associated with the underlying businesses. (13) Relates to Williams Partners’ previously held interest in DBJV, as well as equity-method investments in certain of the Appalachia Midstream Investments, UEOM, and Laurel Mountain, all of which are currently held. We estimated the fair value of these equity-method investments using an income approach based on expected future cash flows and appropriate discount rates. The determination of estimated future cash flows involved significant assumptions regarding gathering volumes and related capital spending. Discount rates utilized ranged from 10.8 percent to 14.4 percent and reflected further fourth-quarter 2015 increases in the estimated cost of capital, revised estimates of expected future cash flows, and risks associated with the underlying businesses. (14) Relates to Williams Partners’ previously held interest in DBJV and certain of the Appalachia Midstream Investments currently held. The historical carrying value of these equity-method investments was initially recorded based on estimated fair value during the third quarter of 2014 in conjunction with the acquisition of ACMP. We estimated the fair value of these equity-method investments using an income approach based on expected future cash flows and appropriate discount rates. The determination of estimated future cash flows involved significant assumptions regarding gathering volumes and related capital spending. Discount rates utilized were 11.8 percent and 8.8 percent for DBJV and certain of the Appalachia Midstream Investments, respectively, and reflected an estimated cost of capital as impacted by market conditions, and risks associated with the underlying businesses. 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, 2017 2016 (Millions) NGLs, natural gas, and related products and services $ 760 $ 736 Transportation of natural gas and related products 212 187 Other 4 15 Total $ 976 $ 938 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, 2017 and 2016, Chesapeake Energy Corporation, and its affiliates (Chesapeake), a customer within our Williams Partners segment, accounted for $176 million and $133 million , respectively, of the consolidated Trade accounts and other receivables balances. Revenues In 2017 , 2016, and 2015, Chesapeake accounted for 10 percent , 14 percent , and 18 percent , respectively, of our consolidated revenues.

Contingent Liabilities and Comm

Contingent Liabilities and Commitments	12 Months Ended
	Dec. 31, 2017
Commitments and Contingencies Disclosure [Abstract]
Contingent Liabilities and Commitments [Text Block]	Note 17 – 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 Energy, Inc. (WPX) and its subsidiaries, and others alleging the manipulation of published gas price indices and seeking unspecified amounts of damages. Such actions were transferred to the Nevada federal district court for consolidation of discovery and pre-trial issues. We have agreed to indemnify WPX and its subsidiaries related to this matter. In the individual action, filed by Farmland Industries Inc. (Farmland), the court issued an order on May 24, 2016, granting one of our co-defendant’s motion for summary judgment as to Farmland’s claims. On January 5, 2017, the court extended such ruling to us, entering final judgment in our favor. Farmland has appealed. In the putative class actions, on March 30, 2017, the court issued an order denying the plaintiffs’ motions for class certification. On June 13, 2017, the United States Court of Appeals for the Ninth Circuit granted the plaintiffs’ petition for permission to appeal the order, and the appeal is now pending. Because of the uncertainty around the remaining pending unresolved issues, we cannot reasonably estimate a range of potential exposure at this time. However, it is reasonably possible that the ultimate resolution of these actions and our related indemnification obligation could result in a potential loss that may be material to our results of operations. In connection with this indemnification, we have an accrued liability balance associated with this matter, and as a result, have exposure to future developments in this matter. Alaska Refinery Contamination Litigation We are involved in litigation arising from our ownership and operation of the North Pole Refinery in North Pole, Alaska, from 1980 until 2004, through our wholly-owned subsidiaries, Williams Alaska Petroleum Inc. (WAPI) and MAPCO Inc. We sold the refinery to Flint Hills Resources Alaska, LLC (FHRA), a subsidiary of Koch Industries, Inc., in 2004. The litigation involves three cases, with filing dates ranging from 2010 to 2014. The actions arise from sulfolane contamination allegedly emanating from the refinery. A putative class action lawsuit was filed by James West in 2010 naming us, WAPI, and FHRA as defendants. We and FHRA filed claims against each other seeking, among other things, contractual indemnification alleging that the other party caused the sulfolane contamination. In 2011, we and FHRA settled the claim with James West. Certain claims by FHRA against us were resolved by the Alaska Supreme Court in our favor. FHRA’s claims against us for contractual indemnification and statutory claims for damages related to off-site sulfolane remain pending. The State of Alaska filed its action in March 2014, seeking damages. The City of North Pole (North Pole) filed its lawsuit in November 2014, seeking past and future damages, as well as punitive damages. Both we and WAPI asserted counterclaims against the State of Alaska and North Pole, and cross-claims against FHRA. FHRA has also filed cross-claims against us. The underlying factual basis and claims in the cases are similar and may duplicate exposure. As such, in February 2017, the three cases were consolidated into one action in state court containing the remaining claims from the James West case and those of the State of Alaska and North Pole. A trial encompassing all three cases was originally scheduled to commence in May 2017, but has been continued. A new trial date has not been scheduled. 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 to the State of Alaska or North Pole at this time. We currently estimate that our reasonably possible loss exposure to FHRA 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. 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. To date, no compliance order has been issued. Due to the ongoing assessment of the level and extent of sulfolane contamination, the ultimate cost of remediation and division of costs among the potentially responsible parties, and the previously described separate litigation, 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 filed in Pennsylvania based on allegations that we improperly participated with that major customer in causing the alleged royalty underpayments. We believe that the claims asserted are subject to indemnity obligations owed to us by that major customer. Due to the preliminary status of the cases, we are unable to estimate a range of potential loss at this time. Shareholder Litigation A purported shareholder filed a 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 Equity, L.P. (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, and on May 15, 2017, the court dismissed the action. On June 6, 2017, the plaintiff filed a notice of appeal, and on December 18, 2017, the Delaware Supreme Court affirmed the lower court’s decision. 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 former Chief Financial Officer 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, and on March 8, 2017, the court dismissed the complaint with prejudice. On April 7, 2017, the plaintiff filed a notice of appeal. We cannot reasonably estimate a range of potential loss related to these matters 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. On March 23, 2017, the Supreme Court of Delaware affirmed the Court of Chancery’s ruling. On March 30, 2017, we filed a motion for reargument with the Supreme Court of Delaware, which was denied on April 5, 2017. On September 16, 2016, we filed an amended complaint with the Court of Chancery seeking damages for breaches of the 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. On December 1, 2017, the court granted our motion to dismiss certain of Energy Transfer’s counterclaims, including its claim seeking payment of the $1.48 billion termination fee. On December 8, 2017, Energy Transfer filed a motion for reargument with the Court of Chancery. Environmental Matters We are a participant in certain environmental activities in various stages including assessment studies, cleanup operations, and/or remedial processes at certain sites, some of which we currently do not own. We are monitoring these sites in a coordinated effort with other potentially responsible parties, the U.S. Environmental Protection Agency (EPA), or other governmental authorities. We are jointly and severally liable along with unrelated third parties in some of these activities and solely responsible in others. Certain of our subsidiaries have been identified as potentially responsible parties at various Superfund and state waste disposal sites. In addition, these subsidiaries have incurred, or are alleged to have incurred, various other hazardous materials removal or remediation obligations under environmental laws. As of December 31, 2017 , we have accrued liabilities totaling $38 million for these matters, as discussed below. Estimates of the most likely costs of cleanup are generally based on completed assessment studies, preliminary results of studies, or our experience with other similar cleanup operations. At December 31, 2017 , 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. 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, 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 rule regarding National Ambient Air Quality Standards for ground-level ozone, setting a stricter standard of 70 parts per billion. We are monitoring the rule’s implementation as the reduction will trigger additional federal and state regulatory actions that may impact our operations. Implementation of the regulations is expected to result in impacts to our operations and increase the cost of additions to Property, plant, and equipment – net in the Consolidated Balance Sheet for both new and existing facilities in affected areas. We are unable to reasonably estimate the cost of additions that may be required to meet the regulations at this time due to uncertainty created by various legal challenges to these regulations and the need for further specific regulatory guidance. Continuing operations Our interstate gas pipelines are involved in remediation activities related to certain facilities and locations for polychlorinated biphenyls, mercury, and other hazardous substances. These activities have involved the EPA and various state environmental authorities, resulting in our identification as a potentially responsible party at various Superfund waste sites. At December 31, 2017 , we have accrued liabilities of $7 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, 2017 , we have accrued liabilities totaling $8 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; • Former exploration and production and mining operations; • Former electricity and natural gas marketing and trading operations. At December 31, 2017 , we have accrued environmental liabilities of $23 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, 2017 , other than as previously disclosed, we are not aware of any material claims against us involving the indemnities; thus, we do not expect any of the indemnities provided pursuant to the sales agreements to have a material impact on our future financial position. Any claim for indemnity brought against us in the future may have a material adverse effect on our results of operations in the period in which the claim is made. In addition to the foregoing, various other proceedings are pending against us which are incidental to our operations, none of which are expected to be material to our expected future annual results of operations, liquidity, and financial position. Summary We have disclosed our estimated range of reasonably possible losses for certain matters above, as well as all significant matters for which we are unable to reasonably estimate a range of possible loss. We estimate that for all other matters for which we are able to reasonably estimate a range of loss, our aggregate reasonably possible losses beyond amounts accrued are immaterial to our expected future annual results of operations, liquidity, and financial position. These calculations have been made without consideration of any potential recovery from third parties. Commitments Commitments for construction and acquisition of property, plant, and equipment are approximately $348 million at December 31, 2017 .

Segment Disclosures

Segment Disclosures	12 Months Ended
	Dec. 31, 2017
Segment Reporting [Abstract]
Segment Disclosures [Text Block]	Note 18 – 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 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. We define Modified EBITDA as follows: • Net income (loss) before: ◦ 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: 2017 $ 8,030 $ 1 $ 8,031 2016 7,425 74 7,499 2015 7,247 113 7,360 Long-lived assets: 2017 $ 37,002 $ — $ 37,002 2016 38,091 — 38,091 2015 38,016 1,580 39,596 Long-lived assets are comprised of property, plant, and equipment, goodwill, and other intangible assets. 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) 2017 Segment revenues: Service revenues External $ 5,291 $ 21 $ — $ 5,312 Internal 1 11 (12 ) — Total service revenues 5,292 32 (12 ) 5,312 Product sales External 2,718 1 — 2,719 Internal — — — — Total product sales 2,718 1 — 2,719 Total revenues $ 8,010 $ 33 $ (12 ) $ 8,031 Other financial information: Additions to long-lived assets $ 2,792 $ 22 $ — $ 2,814 Proportional Modified EBITDA of equity-method investments 795 — — 795 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 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, 2017 2016 2015 (Millions) Modified EBITDA by segment: Williams Partners $ 3,616 $ 3,864 $ 4,003 Other (150 ) (542 ) (112 ) 3,466 3,322 3,891 Accretion expense associated with asset retirement obligations for nonregulated operations (33 ) (31 ) (28 ) Depreciation and amortization expenses (1,736 ) (1,763 ) (1,738 ) Impairment of goodwill — — (1,098 ) Equity earnings (losses) 434 397 335 Impairment of equity-method investments — (430 ) (1,359 ) Other investing income (loss) – net 282 63 27 Proportional Modified EBITDA of equity-method investments (795 ) (754 ) (699 ) Interest expense (1,083 ) (1,179 ) (1,044 ) (Provision) benefit for income taxes 1,974 25 399 Net income (loss) $ 2,509 $ (350 ) $ (1,314 ) The following table reflects Total assets and Equity-method investments by reportable segments: Total Assets Equity-Method Investments December 31, 2017 December 31, 2016 December 31, 2017 December 31, 2016 (Millions) Williams Partners $ 45,903 $ 46,265 $ 6,552 $ 6,701 Other 589 685 — — Eliminations (140 ) (115 ) — — Total $ 46,352 $ 46,835 $ 6,552 $ 6,701

Schedule I - Condensed Financia

Schedule I - Condensed Financial Information of Registrant	12 Months Ended
	Dec. 31, 2017
Condensed Financial Information of Parent Company Only Disclosure [Abstract]
Schedule I - Condensed Financial Information of Registrant [Text Block]	The Williams Companies, Inc. Schedule I — Condensed Financial Information of Registrant Statement of Comprehensive Income (Loss) (Parent) Years Ended December 31, 2017 2016 2015 (Millions, except per-share amounts) Equity in earnings of consolidated subsidiaries $ 898 $ 522 $ 232 Interest incurred — external (261 ) (268 ) (255 ) Interest incurred — affiliate (413 ) (568 ) (828 ) Interest income — affiliate — — 6 Other income (expense) — net (23 ) (53 ) (75 ) Income (loss) before income taxes 201 (367 ) (920 ) Provision (benefit) for income taxes (1,973 ) 57 (349 ) Net income (loss) $ 2,174 $ (424 ) $ (571 ) Basic earnings (loss) per common share: Net income (loss) $ 2.63 $ (.57 ) $ (.76 ) Weighted-average shares (thousands) 826,177 750,673 749,271 Diluted earnings (loss) per common share: Net income (loss) $ 2.62 $ (.57 ) $ (.76 ) Weighted-average shares (thousands) 828,518 750,673 749,271 Other comprehensive income (loss): Equity in other comprehensive income (loss) of consolidated subsidiaries $ (2 ) $ 171 $ (204 ) Other comprehensive income (loss) attributable to The Williams Companies, Inc. 102 1 33 Other comprehensive income (loss) 100 172 (171 ) Less: Other comprehensive income (loss) attributable to noncontrolling interests (1 ) 69 (70 ) Comprehensive income (loss) attributable to The Williams Companies, Inc. $ 2,275 $ (321 ) $ (672 ) See accompanying notes. The Williams Companies, Inc. Schedule I — Condensed Financial Information of Registrant – (Continued) Balance Sheet (Parent) December 31, 2017 2016 (Millions) ASSETS Current assets: Cash and cash equivalents $ 14 $ 14 Other current assets and deferred charges 10 16 Total current assets 24 30 Investments in and advances to consolidated subsidiaries 25,268 22,359 Property, plant, and equipment — net 77 77 Other noncurrent assets 6 8 Total assets $ 25,375 $ 22,474 LIABILITIES AND STOCKHOLDERS’ EQUITY Current liabilities: Accounts payable $ 20 $ 27 Other current liabilities 187 169 Total current liabilities 207 196 Long-term debt 4,438 4,939 Notes payable — affiliates 7,763 8,171 Pension, other postretirement, and other noncurrent liabilities 164 287 Deferred income tax liabilities 3,147 4,238 Contingent liabilities and commitments Equity: Common stock 861 785 Other stockholders’ equity 8,795 3,858 Total stockholders’ equity 9,656 4,643 Total liabilities and stockholders’ equity $ 25,375 $ 22,474 See accompanying notes. The Williams Companies, Inc. Schedule I — Condensed Financial Information of Registrant – (Continued) Statement of Cash Flows (Parent) Years Ended December 31, 2017 2016 2015 (Millions) NET CASH FLOWS PROVIDED (USED) BY OPERATING ACTIVITIES $ (648 ) $ (827 ) $ (1,181 ) FINANCING ACTIVITIES: Proceeds from long-term debt 1,635 2,280 2,097 Payments of long-term debt (2,140 ) (2,155 ) (1,817 ) Changes in notes payable to affiliates (408 ) 9 2,211 Proceeds from issuance of common stock 2,131 9 27 Dividends paid (992 ) (1,261 ) (1,836 ) Other — net (9 ) (6 ) (30 ) Net cash provided (used) by financing activities 217 (1,124 ) 652 INVESTING ACTIVITIES: Capital expenditures (22 ) (13 ) (29 ) Changes in investments in and advances to consolidated subsidiaries 453 1,966 521 Net cash provided (used) by investing activities 431 1,953 492 Increase (decrease) in cash and cash equivalents — 2 (37 ) Cash and cash equivalents at beginning of year 14 12 49 Cash and cash equivalents at end of year $ 14 $ 14 $ 12 See accompanying notes. 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, 2017, 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, 2017, 2016, and 2015 was approximately $1.9 billion , $1.7 billion , and $1.8 billion , respectively.

Schedule II - Valuation and Qua

Schedule II - Valuation and Qualifying Accounts	12 Months Ended
	Dec. 31, 2017
Valuation and Qualifying Accounts [Abstract]
Schedule II - Valuation and Qualifying Accounts [Text Block]	The Williams Companies, Inc. Schedule II — Valuation and Qualifying Accounts Additions Beginning Balance Charged (Credited) To Costs and Expenses Other Deductions Ending Balance (Millions) 2017 Deferred tax asset valuation allowance (1) $ 334 $ (110 ) $ — $ — $ 224 2016 Deferred tax asset valuation allowance (1) 190 144 — — 334 2015 Deferred tax asset valuation allowance (1) 206 (16 ) — — 190 __________ (1) Deducted from related assets.

General, Description of Busin29

General, Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2017
Accounting Policies [Abstract]
Principles of consolidation [Policy Text Block]	Principles of consolidation The consolidated financial statements include the accounts of all entities that we control and our proportionate interest in the accounts of certain ventures in which we own an undivided interest. Our judgment is required to evaluate whether we control an entity. Key areas of that evaluation include: • Determining whether an entity is a VIE; • Determining whether we are the primary beneficiary of a VIE, including evaluating which activities of the VIE most significantly impact its economic performance and the degree of power that we and our related parties have over those activities through our variable interests; • Identifying events that require reconsideration of whether an entity is a VIE and continuously evaluating whether we are a VIE’s primary beneficiary; • Evaluating whether other owners in entities that are not VIEs are able to effectively participate in significant decisions that would be expected to be made in the ordinary course of business such that we do not have the power to control such entities. We apply the equity method of accounting to investments over which we exercise significant influence but do not control.
Equity-method investment basis differences [Policy Text Block]	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 [Policy Text Block]	Use of estimates The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires us 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; • Measurement of regulatory liabilities; • Measurement of deferred income tax assets and liabilities. These estimates are discussed further throughout these notes.
Regulatory Accounting [Policy Text Block]	Regulatory accounting Transco and Northwest Pipeline are regulated by the Federal Energy Regulatory Commission (FERC). Their rates, which are established by the FERC, are designed to recover the costs of providing the regulated services, and their competitive environment makes it probable that such rates can be charged and collected. Therefore, we have determined that it is appropriate under Accounting Standards Codification (ASC) Topic 980, “Regulated Operations,” to account for and report regulatory assets and liabilities related to these operations consistent with the economic effect of the way in which their rates are established. Accounting for these operations that are regulated can differ from the accounting requirements for nonregulated operations. For example, for regulated operations, allowance for funds used during construction (AFUDC) represents the estimated cost of debt and equity funds applicable to utility plant in the process of construction and is capitalized as a cost of property, plant, and equipment because it constitutes an actual cost of construction under established regulatory practices; nonregulated operations are only allowed to capitalize the cost of debt funds related to construction activities, while a component for equity is prohibited. The components of our regulatory assets and liabilities relate to the effects of deferred taxes on equity funds used during construction, asset retirement obligations, fuel cost differentials, levelized incremental depreciation, negative salvage, pension and other postretirement benefits, and rate allowances for deferred income taxes at a historically higher federal income tax rate. In December 2017, the Tax Cuts and Jobs Act was enacted, which, among other things, reduced the federal corporate income tax rate from 35 percent to 21 percent (Tax Reform) (see Note 7 – Provision (Benefit) for Income Taxes ). In accordance with ASC 980-740-25-2, Transco and Northwest Pipeline have recognized regulatory liabilities to reflect the probable return to customers through future rates of the future decrease in income taxes payable associated with Tax Reform. These liabilities represent an obligation to return amounts directly to our customers. While a majority of our customers have entered into tariff rates based on our cost-of-service proceedings and related rate base therein, certain other contracts with customers reflect contractually-based rates that are designed to recover the cost of providing those services, including an allowance for income taxes, with no expected future rate adjustment for the term of those contracts. This relative mix of contracts for services was considered in determining the probable amount to be returned to customers through future rates. The regulatory liabilities were recorded in December 2017 through regulatory charges to operating income totaling $674 million . The timing and actual amount of such return will be subject to future negotiations regarding this matter and many other elements of cost-of-service rate proceedings, including other costs of providing service. Certain of our equity-method investees recorded similar regulatory liabilities, for which our Equity earnings (losses) in the Consolidated Statement of Operations have been reduced by $11 million related to our proportionate share of the associated regulatory charges. Our regulatory assets associated with the effects of deferred taxes on equity funds used during construction were also impacted by Tax Reform and were reduced by $102 million in December 2017 through a charge to Other income (expense) – net below Operating income (loss) in the Consolidated Statement of Operations (see Note 6 – Other Income and Expenses ). This amount, along with the previously described charges for establishing the regulatory liabilities resulting from Tax Reform, is reported within Regulatory charges resulting from Tax Reform within the Consolidated Statement of Cash Flows . Our current and noncurrent regulatory asset and liability balances for the years ended December 31, 2017 and 2016 are as follows: December 31, 2017 2016 (Millions) Current assets reported within Other current assets and deferred charges $ 102 $ 91 Noncurrent assets reported within Regulatory assets, deferred charges, and other 376 387 Total regulated assets $ 478 $ 478 Current liabilities reported within Accrued liabilities $ 18 $ 11 Noncurrent liabilities reported within Regulatory liabilities, deferred income, and other 1,250 498 Total regulated liabilities $ 1,268 $ 509
Cash and cash equivalents [Policy Text Block]	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 [Policy Text Block]	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 [Policy Text Block]	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 net realizable value. The cost of inventories is primarily determined using the average-cost method.
Property, plant, and equipment [Policy Text Block]	Property, plant, and equipment Property, plant, and equipment is initially recorded at cost. We base the carrying value of these assets on estimates, assumptions, and judgments relative to capitalized costs, useful lives, and salvage values. As regulated entities, Northwest Pipeline and Transco provide for depreciation using the straight-line method at FERC-prescribed rates. Depreciation for nonregulated entities is provided primarily on the straight-line method over estimated useful lives, except for certain offshore facilities that apply an accelerated depreciation method. Gains or losses from the ordinary sale or retirement of property, plant, and equipment for regulated pipelines are credited or charged to accumulated depreciation. Other gains or losses are recorded in Other (income) expense – net included in Operating income (loss) in the Consolidated Statement of Operations . Ordinary maintenance and repair costs are generally expensed as incurred. Costs of major renewals and replacements are capitalized as property, plant, and equipment. We record a liability and increase the basis in the underlying asset for the present value of each expected future 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 we expect to recover these amounts in future rates. We measure changes in the liability due to passage of time by applying an interest rate to the liability balance. This amount is recognized as an increase in the carrying amount of the liability and as a corresponding accretion expense included in Operating and maintenance expenses in the Consolidated Statement of Operations , except for regulated entities, for which the liability is offset by a regulatory asset. The regulatory asset is amortized commensurate with our collection of those costs in rates. Measurements of AROs include, as a component of future expected costs, an estimate of the price that a third party would demand, and could expect to receive, for bearing the uncertainties inherent in the obligations, sometimes referred to as a market-risk premium.
Goodwill [Policy Text Block]	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. Generally, the evaluation of goodwill for impairment involves a two-step quantitative test, although under certain circumstances an initial qualitative evaluation may be sufficient to conclude goodwill is not impaired. If a quantitative assessment is performed, 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 estimate of fair value. Effective October 1, 2017, we early adopted Accounting Standards Update (ASU) 2017-04 “Intangibles - Goodwill and Other (Topic 350): Simplifying the Test for Goodwill Impairment” (ASU 2017-04), which removed the computation of the implied fair value of goodwill from the measurement process.
Other intangibles assets [Policy Text Block]	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 [Policy Text Block]	Impairment of property, plant, and equipment, other identifiable intangible assets, and investments We evaluate our property, plant, and equipment and other identifiable intangible assets for impairment when events or changes in circumstances indicate, in our judgment, that the carrying value of such assets may not be recoverable. When an indicator of impairment has occurred, we compare our estimate of undiscounted future cash flows attributable to the assets to the carrying value of the assets to determine whether an impairment has occurred and we may apply a probability-weighted approach to consider the likelihood of different cash flow assumptions and possible outcomes including selling in the near term or holding for the remaining estimated useful life. If an impairment of the carrying value has occurred, we determine the amount of the impairment recognized in the financial statements by estimating the fair value of the assets and recording a loss for the amount that the carrying value exceeds the estimated fair value. This evaluation is performed at the lowest level for which separately identifiable cash flows exist. For assets identified to be disposed of in the future and considered held for sale, we compare the carrying value to the estimated fair value less the cost to sell to determine if recognition of an impairment is required. Until the assets are disposed of, the estimated fair value, which includes estimated cash flows from operations until the assumed date of sale, is recalculated when related events or circumstances change. We evaluate our investments for impairment when events or changes in circumstances indicate, in our judgment, that the carrying value of such investments may have experienced an other-than-temporary decline in value. When evidence of loss in value has occurred, we compare our estimate of fair value of the investment to the carrying value of the investment to determine whether an impairment has occurred. If the estimated fair value is less than the carrying value and we consider the decline in value to be other-than-temporary, the excess of the carrying value over the fair value is recognized in the consolidated financial statements as an impairment charge. Judgments and assumptions are inherent in our estimate of undiscounted future cash flows and an asset’s or investment’s fair value. Additionally, judgment is used to determine the probability of sale with respect to assets considered for disposal.
Deferred income [Policy Text Block]	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 income is reflected within Accrued liabilities and Regulatory liabilities, deferred income, and other on the Consolidated Balance Sheet . (See Note 12 – Accrued Liabilities .) WPZ received an aggregate amount of $240 million in three equal installments as certain milestones of Transco’s Hillabee Expansion Project were met related to an agreement to resolve several matters in relation to the project. (See Note 12 – Accrued Liabilities .) During the third quarter of 2017, WPZ received the final installment and placed the project into service. As a result of placing the project into service, WPZ reclassified the refundable deposits to deferred income and expects to recognize income associated with these receipts over the term of an underlying contract. 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 income and are being amortized into income. 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 [Policy Text Block]	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 [Policy Text Block]	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 13 – Debt, Banking Arrangements, and Leases .)
Treasury stock [Policy Text Block]	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.
Derivative instruments and hedging activities [Policy Text Block]	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 16 – 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 costs in 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 us. For commodity derivatives that are not designated in a hedging relationship, and for which we have not elected the normal purchases and normal sales exception, we report changes in fair value currently in Product sales or Product costs in the Consolidated Statement of Operations . Certain gains and losses on derivative instruments included in the Consolidated Statement of Operations are netted together to a single net gain or loss, while other gains and losses are reported on a gross basis. Gains and losses recorded on a net basis include unrealized gains and losses on all derivatives that are not designated as hedges and for which we have not elected the normal purchases and normal sales exception. Realized gains and losses on derivatives that require physical delivery, as well as natural gas derivatives for NGL processing activities and which are not held for trading purposes nor were entered into as a pre-contemplated buy/sell arrangement, are recorded on a gross basis.
Revenue recognition [Policy Text Block]	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. We market NGLs, crude oil, and natural gas that we purchase from our producer customers as part of the overall service provided to producers. Revenues from marketing activities are recognized when the products have been sold and delivered. Under our keep-whole and percent-of-liquids processing contracts, we retain the rights to all or a portion of the NGLs extracted from the producers’ natural gas stream and recognize revenues when the extracted NGLs are sold and delivered. Our former domestic olefins business produced olefins from purchased or produced feedstock and we recognized revenues when the olefins were sold and delivered. 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 [Policy Text Block]	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 [Policy Text Block]	Employee stock-based awards We recognize compensation expense on employee stock-based awards on a straight-line basis; forfeitures are recognized when they occur. (See Note 15 – Equity-Based Compensation .)
Pension and other postretirement benefits [Policy Text Block]	Pension and other postretirement benefits The funded status of each of the pension and other postretirement benefit plans is recognized separately in the Consolidated Balance Sheet as either an asset or liability. The funded status is the difference between the fair value of plan assets and the plan’s benefit obligation. The plans’ benefit obligations and net periodic benefit costs (credits) are actuarially determined and impacted by various assumptions and estimates. (See Note 9 – Employee Benefit Plans .) The discount rates are determined separately for each of our pension and other postretirement benefit plans based on an approach specific to our plans. The year-end discount rates are determined considering a yield curve comprised of high-quality corporate bonds and the timing of the expected benefit cash flows of each plan. The expected long-term rates of return on plan assets are determined by combining a review of the historical returns within the portfolio, the investment strategy included in the plans’ investment policy statement, and capital market projections for the asset classes in which the portfolio is invested, as well as the weighting of each asset class. Unrecognized actuarial gains and losses and unrecognized prior service costs and credits are deferred and recorded in AOCI or, for Transco and Northwest Pipeline, as a regulatory asset or liability, until amortized as a component of net periodic benefit cost (credit). Unrecognized actuarial gains and losses in excess of 10 percent of the greater of the benefit obligation or the market-related value of plan assets are amortized over the participants’ average remaining future years of service, which is approximately 13 years for our pension plans and approximately 7 years for our other postretirement benefit plans. The expected return on plan assets component of net periodic benefit cost (credit) is calculated using the market-related value of plan assets. For our pension plans, the market-related value of plan assets is equal to the fair value of plan assets adjusted to reflect the amortization of gains or losses associated with the difference between the expected and actual return on plan assets over a 5 -year period. Additionally, the market-related value of assets may be no more than 110 percent or less than 90 percent of the fair value of plan assets at the beginning of the year. The market-related 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 [Policy Text Block]	Income taxes We include the operations of our domestic corporate subsidiaries and income from our subsidiary partnerships in our consolidated federal income tax return and also file tax returns in various foreign and state jurisdictions as required. Deferred income taxes are computed using the liability method and are provided on all temporary differences between the financial basis and the tax basis of our assets and liabilities. Our judgment and income tax assumptions are used to determine the levels, if any, of valuation allowances associated with deferred tax assets.
Earnings (loss) per common share [Policy Text Block]	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 [Policy Text Block]	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.

General, Description of Busin30

General, Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies (Tables)	12 Months Ended
	Dec. 31, 2017
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Regulatory Assets and Liabilities [Table Text Block]	Our current and noncurrent regulatory asset and liability balances for the years ended December 31, 2017 and 2016 are as follows: December 31, 2017 2016 (Millions) Current assets reported within Other current assets and deferred charges $ 102 $ 91 Noncurrent assets reported within Regulatory assets, deferred charges, and other 376 387 Total regulated assets $ 478 $ 478 Current liabilities reported within Accrued liabilities $ 18 $ 11 Noncurrent liabilities reported within Regulatory liabilities, deferred income, and other 1,250 498 Total regulated liabilities $ 1,268 $ 509

Acquisitions and Divestitures (

Acquisitions and Divestitures (Tables)	12 Months Ended
	Dec. 31, 2017
Williams Olefins, L.L.C. [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Results of Operations of Disposal Group [Table Text Block]	The following table presents the results of operations for the Geismar Interest, excluding the gain noted above: Years Ended December 31, 2017 2016 (Millions) Income (loss) before income taxes of the Geismar Interest $ 26 $ 141 Income (loss) before income taxes of the Geismar Interest attributable to The Williams Companies, Inc. 19 85
Canadian Operations [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Results of Operations of Disposal Group [Table Text Block]	The following table presents the results of operations for the Canadian disposal group, excluding the impairment and loss noted above: Years Ended December 31, 2017 2016 (Millions) Income (loss) before income taxes of Canadian disposal group $ — $ (98 ) Income (loss) before income taxes of Canadian disposal group attributable to The Williams Companies, Inc. — (95 )

Variable Interest Entities (Tab

Variable Interest Entities (Tables)	12 Months Ended
	Dec. 31, 2017
Variable Interest Entity Disclosures [Abstract]
Schedule of Variable Interest Entities [Table Text Block]	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, 2017 2016 Classification (Millions) Assets (liabilities): Cash and cash equivalents $ 881 $ 145 Cash and cash equivalents Trade accounts and other receivables – net 972 925 Trade accounts and other receivables Inventories 113 138 Inventories Other current assets 176 205 Other current assets and deferred charges Investments 6,552 6,701 Investments Property, plant, and equipment – net 27,912 28,021 Property, plant, and equipment – net Intangible assets – net 8,790 9,662 Intangible assets – net of accumulated amortization Regulatory assets, deferred charges, and other noncurrent assets 507 467 Regulatory assets, deferred charges, and other Accounts payable (957 ) (589 ) Accounts payable Accrued liabilities including current asset retirement obligations (857 ) (1,122 ) Accrued liabilities Commercial paper — (93 ) Commercial paper Long-term debt due within one year (501 ) (785 ) Long-term debt due within one year Long-term debt (15,996 ) (17,685 ) Long-term debt Deferred income tax liabilities (16 ) (20 ) Deferred income tax liabilities Noncurrent asset retirement obligations (944 ) (798 ) Regulatory liabilities, deferred income, and other Long-term deferred income (1,119 ) (1,048 ) Regulatory liabilities, deferred income, and other Regulatory liabilities and other (1,690 ) (812 ) Regulatory liabilities, deferred income, and other

Investing Activities (Tables)

Investing Activities (Tables)	12 Months Ended
	Dec. 31, 2017
Investments [Abstract]
Impairments [Table Text Block]	Impairment of equity-method investments The following table presents other-than-temporary impairment charges related to certain equity-method investments (see Note 16 – 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
Investments [Table Text Block]	Investments Ownership Interest at December 31, 2017 December 31, 2017 2016 (Millions) Equity-method investments: Appalachia Midstream Investments (1) $ 3,104 $ 2,062 UEOM 62% 1,383 1,448 Discovery 60% 534 572 Caiman II 58% 429 426 OPPL 50% 422 430 Laurel Mountain 69% 309 324 Gulfstream 50% 244 261 DBJV — — 988 Other Various 127 190 $ 6,552 $ 6,701 ___________ (1) Includes equity-method investments in multiple gathering systems in the Marcellus Shale with an approximate average 66 percent interest.
Contributions [Table Text Block]	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, 2017 2016 2015 (Millions) Appalachia Midstream Investments $ 70 $ 28 $ 93 DBJV 32 105 57 Caiman II 24 22 — Discovery 1 — 35 UEOM — — 357 Other 5 22 53 $ 132 $ 177 $ 595
Dividends and distributions [Table Text Block]	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, 2017 2016 2015 (Millions) Appalachia Midstream Investments $ 270 $ 211 $ 219 Discovery 127 141 116 Gulfstream 92 100 88 UEOM 80 92 42 OPPL 68 69 45 Caiman II 49 40 33 DBJV 39 39 33 Laurel Mountain 32 28 31 Other 27 22 26 $ 784 $ 742 $ 633
Summarized Financial Position and Results of Operations of Equity Method Investments [Table Text Block]	Summarized Financial Position and Results of Operations of All Equity-Method Investments December 31, 2017 2016 (Millions) Assets (liabilities): Current assets $ 447 $ 508 Noncurrent assets 9,181 9,695 Current liabilities (295 ) (412 ) Noncurrent liabilities (1,538 ) (1,484 ) Years Ended December 31, 2017 2016 2015 (Millions) Gross revenue $ 1,961 $ 1,883 $ 1,707 Operating income 871 799 690 Net income 806 726 611

Other Income and Expenses (Tabl

Other Income and Expenses (Tables)	12 Months Ended
	Dec. 31, 2017
Other Income and Expenses [Abstract]
Other Income and Expenses [Table Text Block]	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, 2017 2016 2015 (Millions) Williams Partners Loss on sale of Canadian operations (Note 2) $ 4 $ 34 $ — Amortization of regulatory assets associated with asset retirement obligations 33 33 33 Accrual of regulatory liability related to overcollection of certain employee expenses 22 25 20 Project development costs related to Constitution (Note 3) 16 28 — Gains on contract settlements and terminations (15 ) — — Gain on sale of Refinery Grade Propylene Splitter (12 ) — — Net foreign currency exchange (gains) losses (1) — 10 (10 ) Gain on asset retirement — (11 ) — Other Loss on sale of Canadian operations (Note 2) 1 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 2 – Acquisitions and Divestitures ).

Provision (Benefit) for Incom35

Provision (Benefit) for Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2017
Income Tax Expense (Benefit), Continuing Operations [Abstract]
Schedule of Components of Provision (benefit) for income taxes [Table Text Block]	The Provision (benefit) for income taxes includes: Years Ended December 31, 2017 2016 2015 (Millions) Current: Federal $ 15 $ — $ — State 23 2 (7 ) Foreign — (1 ) (55 ) 38 1 (62 ) Deferred: Federal (2,004 ) (6 ) (317 ) State (8 ) 61 (25 ) Foreign — (81 ) 5 (2,012 ) (26 ) (337 ) Provision (benefit) for income taxes $ (1,974 ) $ (25 ) $ (399 )
Provision for income taxes at federal statutory rate [Table Text Block]	Reconciliations from the Provision (benefit) at statutory rate to recorded Provision (benefit) for income taxes are as follows: Years Ended December 31, 2017 2016 2015 (Millions) Provision (benefit) at statutory rate $ 187 $ (131 ) $ (600 ) Increases (decreases) in taxes resulting from: Impact of nontaxable noncontrolling interests (117 ) (22 ) 263 Federal Tax Reform rate change (1,932 ) — — State income taxes (net of federal benefit) (17 ) 3 (21 ) State deferred income tax rate change 26 43 — Foreign operations – net (including tax effect of Canadian Sale) (127 ) 78 8 Translation adjustment of certain unrecognized tax benefits — (1 ) (71 ) Other – net 6 5 22 Provision (benefit) for income taxes $ (1,974 ) $ (25 ) $ (399 )
Deferred tax liabilities and Deferred tax assets [Table Text Block]	Significant components of Deferred income tax liabilities and Deferred income tax assets are as follows: December 31, 2017 2016 (Millions) Deferred income tax liabilities: Investments $ 3,565 $ 5,300 Other 19 29 Total deferred income tax liabilities 3,584 5,329 Deferred income tax assets: Accrued liabilities 53 145 Minimum tax credit 155 139 Foreign tax credit 140 140 Federal loss carryovers — 651 State losses and credits 283 313 Other 30 37 Total deferred income tax assets 661 1,425 Less valuation allowance 224 334 Net deferred income tax assets 437 1,091 Overall net deferred income tax liabilities $ 3,147 $ 4,238
Reconciliation of unrecognized tax benefits [Table Bext Block]	A reconciliation of the beginning and ending amount of unrecognized tax benefits is as follows: 2017 2016 (Millions) Balance at beginning of period $ 50 $ 55 Reductions for tax positions of prior years — (4 ) Changes due to currency translation — (1 ) Balance at end of period $ 50 $ 50

Earnings (Loss) Per Common Sh36

Earnings (Loss) Per Common Share (Tables)	12 Months Ended
	Dec. 31, 2017
Earnings Per Share [Abstract]
Earnings (loss) per common share [Table Text Block]	Years Ended December 31, 2017 2016 2015 (Dollars in millions, except per-share amounts; shares in thousands) Net income (loss) attributable to The Williams Companies, Inc. available to common stockholders for basic and diluted earnings (loss) per common share $ 2,174 $ (424 ) $ (571 ) Basic weighted-average shares 826,177 750,673 749,271 Effect of dilutive securities: Nonvested restricted stock units 1,704 — — Stock options 637 — — Diluted weighted-average shares (1) 828,518 750,673 749,271 Earnings (loss) per common share: Basic $ 2.63 $ (.57 ) $ (.76 ) Diluted $ 2.62 $ (.57 ) $ (.76 ) ________________ (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.

Employee Benefit Plans (Tables)

Employee Benefit Plans (Tables)	12 Months Ended
	Dec. 31, 2017
Retirement Benefits [Abstract]
Changes in benefit obligations and plan assets [Table Text Block]	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 2017 2016 2017 2016 (Millions) Change in benefit obligation: Benefit obligation at beginning of year $ 1,466 $ 1,464 $ 197 $ 202 Service cost 50 54 1 1 Interest cost 59 62 8 8 Plan participants’ contributions — — 3 2 Benefits paid (35 ) (130 ) (14 ) (15 ) Actuarial loss (gain) 40 20 11 (1 ) Settlements (261 ) (4 ) — — Net increase (decrease) in benefit obligation (147 ) 2 9 (5 ) Benefit obligation at end of year 1,319 1,466 206 197 Change in plan assets: Fair value of plan assets at beginning of year 1,254 1,241 208 201 Actual return on plan assets 184 82 25 13 Employer contributions 85 65 5 7 Plan participants’ contributions — — 3 2 Benefits paid (35 ) (130 ) (14 ) (15 ) Settlements (261 ) (4 ) — — Net increase (decrease) in fair value of plan assets (27 ) 13 19 7 Fair value of plan assets at end of year 1,227 1,254 227 208 Funded status — overfunded (underfunded) $ (92 ) $ (212 ) $ 21 $ 11 Accumulated benefit obligation $ 1,294 $ 1,440
Overfunded (underfunded) status of our pension plans and other postretirement benefit plans [Table Text Block]	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, 2017 2016 (Millions) Underfunded pension plans: Current liabilities $ (2 ) $ (2 ) Noncurrent liabilities (90 ) (210 ) Overfunded (underfunded) other postretirement benefit plans: Current liabilities (6 ) (7 ) Noncurrent assets (liabilities) 27 18
Pre-tax amounts not yet recognized in net periodic benefit cost [Table Text Block]	Pre-tax amounts not yet recognized in Net periodic benefit cost (credit) at December 31 are as follows: Pension Benefits Other Postretirement Benefits 2017 2016 2017 2016 (Millions) Amounts included in Accumulated other comprehensive income (loss) : Prior service credit $ — $ — $ — $ 5 Net actuarial loss (375 ) (535 ) (21 ) (18 ) Amounts included in regulatory liabilities associated with Transco and Northwest Pipeline: Prior service credit N/A N/A $ 2 $ 10 Net actuarial gain N/A N/A 14 8
Schedule of Net Benefit Cost (Credit) [Table Text Block]	Net periodic benefit cost (credit) for the years ended December 31 consist of the following: Pension Benefits Other Postretirement Benefits 2017 2016 2015 2017 2016 2015 (Millions) Components of net periodic benefit cost (credit): Service cost $ 50 $ 54 $ 59 $ 1 $ 1 $ 2 Interest cost 59 62 58 8 8 9 Expected return on plan assets (82 ) (85 ) (75 ) (11 ) (12 ) (12 ) Amortization of prior service credit — — — (13 ) (15 ) (17 ) Amortization of net actuarial loss 27 30 42 — — 2 Net actuarial loss from settlements 71 2 2 — — — Reclassification to regulatory liability — — — 3 4 3 Net periodic benefit cost (credit) $ 125 $ 63 $ 86 $ (12 ) $ (14 ) $ (13 )
Other changes in plan assets and benefit obligations recognized in other comprehensive income (loss) [Table Text Block]	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 2017 2016 2015 2017 2016 2015 (Millions) Other changes in plan assets and benefit obligations recognized in Other comprehensive income (loss) : Net actuarial gain (loss) $ 62 $ (23 ) $ 5 $ (3 ) $ — $ 8 Amortization of prior service credit — — — (5 ) (6 ) (6 ) Amortization of net actuarial loss 27 30 42 — — 2 Net actuarial loss from settlements 71 2 2 — — — Other changes in plan assets and benefit obligations recognized in Other comprehensive income (loss) $ 160 $ 9 $ 49 $ (8 ) $ (6 ) $ 4
Schedule of Regulatory Assets / Liabilities [Table Text Block]	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 and liabilities. Amounts recognized in regulatory assets and liabilities for the years ended December 31 consist of the following: 2017 2016 2015 (Millions) Other changes in plan assets and benefit obligations recognized in regulatory (assets) and liabilities: Net actuarial gain (loss) $ 6 $ 2 $ 10 Amortization of prior service credit (8 ) (9 ) (11 )
Pre-tax amounts expected to be amortized in net periodic benefit cost (credit) [Table Text Block]	Pre-tax amounts expected to be amortized in Net periodic benefit cost (credit) in 2018 are as follows: Pension Benefits Other Postretirement Benefits (Millions) Amounts included in Accumulated other comprehensive income (loss) : Prior service credit $ — $ (1 ) Net actuarial loss 23 — Amounts included in regulatory liabilities associated with Transco and Northwest Pipeline: Prior service credit N/A $ (2 ) Net actuarial loss N/A —
Schedule of Assumptions Used [Table Text Block]	The weighted-average assumptions utilized to determine benefit obligations as of December 31 are as follows: Pension Benefits Other Postretirement Benefits 2017 2016 2017 2016 Discount rate 3.66 % 4.17 % 3.71 % 4.27 % Rate of compensation increase 4.93 4.87 N/A N/A The weighted-average assumptions utilized to determine Net periodic benefit cost (credit) for the years ended December 31 are as follows: Pension Benefits Other Postretirement Benefits 2017 2016 2015 2017 2016 2015 Discount rate 4.17 % 4.37 % 3.96 % 4.27 % 4.50 % 4.12 % Expected long-term rate of return on plan assets 6.45 6.85 6.38 5.53 6.11 5.70 Rate of compensation increase 4.87 4.88 4.62 N/A N/A N/A
One percentage point change in assumed health care cost trend rates effects [Table Text Block]	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 5 (5 )
Fair values of plan assets [Table Text Block]	The fair values of our pension plan assets at December 31, 2017 and 2016 by asset class are as follows: 2017 Quoted Prices Significant Significant Total (Millions) Pension assets: Cash management fund $ 17 $ — $ — $ 17 Equity securities: U.S. large cap 62 — — 62 U.S. small cap 54 — — 54 Fixed income securities (1): U.S. Treasury securities 103 — — 103 Government and municipal bonds — 15 — 15 Mortgage and asset-backed securities — 47 — 47 Corporate bonds — 158 — 158 Insurance company investment contracts and other — 5 — 5 $ 236 $ 225 $ — 461 Commingled investment funds measured at net asset value practical expedient (2): Equities — U.S. large cap 265 Equities — International small cap 26 Equities — International emerging markets 41 Equities — International developed markets 110 Fixed income — U.S. long duration 205 Fixed income — Corporate bonds 119 Total assets at fair value at December 31, 2017 $ 1,227 2016 Quoted Prices Significant Significant 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 (2): 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 The fair values of our other postretirement benefits plan assets at December 31, 2017 and 2016 by asset class are as follows: 2017 Quoted Prices Significant Significant Total (Millions) Other postretirement benefit assets: Cash management funds $ 11 $ — $ — $ 11 Equity securities: U.S. large cap 25 — — 25 U.S. small cap 14 — — 14 International developed markets large cap growth — 6 — 6 Fixed income securities (1): U.S. Treasury securities 12 — — 12 Government and municipal bonds — 2 — 2 Mortgage and asset-backed securities — 5 — 5 Corporate bonds — 19 — 19 Mutual fund — Municipal bonds 43 — — 43 $ 105 $ 32 $ — 137 Commingled investment funds measured at net asset value practical expedient (2): Equities — U.S. large cap 31 Equities — International small cap 3 Equities — International emerging markets 5 Equities — International developed markets 13 Fixed income — U.S. long duration 24 Fixed income — Corporate bonds 14 Total assets at fair value at December 31, 2017 $ 227 2016 Quoted Prices Significant Significant 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 (1): 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 (2): 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 ____________ (1) The weighted-average credit quality rating of the fixed income security portfolio is investment grade with a weighted-average duration of approximately 12 years for 2017 and 8 years for 2016 . (2) The stated intents of the funds vary based on each commingled fund’s investment objective. These objectives generally include strategies to replicate or outperform various market indices. Certain standard withdrawal restrictions generally apply, which may include redemption notification period restrictions ranging from 10 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.
Expected benefit payments [Table Text Block]	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) 2018 $ 91 $ 13 2019 90 13 2020 92 14 2021 96 13 2022 96 13 2023-2027 486 60

Property, Plant, and Equipment

Property, Plant, and Equipment (Tables)	12 Months Ended
	Dec. 31, 2017
Property, Plant and Equipment [Abstract]
Property, Plant, and Equipment [Table Text Block]	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, 2017 2016 (Millions) Nonregulated: Natural gas gathering and processing facilities (2) 5 - 40 $ 18,440 $ 19,523 Construction in progress Not applicable 566 412 Other (2) 2 - 45 2,776 3,092 Regulated: Natural gas transmission facilities 1.20 - 6.97 14,460 12,692 Construction in progress Not applicable Not applicable 1,637 1,603 Other 5 - 45 1.35 - 33.33 1,634 1,590 Total property, plant, and equipment, at cost 39,513 38,912 Accumulated depreciation and amortization (11,302 ) (10,484 ) Property, plant, and equipment — net $ 28,211 $ 28,428 __________ (1) Estimated useful life and depreciation rates are presented as of December 31, 2017 . Depreciation rates and estimated useful lives for regulated assets are prescribed by the FERC. (2) The 2016 presentation has been changed to reflect $890 million of right-of-way assets previously presented in Natural gas gathering and processing facilities , now in Other .
Asset Retirement Obligation [Table Text Block]	The following table presents the significant changes to our ARO, of which $946 million and $801 million are included in Regulatory liabilities, deferred income, and other with the remaining current portion in Accrued liabilities at December 31, 2017 and 2016 , respectively. December 31, 2017 2016 (Millions) Beginning balance $ 862 $ 915 Liabilities incurred 33 24 Liabilities settled (16 ) (8 ) Accretion expense (1) 141 69 Revisions (2) (22 ) (138 ) Ending balance $ 998 $ 862 ___________ (1) The increase in accretion expense for 2017 includes an adjustment associated with obligations identified from certain Transco land agreements. (2) Several factors are considered in the annual review process, including inflation rates, current estimates for removal cost, market risk premiums, discount rates, and the estimated remaining useful life of the assets. The 2017 revisions reflect changes in removal cost estimates and decreases in the estimated remaining useful life of certain assets and discount rates used in the annual review process. 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.

Goodwill and Other Intangible39

Goodwill and Other Intangible Assets (Tables)	12 Months Ended
	Dec. 31, 2017
Goodwill and Intangible Assets Disclosure [Abstract]
Schedule of Finite-Lived Intangible Assets [Table Text Block]	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: 2017 2016 Gross Carrying Amount Accumulated Amortization Gross Carrying Amount Accumulated Amortization (Millions) Contractual customer relationships $ 10,027 $ (1,283 ) $ 10,635 $ (1,019 )

Accrued Liabilities (Tables)

Accrued Liabilities (Tables)	12 Months Ended
	Dec. 31, 2017
Accrued Liabilities, Current [Abstract]
Accrued Liabilities [Table Text Block]	December 31, 2017 2016 (Millions) Deferred income $ 361 $ 338 Interest on debt 267 310 Employee costs 202 223 Refundable deposits — 160 Property taxes 63 55 Asset retirement obligations 53 61 Other, including other loss contingencies 221 301 $ 1,167 $ 1,448

Debt, Banking Arrangements, a41

Debt, Banking Arrangements, and Leases (Tables)	12 Months Ended
	Dec. 31, 2017
Debt Disclosure [Abstract]
Schedule of Long-term Debt Instruments [Table Text Block]	Long-Term Debt December 31, 2017 2016 (Millions) Transco: 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 1,000 5.4% Notes due 2041 375 375 4.45% Notes due 2042 400 400 Other financing obligation 231 — Northwest Pipeline: 5.95% Notes due 2017 — 185 6.05% Notes due 2018 250 250 7.125% Debentures due 2025 85 85 4% Notes due 2027 250 — WPZ: 7.25% Notes due 2017 — 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 4.5% Notes due 2023 600 600 4.875% Notes due 2023 — 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 3.75% Notes due 2027 1,450 — 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 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 7.75% Notes due 2031 252 252 8.75% Notes due 2032 445 445 5.75% Notes due 2044 650 650 Various — 7.625% to 10.25% Notes and Debentures due 2019 to 2027 55 55 Credit facility loans 270 775 Debt issuance costs (122 ) (119 ) Net unamortized debt premium (discount) (24 ) 88 Total long-term debt, including current portion 20,935 23,409 Long-term debt due within one year (501 ) (785 ) Long-term debt $ 20,434 $ 22,624
Schedule of Maturities of Long-term Debt [Table Text Block]	The following table presents aggregate minimum maturities of long-term debt, excluding net unamortized debt premium (discount) and debt issuance costs, for each of the next five years: December 31, 2017 (Millions) 2018 $ 502 2019 33 2020 2,123 2021 1,143 2022 2,003
Schedule of Line of Credit Facilities [Table Text Block]	Credit Facilities December 31, 2017 Available Outstanding (Millions) WMB Long-term credit facility $ 1,500 $ 270 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.
Schedule of Future Minimum Rental Payments for Operating Leases [Table Text Block]	The future minimum annual rentals under noncancelable operating leases, are payable as follows: December 31, 2017 (Millions) 2018 $ 43 2019 41 2020 33 2021 33 2022 29 Thereafter 137 Total $ 316

Stockholders' Equity (Tables)

Stockholders' Equity (Tables)	12 Months Ended
	Dec. 31, 2017
Stockholders' Equity Note [Abstract]
Accumulated Other Comprehensive Income (Loss) [Table Text Block]	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, 2016 $ — $ (2 ) $ (337 ) $ (339 ) Other comprehensive income (loss) before reclassifications (6 ) 1 44 39 Amounts reclassified from accumulated other comprehensive income (loss) 4 — 58 62 Other comprehensive income (loss) (2 ) 1 102 101 Balance at December 31, 2017 $ (2 ) $ (1 ) $ (235 ) $ (238 )
Reclassifications Out Of Accumulated Other Comprehensive Income [Table Text Block]	Reclassifications out of AOCI are presented in the following table by component for the year ended December 31, 2017 : Component Reclassifications Classification (Millions) Cash flow hedges: Energy commodity contracts $ 7 Product sales and Product costs Pension and other postretirement benefits: Amortization of prior service cost (credit) included in net periodic benefit cost (credit) (5 ) Note 9 – Employee Benefit Plans Amortization of actuarial (gain) loss and net actuarial loss from settlements included in net periodic benefit cost (credit) 98 Note 9 – Employee Benefit Plans Total before tax 100 Income tax benefit (36 ) Provision (benefit) for income taxes Net of income tax 64 Noncontrolling interest (2 ) Net income (loss) attributable to noncontrolling interests Reclassifications during the period $ 62

Equity-Based Compensation (Tabl

Equity-Based Compensation (Tables) - Williams Companies Incentive Plan [Member]	12 Months Ended
	Dec. 31, 2017
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock Option Rollfoward and related information [Table Text Block]	The following summary reflects stock option activity and related information for the year ended December 31, 2017 : Stock Options Options Weighted- Average Exercise Price Aggregate Intrinsic Value (Millions) (Millions) Outstanding at December 31, 2016 6.2 $ 31.32 Granted 1.0 $ 28.85 Exercised (0.5 ) $ 21.33 Cancelled (0.1 ) $ 36.75 Outstanding at December 31, 2017 6.6 $ 31.53 $ 23 Exercisable at December 31, 2017 5.1 $ 31.85 $ 19
Cash Proceeds Received and Tax Benefit from Share-based Payment Awards [Table Text Block]	The following table summarizes additional information related to stock option activity during each of the last three years: Years Ended December 31, 2017 2016 2015 (Millions) Total intrinsic value of options exercised $ 4 $ 2 $ 37 Tax benefits realized on options exercised $ 1 $ 1 $ 13 Cash received from the exercise of options $ 7 $ 4 $ 20
Stock Options Schedule of Valuation Assumptions [Table Text Block]	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: 2017 2016 2015 Weighted-average grant date fair value of options for our common stock granted during the year, per share $ 6.61 $ 7.90 $ 7.61 Weighted-average assumptions: Dividend yield 4.2 % 3.2 % 4.8 % Volatility 35.1 % 44.7 % 27.8 % Risk-free interest rate 2.1 % 1.2 % 1.8 % Expected life (years) 6.0 6.0 6.0
Nonvested Restricted Stock Unit Rollforward and related information [Table Text Block]	The following summary reflects nonvested restricted stock unit activity and related information for the year ended December 31, 2017 : Restricted Stock Units Outstanding Shares Weighted- Average Fair Value (1) (Millions) Nonvested at December 31, 2016 3.9 $ 35.19 Granted 2.0 $ 29.47 Forfeited (0.8 ) $ 39.21 Vested (0.9 ) $ 38.30 Nonvested at December 31, 2017 4.2 $ 31.02 ______________ (1) Performance-based restricted stock units are valued utilizing a Monte Carlo valuation method using measures of total shareholder return. All other restricted stock units are valued at the grant-date market price. Restricted stock units generally vest after three years .
Other restricted stock unit information [Table Text Block]	Value of Restricted Stock Units 2017 2016 2015 Weighted-average grant date fair value of restricted stock units granted during the year, per share $ 29.47 $ 26.51 $ 40.15 Total fair value of restricted stock units vested during the year ($’s in millions) $ 33 $ 32 $ 42

Fair Value Measurements, Guar44

Fair Value Measurements, Guarantees, and Concentration of Credit Risk (Tables)	12 Months Ended
	Dec. 31, 2017
Fair Value Disclosures [Abstract]
Fair Value Assets and Liabilities Measured On Recurring Basis [Table Text Block]	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, 2017: Measured on a recurring basis: ARO Trust investments $ 135 $ 135 $ 135 $ — $ — Energy derivatives liabilities designated as hedging instruments (3 ) (3 ) (2 ) (1 ) — Energy derivatives liabilities not designated as hedging instruments (3 ) (3 ) — — (3 ) Additional disclosures: Other receivables 7 7 7 — — Long-term debt, including current portion (20,935 ) (23,005 ) — (23,005 ) — Guarantees (43 ) (30 ) — (14 ) (16 ) 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 )
Fair Value Measurements, Nonrecurring [Table Text Block]	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 2017 2016 2015 (Millions) Certain gathering operations (1) Property, plant, and equipment – net and Intangible assets - net of accumulated amortization Williams Partners September 30, 2017 $ 439 $ 1,019 Certain gathering operations (2) Property, plant, and equipment – net and Intangible assets - net of accumulated amortization Williams Partners September 30, 2017 21 115 Certain NGL pipeline (3) Property, plant, and equipment – net Other September 30, 2017 32 68 Certain olefins pipeline project (4) Property, plant, and equipment – net Other June 30, 2017 18 23 Canadian operations (5) Assets held for sale Other June 30, 2016 206 $ 406 Canadian operations (5) Assets held for sale Williams Partners June 30, 2016 924 341 Certain gathering operations (6) 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 Previously capitalized project development costs (7) Property, plant, and equipment – net Williams Partners December 31, 2015 13 $ 94 Previously capitalized project development costs (8) Property, plant, and equipment – net Other December 31, 2015 40 64 Surplus equipment (9) Property, plant, and equipment – net Williams Partners June 30, 2015 17 20 Level 3 fair value measurements of certain assets 1,225 803 178 Other impairments and write-downs (10) 23 70 31 Impairment of certain assets $ 1,248 $ 873 $ 209 Impairments Years Ended December 31, Classification Segment Date of Measurement Fair Value 2017 2016 2015 (Millions) Equity-method investments (11) Investments Williams Partners December 31, 2016 $ 1,295 $ 318 Equity-method investments (12) Investments Williams Partners March 31, 2016 1,294 109 Other equity-method investment Investments Williams Partners March 31, 2016 — 3 Equity-method investments (13) Investments Williams Partners December 31, 2015 4,017 $ 890 Equity-method investments (14) Investments Williams Partners September 30, 2015 1,203 461 Other equity-method investment Investments Williams Partners December 31, 2015 58 8 Impairment of equity-method investments $ 430 $ 1,359 ______________ (1) Relates to certain gathering operations in the Mid-Continent region. During the third quarter of 2017, we received solicitations and engaged in negotiations for the sale of certain of these assets which led to our impairment evaluation. The estimated fair value was determined using an income approach and incorporated market inputs based on ongoing negotiations for a potential sale of a portion of the underlying assets. For the income approach, we utilized a discount rate of 10.2 percent , reflecting an estimated cost of capital and risks associated with the underlying assets. (2) Relates to certain gathering operations in the Marcellus South region resulting from an anticipated decline in future volumes following a third-quarter 2017 shut-in by the primary producer. The estimated fair value was determined by the income approach utilizing a discount rate of 11.1 percent , reflecting an estimated cost of capital and risks associated with the underlying assets. (3) Relates to an NGL pipeline near the Houston Ship Channel region which we anticipate will be underutilized for the foreseeable future. The estimated fair value was primarily determined by using a market approach based on our analysis of observable inputs in the principal market. (4) Relates primarily to project development costs associated with an olefins pipeline project in the Gulf Coast region, the likelihood of completion of which is now considered remote. The estimated fair value of the remaining pipe and equipment considered a market approach based on our analysis of observable inputs in the principal market, as well as an estimate of replacement cost. (5) 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 2 – Acquisitions and Divestitures ). (6) 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. (7) 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. (8) 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. (9) 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. (10) Reflects multiple individually insignificant impairments and write-downs of other certain assets that may no longer be in use or are surplus in nature for which the fair value was determined to be lower than the carrying value. (11) Relates to Williams Partners’ previously held interest in Ranch Westex and multiple Appalachia Midstream Investments currently held. The historical carrying value of these equity-method investments was initially recorded based on estimated fair value during the third quarter of 2014 in conjunction with the acquisition of ACMP. We estimated the fair value of these Appalachia Midstream Investments using an income approach based on expected future cash flows and appropriate discount rates. The determination of estimated future cash flows involved significant assumptions regarding gathering volumes, rates, and related capital spending. The discount rate utilized for the Appalachia Midstream Investments evaluation was 10.2 percent and reflected an estimated cost of capital as impacted by market conditions and risks associated with the underlying businesses. In addition to utilizing an income approach, we also considered a market approach for certain Appalachia Midstream Investments and Ranch Westex based on an agreement reached in February 2017 to exchange our interests in DBJV and Ranch Westex for additional interests in certain Appalachia Midstream Investments and cash. (See Note 5 – Investing Activities ). (12) Relates to Williams Partners’ previously held interest in DBJV and currently held equity-method investment in Laurel Mountain. Our carrying values in these equity-method investments had been written down to fair value at December 31, 2015. Our first-quarter 2016 analysis reflected higher discount rates for both of these equity-method investments, along with lower natural gas prices for Laurel Mountain. We estimated the fair value of these equity-method investments using an income approach based on expected future cash flows and appropriate discount rates. The determination of estimated future cash flows involved significant assumptions regarding gathering volumes and related capital spending. Discount rates utilized ranged from 13.0 percent to 13.3 percent and reflected increases in the estimated cost of capital, revised estimates of expected future cash flows, and risks associated with the underlying businesses. (13) Relates to Williams Partners’ previously held interest in DBJV, as well as equity-method investments in certain of the Appalachia Midstream Investments, UEOM, and Laurel Mountain, all of which are currently held. We estimated the fair value of these equity-method investments using an income approach based on expected future cash flows and appropriate discount rates. The determination of estimated future cash flows involved significant assumptions regarding gathering volumes and related capital spending. Discount rates utilized ranged from 10.8 percent to 14.4 percent and reflected further fourth-quarter 2015 increases in the estimated cost of capital, revised estimates of expected future cash flows, and risks associated with the underlying businesses. (14) Relates to Williams Partners’ previously held interest in DBJV and certain of the Appalachia Midstream Investments currently held. The historical carrying value of these equity-method investments was initially recorded based on estimated fair value during the third quarter of 2014 in conjunction with the acquisition of ACMP. We estimated the fair value of these equity-method investments using an income approach based on expected future cash flows and appropriate discount rates. The determination of estimated future cash flows involved significant assumptions regarding gathering volumes and related capital spending. Discount rates utilized were 11.8 percent and 8.8 percent for DBJV and certain of the Appalachia Midstream Investments, respectively, and reflected an estimated cost of capital as impacted by market conditions, and risks associated with the underlying businesses.
Concentration of receivables, net of allowances, by product or service [Table Text Block]	Trade accounts and other receivables The following table summarizes concentration of receivables, net of allowances: December 31, 2017 2016 (Millions) NGLs, natural gas, and related products and services $ 760 $ 736 Transportation of natural gas and related products 212 187 Other 4 15 Total $ 976 $ 938

Segment Disclosures (Tables)

Segment Disclosures (Tables)	12 Months Ended
	Dec. 31, 2017
Segment Reporting [Abstract]
Schedule of Revenue from External Customers and Long-Lived Assets, by Geographical Areas [Table Text Block]	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: 2017 $ 8,030 $ 1 $ 8,031 2016 7,425 74 7,499 2015 7,247 113 7,360 Long-lived assets: 2017 $ 37,002 $ — $ 37,002 2016 38,091 — 38,091 2015 38,016 1,580 39,596 Long-lived assets are comprised of property, plant, and equipment, goodwill, and other intangible assets.
Reconciliation of revenue from segment to consolidated [Table Text Block]	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) 2017 Segment revenues: Service revenues External $ 5,291 $ 21 $ — $ 5,312 Internal 1 11 (12 ) — Total service revenues 5,292 32 (12 ) 5,312 Product sales External 2,718 1 — 2,719 Internal — — — — Total product sales 2,718 1 — 2,719 Total revenues $ 8,010 $ 33 $ (12 ) $ 8,031 Other financial information: Additions to long-lived assets $ 2,792 $ 22 $ — $ 2,814 Proportional Modified EBITDA of equity-method investments 795 — — 795 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
Reconciliation of Modified EBITDA to Net income (loss) [Table Text Block]	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, 2017 2016 2015 (Millions) Modified EBITDA by segment: Williams Partners $ 3,616 $ 3,864 $ 4,003 Other (150 ) (542 ) (112 ) 3,466 3,322 3,891 Accretion expense associated with asset retirement obligations for nonregulated operations (33 ) (31 ) (28 ) Depreciation and amortization expenses (1,736 ) (1,763 ) (1,738 ) Impairment of goodwill — — (1,098 ) Equity earnings (losses) 434 397 335 Impairment of equity-method investments — (430 ) (1,359 ) Other investing income (loss) – net 282 63 27 Proportional Modified EBITDA of equity-method investments (795 ) (754 ) (699 ) Interest expense (1,083 ) (1,179 ) (1,044 ) (Provision) benefit for income taxes 1,974 25 399 Net income (loss) $ 2,509 $ (350 ) $ (1,314 )
Total assets and equity method investments by reporting segment [Table Text Block]	The following table reflects Total assets and Equity-method investments by reportable segments: Total Assets Equity-Method Investments December 31, 2017 December 31, 2016 December 31, 2017 December 31, 2016 (Millions) Williams Partners $ 45,903 $ 46,265 $ 6,552 $ 6,701 Other 589 685 — — Eliminations (140 ) (115 ) — — Total $ 46,352 $ 46,835 $ 6,552 $ 6,701

Schedule I - Condensed Financ46

Schedule I - Condensed Financial Information of Registrant (Tables)	12 Months Ended
	Dec. 31, 2017
Condensed Financial Information of Parent Company Only Disclosure [Abstract]
Statement of Comprehensive Income (Loss) (Parent) [Table Text Block]	The Williams Companies, Inc. Schedule I — Condensed Financial Information of Registrant Statement of Comprehensive Income (Loss) (Parent) Years Ended December 31, 2017 2016 2015 (Millions, except per-share amounts) Equity in earnings of consolidated subsidiaries $ 898 $ 522 $ 232 Interest incurred — external (261 ) (268 ) (255 ) Interest incurred — affiliate (413 ) (568 ) (828 ) Interest income — affiliate — — 6 Other income (expense) — net (23 ) (53 ) (75 ) Income (loss) before income taxes 201 (367 ) (920 ) Provision (benefit) for income taxes (1,973 ) 57 (349 ) Net income (loss) $ 2,174 $ (424 ) $ (571 ) Basic earnings (loss) per common share: Net income (loss) $ 2.63 $ (.57 ) $ (.76 ) Weighted-average shares (thousands) 826,177 750,673 749,271 Diluted earnings (loss) per common share: Net income (loss) $ 2.62 $ (.57 ) $ (.76 ) Weighted-average shares (thousands) 828,518 750,673 749,271 Other comprehensive income (loss): Equity in other comprehensive income (loss) of consolidated subsidiaries $ (2 ) $ 171 $ (204 ) Other comprehensive income (loss) attributable to The Williams Companies, Inc. 102 1 33 Other comprehensive income (loss) 100 172 (171 ) Less: Other comprehensive income (loss) attributable to noncontrolling interests (1 ) 69 (70 ) Comprehensive income (loss) attributable to The Williams Companies, Inc. $ 2,275 $ (321 ) $ (672 ) See accompanying notes.
Balance Sheet (Parent) [Table Text Block]	The Williams Companies, Inc. Schedule I — Condensed Financial Information of Registrant – (Continued) Balance Sheet (Parent) December 31, 2017 2016 (Millions) ASSETS Current assets: Cash and cash equivalents $ 14 $ 14 Other current assets and deferred charges 10 16 Total current assets 24 30 Investments in and advances to consolidated subsidiaries 25,268 22,359 Property, plant, and equipment — net 77 77 Other noncurrent assets 6 8 Total assets $ 25,375 $ 22,474 LIABILITIES AND STOCKHOLDERS’ EQUITY Current liabilities: Accounts payable $ 20 $ 27 Other current liabilities 187 169 Total current liabilities 207 196 Long-term debt 4,438 4,939 Notes payable — affiliates 7,763 8,171 Pension, other postretirement, and other noncurrent liabilities 164 287 Deferred income tax liabilities 3,147 4,238 Contingent liabilities and commitments Equity: Common stock 861 785 Other stockholders’ equity 8,795 3,858 Total stockholders’ equity 9,656 4,643 Total liabilities and stockholders’ equity $ 25,375 $ 22,474 See accompanying notes.
Statement of Cash Flows (Parent) [Table Text Block]	The Williams Companies, Inc. Schedule I — Condensed Financial Information of Registrant – (Continued) Statement of Cash Flows (Parent) Years Ended December 31, 2017 2016 2015 (Millions) NET CASH FLOWS PROVIDED (USED) BY OPERATING ACTIVITIES $ (648 ) $ (827 ) $ (1,181 ) FINANCING ACTIVITIES: Proceeds from long-term debt 1,635 2,280 2,097 Payments of long-term debt (2,140 ) (2,155 ) (1,817 ) Changes in notes payable to affiliates (408 ) 9 2,211 Proceeds from issuance of common stock 2,131 9 27 Dividends paid (992 ) (1,261 ) (1,836 ) Other — net (9 ) (6 ) (30 ) Net cash provided (used) by financing activities 217 (1,124 ) 652 INVESTING ACTIVITIES: Capital expenditures (22 ) (13 ) (29 ) Changes in investments in and advances to consolidated subsidiaries 453 1,966 521 Net cash provided (used) by investing activities 431 1,953 492 Increase (decrease) in cash and cash equivalents — 2 (37 ) Cash and cash equivalents at beginning of year 14 12 49 Cash and cash equivalents at end of year $ 14 $ 14 $ 12 See accompanying notes.

General, Description of Busin47

General, Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies (Details) - USD ($) $ / shares in Units, $ in Millions

Feb. 10, 2017

Jan. 09, 2017

Sep. 28, 2015

Feb. 03, 2017

Jan. 31, 2017

May 31, 2016

Feb. 29, 2016

Nov. 30, 2015

Jun. 30, 2015

Dec. 31, 2017

Dec. 31, 2016

Dec. 31, 2015

Jan. 01, 2018

Jan. 01, 2017

Basis Of Presentation [Abstract]

Changes in ownership of consolidated subsidiaries, net

$ (910)

$ (6)

$ 94

Income Tax Effects Allocated Directly to Equity, Other

910

Difference between Revenue Guidance in Effect before and after Topic 606 [Member]

Subsidiary of Limited Liability Company or Limited Partnership [Line Items]

Revenue from Contract with Customer, Excluding Assessed Tax

350

Cost of Goods and Services Sold

350

WPZ Merger Agreement [Member]

General and Description Of Business [Abstract]

Gains on contract settlements and terminations

$ 428

Maximum Reduction Of Quarterly Incentive Distributions

$ 209

Basis Of Presentation [Abstract]

Reduction in incentive distribution rights payment

$ 10

$ 209

$ 209

Financial Repositioning [Member]

Basis Of Presentation [Abstract]

Sale Of Stock Number Of Shares Issued In Transaction

277,000

59,000,000

289,000,000

Payments to Acquire Limited Partnership Interests

$ 56

$ 10

Sale of Stock, Price Per Share

$ 36.08586

Noncontrolling Interest [Member]

Basis Of Presentation [Abstract]

Changes in ownership of consolidated subsidiaries, net

(2,407)

(18)

254

Capital in excess of par value [Member]

Basis Of Presentation [Abstract]

Changes in ownership of consolidated subsidiaries, net

$ 1,497

$ 12

$ (160)

Gulfstream Natural Gas System, L.L.C.[Member]

General and Description Of Business [Abstract]

Equity Method Investment, Ownership Percentage

50.00%

Utica East Ohio Midstream, LLC [Member]

General and Description Of Business [Abstract]

Equity Method Investment, Ownership Percentage

62.00%

Delaware Basin Gas Gathering System [Member]

General and Description Of Business [Abstract]

Equity Method Investment, Ownership Percentage

0.00%

50.00%

Laurel Mountain Midstream, LLC [Member]

General and Description Of Business [Abstract]

Equity Method Investment, Ownership Percentage

69.00%

Caiman Energy II [Member]

General and Description Of Business [Abstract]

Equity Method Investment, Ownership Percentage

58.00%

Discovery Producer Services LLC [Member]

General and Description Of Business [Abstract]

Equity Method Investment, Ownership Percentage

60.00%

Overland Pass Pipeline Company LLC [Member]

General and Description Of Business [Abstract]

Equity Method Investment, Ownership Percentage

50.00%

Williams Partners L.P. [Member] | Financial Repositioning [Member]

Basis Of Presentation [Abstract]

Master limited partnership, general partner ownership percentage

2.00%

Williams Partners L.P. [Member] | General and Limited Partner [Member]

General and Description Of Business [Abstract]

Master limited partnership ownership percentage

74.00%

60.00%

Variable Interest Entity Ownership Percentage

74.00%

Williams Partners [Member]

Subsidiary of Limited Liability Company or Limited Partnership [Line Items]

Goodwill

$ 47

$ 47

$ 47

General and Description Of Business [Abstract]

Number Of Interstate Natural Gas Pipelines

2

Williams Partners [Member] | Dividend Reinvestment Program [Member]

Basis Of Presentation [Abstract]

Sale Of Stock Number Of Shares Issued In Transaction

1,606,448

Sale of Stock, Consideration Received on Transaction

$ 61

Williams Partners [Member] | Gulfstream Natural Gas System, L.L.C.[Member]

General and Description Of Business [Abstract]

Equity Method Investment, Ownership Percentage

50.00%

Williams Partners [Member] | Utica East Ohio Midstream, LLC [Member]

General and Description Of Business [Abstract]

Equity Method Investment, Ownership Percentage

62.00%

Basis Of Presentation [Abstract]

Reduction in incentive distribution rights payment

$ 2

Williams Partners [Member] | Delaware Basin Gas Gathering System [Member]

General and Description Of Business [Abstract]

Equity Method Investment, Ownership Percentage

50.00%

Williams Partners [Member] | Laurel Mountain Midstream, LLC [Member]

General and Description Of Business [Abstract]

Equity Method Investment, Ownership Percentage

69.00%

Williams Partners [Member] | Caiman Energy II [Member]

General and Description Of Business [Abstract]

Equity Method Investment, Ownership Percentage

58.00%

Williams Partners [Member] | Discovery Producer Services LLC [Member]

General and Description Of Business [Abstract]

Equity Method Investment, Ownership Percentage

60.00%

Williams Partners [Member] | Overland Pass Pipeline Company LLC [Member]

General and Description Of Business [Abstract]

Equity Method Investment, Ownership Percentage

50.00%

Williams Partners [Member] | Appalachia Midstream Services, LLC [Member]

General and Description Of Business [Abstract]

Equity Method Investment, Ownership Percentage

66.00%

Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest

66.00%

Williams Partners [Member] | Constitution Pipeline Company LLC [Member]

General and Description Of Business [Abstract]

Variable Interest Entity Ownership Percentage

41.00%

Accounting Standards Update 2016-09 [Member]

Subsidiary of Limited Liability Company or Limited Partnership [Line Items]

New Accounting Pronouncement or Change in Accounting Principle, Cumulative Effect of Change on Equity or Net Assets

$ 37

Accounting Standards Update 2014-09 [Member]

Subsidiary of Limited Liability Company or Limited Partnership [Line Items]

New Accounting Pronouncement or Change in Accounting Principle, Cumulative Effect of Change on Equity or Net Assets

$ 255

Summary of Significant Accounti

Summary of Significant Accounting Policies (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Regulatory Assets and Liabilities [Line Items]
Regulatory Charges In Operating Expense Resulting From Tax Reform	$ 674	$ 0	$ 0
Regulatory Charges Resulting From Tax Reform	776	0	$ 0
Regulatory Assets and Liabilities Disclosure [Abstract]
Regulatory Assets, Current	102	91
Regulatory Assets, Noncurrent	376	387
Total regulatory assets	478	478
Regulatory Liabilities, Current	18	11
Regulatory Liabilities, Noncurrent	1,250	498
Total regulatory liabilities	$ 1,268	509
Interest Capitalized [Abstract]
Minimum period of construction for capitalization of interest	3 months
Minimum total project cost for capitalization of interest	$ 1
Retirement Benefits, Description [Abstract]
Threshold For Amortization Of Unrecognized Actuarial Gains Losses	10.00%
Pension Benefits [Member]
Retirement Benefits, Description [Abstract]
Approximate Amortization Period Of Net Actuarial Gain Loss	13 years
Amortization Period Of Difference Between Expected And Actual Return On Plan Assets	5 years
Other Postretirement Benefits [Member]
Retirement Benefits, Description [Abstract]
Approximate Amortization Period Of Net Actuarial Gain Loss	7 years
Maximum [Member]
Regulatory Assets and Liabilities [Line Items]
Effective Income Tax Rate Reconciliation, Change in Enacted Tax Rate, Percent	35.00%
Maximum [Member] | Pension Benefits [Member]
Retirement Benefits, Description [Abstract]
Threshold For Market Related Value	110.00%
Minimum [Member]
Regulatory Assets and Liabilities [Line Items]
Effective Income Tax Rate Reconciliation, Change in Enacted Tax Rate, Percent	21.00%
Minimum [Member] | Pension Benefits [Member]
Retirement Benefits, Description [Abstract]
Threshold For Market Related Value	90.00%
Nonoperating Income (Expense) [Member]
Regulatory Assets and Liabilities [Line Items]
Regulatory Charges Resulting From Tax Reform	$ 11
Other Nonoperating Income (Expense) [Member]
Regulatory Assets and Liabilities [Line Items]
Regulatory Charges Resulting From Tax Reform	$ 102
Contracts in Barnett Shale and Mid-Continent regions [Member]
Regulatory Assets and Liabilities [Line Items]
Deferred Revenue, Additions		$ 820

General, Description of Busin49

General, Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies Deferred Revenue Arrangement, by Type [Table] (Details) - USD ($) $ in Millions	1 Months Ended	12 Months Ended
	Oct. 31, 2016	Dec. 31, 2017	Dec. 31, 2016
Hillabee Expansion Project [Member]
Deferred Revenue Arrangement [Line Items]
Deferred Revenue, Additions		$ 240
Contracts in Barnett Shale and Mid-Continent regions [Member]
Deferred Revenue Arrangement [Line Items]
Deferred Revenue, Additions			$ 820
Newly constructed assets [Member]
Deferred Revenue Arrangement [Line Items]
Deferred Revenue, Additions	$ 104
Maximum [Member]
Deferred Revenue Arrangement [Line Items]
Duration Of Period For Deferred Revenue Recognition		25 years
Minimum [Member]
Deferred Revenue Arrangement [Line Items]
Duration Of Period For Deferred Revenue Recognition		1 year

Acquisitions (Details)

Acquisitions (Details) $ in Millions	1 Months Ended		3 Months Ended	12 Months Ended
	Jun. 30, 2015USD ($)	May 31, 2015USD ($)	Sep. 30, 2015USD ($)	Dec. 31, 2017USD ($)	Dec. 31, 2016USD ($)	Dec. 31, 2015USD ($)
Equity Method Investments and Joint Ventures [Abstract]
Payments to Acquire Equity Method Investments				$ 132	$ 177	$ 595
Utica East Ohio Midstream, LLC [Member]
Equity Method Investments and Joint Ventures [Abstract]
Equity Method Investment, Ownership Percentage				62.00%
Payments to Acquire Equity Method Investments				$ 0	$ 0	$ 357
Utica East Ohio Midstream, LLC [Member] | Williams Partners [Member]
Equity Method Investments and Joint Ventures [Abstract]
Equity Method Investment, Ownership Percentage				62.00%
Payments to Acquire Equity Method Investments	$ 357
Reduction in incentive distribution rights payment	$ 2
Eagle Ford Gathering System [Member]
Business Acquisition, Purchase Price Allocation [Abstract]
Other intangible assets		$ 32
Eagle Ford Gathering System [Member] | Williams Partners [Member]
Business Acquisition [Line Items]
Number Of Miles Of Pipeline Acquired		140
Payments to Acquire Businesses, Gross		$ 112
Business Combination, Provisional Information, Initial Accounting Incomplete, Adjustment, Property, Plant, and Equipment			$ 20
Business Combination, Provisional Information, Initial Accounting Incomplete, Adjustment, Intangibles			$ (20)
Business Acquisition, Purchase Price Allocation [Abstract]
Property, plant, and equipment		$ 80
Additional Investment [Member] | Utica East Ohio Midstream, LLC [Member]
Equity Method Investments and Joint Ventures [Abstract]
Equity Method Investment, Ownership Percentage	13.00%

Divestitures (Details)

Divestitures (Details) - USD ($) $ in Millions		Jul. 06, 2017	Sep. 30, 2017	Jun. 30, 2016	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Oct. 26, 2017
Income (Loss) from Individually Significant Component Disposed of, Attributable to Parent, before Income Tax [Abstract]
Gain (Loss) on Disposition of Business					$ 1,095	$ 0	$ 0
Williams Olefins, L.L.C. [Member]
Income Statement and Additional Disclosures by Disposal Groups [Line Items]
Disposal Group, Consideration		$ 2,084						$ 12
Income (Loss) from Individually Significant Component Disposed of, Attributable to Parent, before Income Tax [Abstract]
Gain (Loss) on Disposition of Business			$ 1,095
Williams Olefins, L.L.C. [Member] | Disposal Group, Not Discontinued Operations [Member]
Income (Loss) from Individually Significant Component Disposed of, Attributable to Parent, before Income Tax [Abstract]
Income (Loss) before Income Taxes of Disposal Group					26	141
Income (Loss) before Income Taxes of Disposal Group Attributable to the Williams Companies, Inc.					19	85
Canadian Operations [Member] | Impairment Of Certain Assets [Member] | Fair Value, Measurements, Nonrecurring [Member] | Level 3 [Member] | Williams Partners [Member]
Income Statement and Additional Disclosures by Disposal Groups [Line Items]
Disposal Group, Not Discontinued Operation, Loss (Gain) on Write-down	[1]			$ 341
Canadian Operations [Member] | Impairment Of Certain Assets [Member] | Fair Value, Measurements, Nonrecurring [Member] | Level 3 [Member] | Corporate and Other [Member]
Income Statement and Additional Disclosures by Disposal Groups [Line Items]
Disposal Group, Not Discontinued Operation, Loss (Gain) on Write-down	[1]			406
Canadian Operations [Member] | Disposal Group, Not Discontinued Operations [Member]
Income Statement and Additional Disclosures by Disposal Groups [Line Items]
Disposal Group, Consideration						1,020
Divested cash of disposal group						31
Reduction in incentive distribution rights payment						150
Income (Loss) from Individually Significant Component Disposed of, Attributable to Parent, before Income Tax [Abstract]
Income (Loss) before Income Taxes of Disposal Group					0	(98)
Income (Loss) before Income Taxes of Disposal Group Attributable to the Williams Companies, Inc.					0	(95)
Canadian Operations [Member] | Disposal Group, Not Discontinued Operations [Member] | Other income (expense) - net [Member]
Income Statement and Additional Disclosures by Disposal Groups [Line Items]
Loss on sale of Canadian operations (Note 2)						66
Gain (Loss) on Foreign Currency Derivative Instruments Not Designated as Hedging Instruments						15
Canadian Operations [Member] | Disposal Group, Not Discontinued Operations [Member] | Other income (expense) - net [Member] | Williams Partners [Member]
Income Statement and Additional Disclosures by Disposal Groups [Line Items]
Loss on sale of Canadian operations (Note 2)					4	34	0
Canadian Operations [Member] | Disposal Group, Not Discontinued Operations [Member] | Other income (expense) - net [Member] | Corporate and Other [Member]
Income Statement and Additional Disclosures by Disposal Groups [Line Items]
Loss on sale of Canadian operations (Note 2)					$ 1	$ 32	$ 0
Canadian Operations [Member] | Disposal Group, Not Discontinued Operations [Member] | Impairment Of Certain Assets [Member] | Fair Value, Measurements, Nonrecurring [Member] | Level 3 [Member]
Income Statement and Additional Disclosures by Disposal Groups [Line Items]
Disposal Group, Not Discontinued Operation, Loss (Gain) on Write-down				$ 747
Geismar [Member] | NGL And Petchem Services [Member]
Income Statement and Additional Disclosures by Disposal Groups [Line Items]
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest					88.50%
Williams Partners L.P. [Member] | Variable Interest Term Loan due 2018 [Member]
Income (Loss) from Individually Significant Component Disposed of, Attributable to Parent, before Income Tax [Abstract]
Extinguishment of Debt, Amount		$ 850
[1]	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 2 – Acquisitions and Divestitures).

Variable Interest Entities (Det

Variable Interest Entities (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2015	Dec. 31, 2016
Variable Interest Entity, Primary Beneficiary [Member] | Cash and cash equivalents [Member]
Variable Interest Entity, Consolidated, Carrying Amount, Assets and Liabilities, Net [Abstract]
Variable Interest Entity, Consolidated, Carrying Amount, Assets	$ 881		$ 145
Variable Interest Entity, Primary Beneficiary [Member] | Accounts receivable [Member]
Variable Interest Entity, Consolidated, Carrying Amount, Assets and Liabilities, Net [Abstract]
Variable Interest Entity, Consolidated, Carrying Amount, Assets	972		925
Variable Interest Entity, Primary Beneficiary [Member] | Inventories [Member]
Variable Interest Entity, Consolidated, Carrying Amount, Assets and Liabilities, Net [Abstract]
Variable Interest Entity, Consolidated, Carrying Amount, Assets	113		138
Variable Interest Entity, Primary Beneficiary [Member] | Other current assets [Member]
Variable Interest Entity, Consolidated, Carrying Amount, Assets and Liabilities, Net [Abstract]
Variable Interest Entity, Consolidated, Carrying Amount, Assets	176		205
Variable Interest Entity, Primary Beneficiary [Member] | Investments [Member]
Variable Interest Entity, Consolidated, Carrying Amount, Assets and Liabilities, Net [Abstract]
Variable Interest Entity, Consolidated, Carrying Amount, Assets	6,552		6,701
Variable Interest Entity, Primary Beneficiary [Member] | Property, plant, and equipment, net [Member]
Variable Interest Entity, Consolidated, Carrying Amount, Assets and Liabilities, Net [Abstract]
Variable Interest Entity, Consolidated, Carrying Amount, Assets	27,912		28,021
Variable Interest Entity, Primary Beneficiary [Member] | Intangible Assets [Member]
Variable Interest Entity, Consolidated, Carrying Amount, Assets and Liabilities, Net [Abstract]
Variable Interest Entity, Consolidated, Carrying Amount, Assets	8,790		9,662
Variable Interest Entity, Primary Beneficiary [Member] | Regulatory assets, deferred charges, and other noncurrent assets [Member]
Variable Interest Entity, Consolidated, Carrying Amount, Assets and Liabilities, Net [Abstract]
Variable Interest Entity, Consolidated, Carrying Amount, Assets	507		467
Variable Interest Entity, Primary Beneficiary [Member] | Accounts payable [Member]
Variable Interest Entity, Consolidated, Carrying Amount, Assets and Liabilities, Net [Abstract]
Variable Interest Entity, Consolidated, Carrying Amount, Liabilities	(957)		(589)
Variable Interest Entity, Primary Beneficiary [Member] | Accrued liabilities [Member]
Variable Interest Entity, Consolidated, Carrying Amount, Assets and Liabilities, Net [Abstract]
Variable Interest Entity, Consolidated, Carrying Amount, Liabilities	(857)		(1,122)
Variable Interest Entity, Primary Beneficiary [Member] | Commercial Paper [Member]
Variable Interest Entity, Consolidated, Carrying Amount, Assets and Liabilities, Net [Abstract]
Variable Interest Entity, Consolidated, Carrying Amount, Liabilities	0		(93)
Variable Interest Entity, Primary Beneficiary [Member] | Long-term debt due within one year [Member]
Variable Interest Entity, Consolidated, Carrying Amount, Assets and Liabilities, Net [Abstract]
Variable Interest Entity, Consolidated, Carrying Amount, Liabilities	(501)		(785)
Variable Interest Entity, Primary Beneficiary [Member] | Long-term Debt [Member]
Variable Interest Entity, Consolidated, Carrying Amount, Assets and Liabilities, Net [Abstract]
Variable Interest Entity, Consolidated, Carrying Amount, Liabilities	(15,996)		(17,685)
Variable Interest Entity, Primary Beneficiary [Member] | Deferred Income Tax Liabilities [Member]
Variable Interest Entity, Consolidated, Carrying Amount, Assets and Liabilities, Net [Abstract]
Variable Interest Entity, Consolidated, Carrying Amount, Liabilities	(16)		(20)
Variable Interest Entity, Primary Beneficiary [Member] | Noncurrent asset retirement obligations [Member]
Variable Interest Entity, Consolidated, Carrying Amount, Assets and Liabilities, Net [Abstract]
Variable Interest Entity, Consolidated, Carrying Amount, Liabilities	(944)		(798)
Variable Interest Entity, Primary Beneficiary [Member] | Deferred Revenue Noncurrent [Member]
Variable Interest Entity, Consolidated, Carrying Amount, Assets and Liabilities, Net [Abstract]
Variable Interest Entity, Consolidated, Carrying Amount, Liabilities	(1,119)		(1,048)
Variable Interest Entity, Primary Beneficiary [Member] | Regulatory liabilities, deferred income, and other noncurrent liabilities [Member]
Variable Interest Entity, Consolidated, Carrying Amount, Assets and Liabilities, Net [Abstract]
Variable Interest Entity, Consolidated, Carrying Amount, Liabilities	$ (1,690)		$ (812)
Variable Interest Entity, Primary Beneficiary [Member] | Gulfstar One [Member]
Variable Interest Entity [Line Items]
Variable Interest Entity Ownership Percentage	51.00%
Variable Interest Entity, Primary Beneficiary [Member] | Constitution Pipeline Company Llc [Member]
Variable Interest Entity [Line Items]
Variable Interest Entity Ownership Percentage	41.00%
Variable Interest Entity, Primary Beneficiary [Member] | Constitution Pipeline Company Llc [Member] | Property, plant, and equipment, net [Member]
Variable Interest Entity [Line Items]
Capitalized project development costs, Cumulative	$ 381
Variable Interest Entity, Primary Beneficiary [Member] | Constitution Pipeline Company Llc [Member] | Estimated Remaining Construction Costs For Variable Interest Entity [Member]
Variable Interest Entity [Line Items]
Estimated remaining construction costs	$ 740
Variable Interest Entity, Primary Beneficiary [Member] | Cardinal Gas Services LLC [Member]
Variable Interest Entity [Line Items]
Variable Interest Entity Ownership Percentage	66.00%
Variable Interest Entity, Primary Beneficiary [Member] | Jackalope Gas Gathering Services LLC [Member]
Variable Interest Entity [Line Items]
Variable Interest Entity Ownership Percentage	50.00%
General and Limited Partner [Member] | Williams Partners L.P. [Member]
Variable Interest Entity [Line Items]
Limited Liability Company or Limited Partnership, Members or Limited Partners, Ownership Interest	74.00%	60.00%
Variable Interest Entity Ownership Percentage	74.00%

Related Party Transactions (Det

Related Party Transactions (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Equity Method Investee [Member]
Related Party Transaction [Line Items]
Product costs	$ 226	$ 180	$ 187
Accounts payable	20	19
Management Fees Revenue	$ 67	66	64
Common Management Transaction [Member]
Related Party Transaction [Line Items]
Service revenues		$ 144	$ 111

Investing Activities (Details)

Investing Activities (Details) - USD ($) $ in Millions		1 Months Ended	12 Months Ended
		Jun. 30, 2015	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Schedule of Investments [Line Items]
Impairment of equity-method investments			$ 0	$ 430	$ 1,359
Equity earnings (losses)			434	397	335
Investment income, nonoperating			282	63	27
Gain on sale of equity-method investment			269	27	0
Equity-method investments			6,552	6,701
Proceeds from dispositions of equity-method investments			200	34	0
Equity-method investment, difference between carrying amount and underlying equity			1,800	1,900
Equity-method investment, payments to purchase or contributions			132	177	595
Equity-method investment, dividends or distributions			784	742	633
Special distribution from equity-method investment			0	0	396
Summarized Financial Position of Equity Method Investments
Current assets			447	508
Noncurrent assets			9,181	9,695
Current liabilities			(295)	(412)
Noncurrent liabilities			(1,538)	(1,484)
Summarized Results of Operations of Equity Method Investments
Gross revenue			1,961	1,883	1,707
Operating income			871	799	690
Net income			806	726	611
Caiman Energy II [Member]
Schedule of Investments [Line Items]
Equity-method investments			$ 429	426
Equity-method investment, ownership percentage			58.00%
Equity-method investment, payments to purchase or contributions			$ 24	22	0
Equity-method investment, dividends or distributions			49	40	33
Delaware Basin Gas Gathering System [Member]
Schedule of Investments [Line Items]
Impairment of equity-method investments				59	503
Equity-method investments			$ 0	$ 988
Equity-method investment, ownership percentage			0.00%	50.00%
Equity-method investment, payments to purchase or contributions			$ 32	$ 105	57
Equity-method investment, dividends or distributions			39	39	33
Appalachia Midstream Investments [Member]
Schedule of Investments [Line Items]
Impairment of equity-method investments				294	562
Equity earnings (losses)					(19)
Gain on sale of equity-method investment				27
Equity-method investments	[1]		$ 3,104	2,062
Equity-method investment, ownership percentage			66.00%
Equity-method investment, payments to purchase or contributions			$ 70	28	93
Equity-method investment, dividends or distributions			270	211	219
Utica East Ohio Midstream, LLC [Member]
Schedule of Investments [Line Items]
Impairment of equity-method investments				0	241
Equity-method investments			$ 1,383	1,448
Equity-method investment, ownership percentage			62.00%
Equity-method investment, payments to purchase or contributions			$ 0	0	357
Equity-method investment, dividends or distributions			80	92	42
Discovery Producer Services LLC [Member]
Schedule of Investments [Line Items]
Equity-method investments			$ 534	572
Equity-method investment, ownership percentage			60.00%
Equity-method investment, payments to purchase or contributions			$ 1	0	35
Equity-method investment, dividends or distributions			127	141	116
Laurel Mountain Midstream, LLC [Member]
Schedule of Investments [Line Items]
Impairment of equity-method investments				50	45
Equity-method investments			$ 309	324
Equity-method investment, ownership percentage			69.00%
Equity-method investment, dividends or distributions			$ 32	28	31
Overland Pass Pipeline Company LLC [Member]
Schedule of Investments [Line Items]
Equity-method investments			$ 422	430
Equity-method investment, ownership percentage			50.00%
Equity-method investment, dividends or distributions			$ 68	69	45
Gulfstream Natural Gas System, L.L.C.[Member]
Schedule of Investments [Line Items]
Equity-method investments			$ 244	261
Equity-method investment, ownership percentage			50.00%
Equity-method investment, dividends or distributions			$ 92	100	88
Special distribution from equity-method investment					396
Contribution to equity-method investment for repayment of debt				148	248
Ranch Westex JV LLC [Member]
Schedule of Investments [Line Items]
Impairment of equity-method investments				24	0
Other [Member]
Schedule of Investments [Line Items]
Impairment of equity-method investments				3	8
Equity-method investments			127	190
Equity-method investment, payments to purchase or contributions			5	22	53
Equity-method investment, dividends or distributions			$ 27	22	26
Former Venezuela Operations [Member]
Schedule of Investments [Line Items]
Investment income, nonoperating				36	27
Equity-Method Investment Debt Due November 1, 2015 [Member] | Gulfstream Natural Gas System, L.L.C.[Member]
Schedule of Investments [Line Items]
Equity-method investment debt					$ 500
Equity-Method Investment Debt Due June 1, 2016 [Member] | Gulfstream Natural Gas System, L.L.C.[Member]
Schedule of Investments [Line Items]
Equity-method investment debt				$ 300
Additional Investment [Member] | Utica East Ohio Midstream, LLC [Member]
Schedule of Investments [Line Items]
Equity-method investment, ownership percentage		13.00%
Williams Partners [Member] | Caiman Energy II [Member]
Schedule of Investments [Line Items]
Equity-method investment, ownership percentage			58.00%
Williams Partners [Member] | Delaware Basin Gas Gathering System [Member]
Schedule of Investments [Line Items]
Gain on sale of equity-method investment			$ 269
Equity-method investment, ownership percentage				50.00%
Proceeds from dispositions of equity-method investments			$ 155
Williams Partners [Member] | Appalachia Midstream Services, LLC [Member]
Schedule of Investments [Line Items]
Equity-method investment, ownership percentage			66.00%
Williams Partners [Member] | Utica East Ohio Midstream, LLC [Member]
Schedule of Investments [Line Items]
Equity-method investment, ownership percentage			62.00%
Reduction in incentive distribution rights payment		$ 2
Equity-method investment, payments to purchase or contributions		$ 357
Williams Partners [Member] | Discovery Producer Services LLC [Member]
Schedule of Investments [Line Items]
Equity-method investment, ownership percentage			60.00%
Williams Partners [Member] | Laurel Mountain Midstream, LLC [Member]
Schedule of Investments [Line Items]
Equity-method investment, ownership percentage			69.00%
Williams Partners [Member] | Overland Pass Pipeline Company LLC [Member]
Schedule of Investments [Line Items]
Equity-method investment, ownership percentage			50.00%
Williams Partners [Member] | Gulfstream Natural Gas System, L.L.C.[Member]
Schedule of Investments [Line Items]
Equity-method investment, ownership percentage			50.00%
Williams Partners [Member] | Ranch Westex JV LLC [Member]
Schedule of Investments [Line Items]
Proceeds from dispositions of equity-method investments			$ 45
Appalachia Midstream Services, LLC [Member] | Williams Partners [Member]
Schedule of Investments [Line Items]
Investments, Fair Value Disclosure			$ 1,100
Fair Value Inputs, Discount Rate			9.50%
[1]	Includes equity-method investments in multiple gathering systems in the Marcellus Shale with an approximate average 66 percent interest.

Other Income and Expenses (Deta

Other Income and Expenses (Details) - USD ($) $ in Millions		Jul. 03, 2017	Feb. 23, 2017	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Segment Reporting Information [Line Items]
Gain on sale of Refinery Grade Propylene Splitter				$ 1,095	$ 0	$ 0
Gain on asset retirement	[1]			22	138
Regulatory charges resulting from Tax Reform (Note 1)				776	0	0
Debt Instrument, Unamortized Discount (Premium), Net		$ 3	$ 30	24	(88)
Williams Partners [Member]
Segment Reporting Information [Line Items]
Litigation Settlement, Amount Awarded to Other Party					15
Other income (expense) - net [Member] | Williams Partners [Member]
Segment Reporting Information [Line Items]
Amortization of regulatory assets associated with asset retirement obligations				33	33	33
Accrual of regulatory liability related to overcollection of certain employee expenses				22	25	20
Project development costs related to Constitution (Note 3)				16	28	0
Gains on contract settlements and terminations				(15)	0	0
Gain on sale of Refinery Grade Propylene Splitter				(12)	0	0
Net foreign currency exchange (gains) losses (1)	[2]			0	10	(10)
Gain on asset retirement				0	(11)	0
Other income (expense) - net [Member] | Corporate and Other [Member]
Segment Reporting Information [Line Items]
Gain on sale of unused pipe				0	(10)	0
Selling, general and administrative expenses [Member] | Williams Partners [Member] | Acquisition and Merger [Member]
Segment Reporting Information [Line Items]
Business combination, acquisition related costs						26
Selling, general and administrative expenses [Member] | Corporate and Other [Member]
Segment Reporting Information [Line Items]
Project development costs related to Constitution (Note 3)					61
Selling, general and administrative expenses [Member] | Corporate and Other [Member] | Acquisition and Merger [Member]
Segment Reporting Information [Line Items]
Restructuring Charges				9	47
Selling, general and administrative expenses [Member] | Corporate and Other [Member] | Other Restructuring [Member]
Segment Reporting Information [Line Items]
Business combination, integration related costs						32
Operation and maintenance expenses [Member] | Williams Partners [Member] | Transition [Member]
Segment Reporting Information [Line Items]
Business combination, integration related costs						12
Service revenues [Member] | Williams Partners [Member]
Segment Reporting Information [Line Items]
Minimum volume commitment fees				66	58	239
Deferred Revenue, Revenue Recognized					173
Selling, general, and administrative expenses and Operating and maintenance expenses [Member] | Williams Partners [Member]
Segment Reporting Information [Line Items]
Severance and other related costs				22	$ 42
Restructuring and Related Cost, Number of Positions Eliminated, Period Percent					10.00%
Other income (expense) - net [Member]
Segment Reporting Information [Line Items]
Regulatory charges resulting from Tax Reform (Note 1)				102
Other income (expense) - net [Member] | Williams Partners [Member]
Segment Reporting Information [Line Items]
Allowance for funds used during construction, capitalized cost of equity				71	$ 66	77
Regulatory charges resulting from Tax Reform (Note 1)				39
Other income (expense) - net [Member] | Corporate and Other [Member]
Segment Reporting Information [Line Items]
Regulatory charges resulting from Tax Reform (Note 1)				63
Unamortized Loan Commitment and Origination Fees and Unamortized Discounts or Premiums		51	53
Debt Instrument, Unamortized Premium		$ 54	$ 23
Deferred taxes on equity funds used during construction [Member] | Corporate and Other [Member]
Segment Reporting Information [Line Items]
Allowance for funds used during construction, capitalized cost of equity				52	23	18
Disposal Group, Not Discontinued Operations [Member] | Canadian Operations [Member] | Other income (expense) - net [Member]
Segment Reporting Information [Line Items]
Loss on sale of Canadian operations (Note 2)					66
Disposal Group, Not Discontinued Operations [Member] | Canadian Operations [Member] | Other income (expense) - net [Member] | Williams Partners [Member]
Segment Reporting Information [Line Items]
Loss on sale of Canadian operations (Note 2)				4	34	0
Disposal Group, Not Discontinued Operations [Member] | Canadian Operations [Member] | Other income (expense) - net [Member] | Corporate and Other [Member]
Segment Reporting Information [Line Items]
Loss on sale of Canadian operations (Note 2)				1	$ 32	$ 0
Pension Plan [Member] | Other income (expense) - net [Member] | Williams Partners [Member]
Segment Reporting Information [Line Items]
Defined Benefit Plan, Net Periodic Benefit Cost (Credit), Gain (Loss) Due to Settlement and Curtailment				$ 35
6.125% Senior Unsecured Notes due 2022 [Member] | Williams Partners L.P. [Member]
Segment Reporting Information [Line Items]
Debt Instrument, Interest Rate, Stated Percentage			6.125%
Extinguishment of Debt, Amount			$ 750
4.875% Senior Unsecured Notes due 2023 [Member] | Williams Partners L.P. [Member]
Segment Reporting Information [Line Items]
Debt Instrument, Interest Rate, Stated Percentage		4.875%
Extinguishment of Debt, Amount		$ 1,400
[1]	(2)Several factors are considered in the annual review process, including inflation rates, current estimates for removal cost, market risk premiums, discount rates, and the estimated remaining useful life of the assets. The 2017 revisions reflect changes in removal cost estimates and decreases in the estimated remaining useful life of certain assets and discount rates used in the annual review process. 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.
[2]	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 2 – Acquisitions and Divestitures).

Provision (Benefit) for Incom56

Provision (Benefit) for Income Taxes Tax Provison (Benefit) Table (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Current :
Federal	$ 15	$ 0	$ 0
State	23	2	(7)
Foreign	0	(1)	(55)
Total	38	1	(62)
Deferred:
Federal	(2,004)	(6)	(317)
State	(8)	61	(25)
Foreign	0	(81)	5
Total	(2,012)	(26)	(337)
Provision (benefit) for income taxes	$ (1,974)	$ (25)	$ (399)

Provision (Benefit) for Incom57

Provision (Benefit) for Income Taxes Reconciliations to Recorded Tax Provision (Benefit) Table (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Effective Income Tax Rate Reconciliation [Abstract]
Provision (benefit) at statutory rate	$ 187	$ (131)	$ (600)
Increases (decreases) in taxes resulting from:
Impact of nontaxable noncontrolling interests	(117)	(22)	263
Federal Tax Reform rate change	(1,932)	0	0
State income taxes (net of federal benefit)	(17)	3	(21)
State deferred income tax rate change	26	43	0
Foreign operations – net (including tax effect of Canadian Sale)	(127)	78	8
Translation adjustment of certain unrecognized tax benefits	0	(1)	(71)
Other – net	6	5	22
Provision (benefit) for income taxes	$ (1,974)	$ (25)	$ (399)

Provision (Benefit) for Incom58

Provision (Benefit) for Income Taxes Deferred Tax Table (Details) - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016
Deferred income tax liabilities:
Investments	$ 3,565	$ 5,300
Other	19	29
Total deferred income tax liabilities	3,584	5,329
Deferred income tax assets:
Accrued liabilities	53	145
Minimum tax credit	155	139
Foreign tax credit	140	140
Federal loss carryovers	0	651
State losses and credits	283	313
Other	30	37
Total deferred income tax assets	661	1,425
Less valuation allowance	224	334
Net deferred income tax assets	437	1,091
Overall net deferred income tax liabilities	$ 3,147	$ 4,238

Provision (Benefit) for Incom59

Provision (Benefit) for Income Taxes Reconciliation of Unrecognized Tax Benefits Table (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward]
Balance at beginning of period	$ 50	$ 55
Reductions for tax positions of prior years	0	(4)
Changes due to currency translation	0	(1)
Balance at end of period	$ 50	$ 50

Provision (Benefit) for Incom60

Provision (Benefit) for Income Taxes Textuals (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Income Tax Contingency [Line Items]
Foreign income (loss) in Income from continuing operations before income taxes	$ (7,000)	$ (885,000)	$ 20,000
Impairment Loss			2,700,000
Minimum tax credit	155,000	139,000
Deferred Tax Assets, Tax Credit Carryforwards, Foreign	140,000	140,000
Valuation Allowance, Deferred Tax Asset, Increase (Decrease), Amount	(127,000)
Cash payments for income taxes (net of refunds and including discontinued operations)	28,000	5,000	(136,000)
Unrecognized tax benefits	50,000	50,000	55,000
Unrecognized Tax Benefits that Would Impact Effective Tax Rate	50,000	49,000
Total interest and penalties recognized as part of income tax provision	(400)	300	$ (22,000)
Total interest and penalties accrued as uncertain tax positions	$ 2,000	$ 3,000
Federal tax rate before Tax Reform [Member]
Income Tax Contingency [Line Items]
Effective Income Tax Rate Reconciliation, Change in Enacted Tax Rate, Percent	35.00%
Federal tax rate after Tax Reform [Member]
Income Tax Contingency [Line Items]
Effective Income Tax Rate Reconciliation, Change in Enacted Tax Rate, Percent	21.00%

Earnings (Loss) Per Common Sh61

Earnings (Loss) Per Common Share (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016		Dec. 31, 2015
Earnings (loss) per common share
Net income (loss) attributable to The Williams Companies, Inc. available to common stockholders for basic and diluted earnings (loss) per common share	$ 2,174	$ (424)		$ (571)
Basic weighted-average shares	826,177	750,673		749,271
Effect of dilutive securities:
Diluted weighted-average shares	828,518	750,673	[1]	749,271	[1]
Earnings (loss) per common share:
Basic	$ 2.63	$ (0.57)		$ (0.76)
Diluted	$ 2.62	$ (0.57)		$ (0.76)
Nonvested restricted stock units [Member]
Effect of dilutive securities:
Incremental common shares attributable to share-based payment arrangements under effects of dilutive securities item	1,704	0		0
Earnings (loss) per common share from continuing operations (Textuals) [Abstract]
Number of weighted-average shares excluded from computation of diluted earnings per common share		600		1,700
Stock options [Member]
Effect of dilutive securities:
Incremental common shares attributable to share-based payment arrangements under effects of dilutive securities item	637	0		0
Earnings (loss) per common share from continuing operations (Textuals) [Abstract]
Number of weighted-average shares excluded from computation of diluted earnings per common share		500		1,500
[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.

EBPs Obligation Rollforward (De

EBPs Obligation Rollforward (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Pension Benefits [Member]
Change in benefit obligation:
Benefit obligation at beginning of year	$ 1,466	$ 1,464
Service cost	50	54	$ 59
Interest cost	59	62	58
Plan participants’ contributions	0	0
Benefits paid	(35)	(130)
Actuarial loss (gain)	40	20
Settlements	(261)	(4)
Net increase (decrease) in benefit obligation	(147)	2
Benefit obligation at end of year	1,319	1,466	1,464
Other Postretirement Benefits [Member]
Change in benefit obligation:
Benefit obligation at beginning of year	197	202
Service cost	1	1	2
Interest cost	8	8	9
Plan participants’ contributions	3	2
Benefits paid	(14)	(15)
Actuarial loss (gain)	11	(1)
Settlements	0	0
Net increase (decrease) in benefit obligation	9	(5)
Benefit obligation at end of year	$ 206	$ 197	$ 202

EBP Asset rollforward and B.S.

EBP Asset rollforward and B.S. classification (Details 1) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Pension Benefits [Member]
Change in plan assets:
Fair value of plan assets at beginning of year	$ 1,254	$ 1,241
Actual return on plan assets	184	82
Employer contributions	85	65
Plan participants’ contributions	0	0
Benefits paid	(35)	(130)
Settlements	(261)	(4)
Net increase (decrease) in fair value of plan assets	(27)	13
Fair value of plan assets at end of year	1,227	1,254
Funded status — overfunded (underfunded)	(92)	(212)
Accumulated benefit obligation	1,294	1,440
Overfunded/(underfunded) status of our pension plans and other postretirement benefit plans
Current liabilities	(2)	(2)
Noncurrent liabilities	(90)	(210)
Amounts included in Accumulated other comprehensive income (loss):
Prior service credit	0	0
Net actuarial loss	(375)	(535)
Amounts included in regulatory liabilities associated with Transco and Northwest Pipeline:
Net regulatory assets (liabilities)	(33)	(21)
Other Postretirement Benefits [Member]
Change in plan assets:
Fair value of plan assets at beginning of year	208	201
Actual return on plan assets	25	13
Employer contributions	5	7
Plan participants’ contributions	3	2
Benefits paid	(14)	(15)
Settlements	0	0
Net increase (decrease) in fair value of plan assets	19	7
Fair value of plan assets at end of year	227	208
Funded status — overfunded (underfunded)	21	11
Overfunded/(underfunded) status of our pension plans and other postretirement benefit plans
Current liabilities	(6)	(7)
Noncurrent assets (liabilities)	27	18
Amounts included in Accumulated other comprehensive income (loss):
Prior service credit	0	5
Net actuarial loss	(21)	(18)
Amounts included in regulatory liabilities associated with Transco and Northwest Pipeline:
Prior service credit	2	10
Net actuarial loss	14	8
Net regulatory assets (liabilities)	$ (108)	$ (94)

EBP Net Periodic Benefit Cost &

EBP Net Periodic Benefit Cost & OCI (Details 2) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Pension Benefits [Member]
Components of net periodic benefit cost (credit):
Service cost	$ 50	$ 54	$ 59
Interest cost	59	62	58
Expected return on plan assets	(82)	(85)	(75)
Amortization of prior service credit	0	0	0
Amortization of net actuarial loss	27	30	42
Net actuarial loss from settlements	71	2	2
Reclassification to regulatory liability	0	0	0
Net periodic benefit cost (credit)	125	63	86
Other changes in plan assets and benefit obligations recognized in Other comprehensive income (loss):
Net actuarial gain (loss)	62	(23)	5
Amortization of prior service credit	0	0	0
Amortization of net actuarial loss	27	30	42
Net actuarial loss from settlements	71	2	2
Other changes in plan assets and benefit obligations recognized in Other comprehensive income (loss)	160	9	49
Amounts included in Accumulated other comprehensive income (loss) expected to be amortized in next fiscal year:
Prior service credit	0
Net actuarial loss	23
Other Postretirement Benefits [Member]
Components of net periodic benefit cost (credit):
Service cost	1	1	2
Interest cost	8	8	9
Expected return on plan assets	(11)	(12)	(12)
Amortization of prior service credit	(13)	(15)	(17)
Amortization of net actuarial loss	0	0	2
Net actuarial loss from settlements	0	0	0
Reclassification to regulatory liability	3	4	3
Net periodic benefit cost (credit)	(12)	(14)	(13)
Other changes in plan assets and benefit obligations recognized in Other comprehensive income (loss):
Net actuarial gain (loss)	(3)	0	8
Amortization of prior service credit	(5)	(6)	(6)
Amortization of net actuarial loss	0	0	2
Net actuarial loss from settlements	0	0	0
Other changes in plan assets and benefit obligations recognized in Other comprehensive income (loss)	(8)	(6)	4
Other changes in plan assets and benefit obligations recognized in regulatory (assets) and liabilities:
Net actuarial gain (loss)	6	2	10
Amortization of prior service credit	(8)	$ (9)	$ (11)
Amounts included in Accumulated other comprehensive income (loss) expected to be amortized in next fiscal year:
Prior service credit	(1)
Net actuarial loss	0
Amounts included in regulatory liabilities associated with Transco and Northwest Pipeline expected to be amortized in next fiscal year:
Prior service credit	(2)
Net actuarial loss	0
Other Nonoperating Income (Expense) [Member] | Pension Benefits [Member]
Components of net periodic benefit cost (credit):
Net actuarial loss from settlements	$ (35)

EBP Key Assumptions (Details 3)

EBP Key Assumptions (Details 3) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Pension Benefits [Member]
Weighted average assumptions utilized to determine benefit obligations
Discount rate	3.66%	4.17%
Rate of compensation increase	4.93%	4.87%
Weighted average assumptions utilized to determine net periodic benefit cost (credit)
Discount rate	4.17%	4.37%	3.96%
Expected long-term rate of return on plan assets	6.45%	6.85%	6.38%
Rate of compensation increase	4.87%	4.88%	4.62%
Other Postretirement Benefits [Member]
Weighted average assumptions utilized to determine benefit obligations
Discount rate	3.71%	4.27%
Weighted average assumptions utilized to determine net periodic benefit cost (credit)
Discount rate	4.27%	4.50%	4.12%
Expected long-term rate of return on plan assets	5.53%	6.11%	5.70%
One percentage point change in assumed health care cost trend rates effects
Effect on total of service and interest cost components, Point increase	$ 0
Effect on total of service and interest cost components, Point decrease	0
Effect on other postretirement benefit obligation, Point increase	5
Effect on other postretirement benefit obligation, Point decrease	$ (5)
Health care cost trend rate assumed for next fiscal year	8.00%
Direction and pattern of change for assumed health care cost trend rate	decreases
Ultimate health care cost trend rate	4.50%
Year that rate reaches ultimate trend rate	2,026

EBP Plan Assets (Details 4)

EBP Plan Assets (Details 4) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Defined Benefit Plan Disclosure [Line Items]
Maximum percentage of total stock portfolio invested in the common stock of any one corporation	5.00%
Maximum percentage of portfolio invested in fixed income securities of any one issuer with exception of bond index funds and U. S. government guaranteed and agency securities	5.00%
Fair value, plan assets, Level 1 to Level 2 transfers, amount	$ 0	$ 0
Fair value, plan assets, Level 2 to Level 1 transfers, amount	$ 0	$ 0
Maximum [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value, Investments, Entities that Calculate Net Asset Value Per Share, Investment Redemption, Notice Period	30 days
Minimum [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value, Investments, Entities that Calculate Net Asset Value Per Share, Investment Redemption, Notice Period	10 days
Fixed income securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Weighted average duration of fixed income security portfolio	12 years	8 years
Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value, plan assets, Level 1 to Level 2 transfers, amount	$ 0
Fair value, plan assets, Level 2 to Level 1 transfers, amount	0
Fair values of plan assets
Total assets at fair value	$ 1,227	$ 1,254	$ 1,241
Pension Benefits [Member] | Equity securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Plan asset target allocation	46.00%
Pension Benefits [Member] | Fixed income securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Plan asset target allocation	54.00%
Pension Benefits [Member] | Plan assets within fair value hierarchy [Member]
Fair values of plan assets
Total assets at fair value	$ 461	489
Pension Benefits [Member] | Cash management fund
Fair values of plan assets
Total assets at fair value	17	14
Pension Benefits [Member] | U.S. large cap | Equity securities [Member]
Fair values of plan assets
Total assets at fair value	62	87
Pension Benefits [Member] | U.S. small cap | Equity securities [Member]
Fair values of plan assets
Total assets at fair value	54	77
Pension Benefits [Member] | U.S. Treasury securities | Fixed income securities [Member]
Fair values of plan assets
Total assets at fair value	103	68
Pension Benefits [Member] | Government and municipal bonds | Fixed income securities [Member]
Fair values of plan assets
Total assets at fair value	15	10
Pension Benefits [Member] | Mortgage and asset-backed securities | Fixed income securities [Member]
Fair values of plan assets
Total assets at fair value	47	80
Pension Benefits [Member] | Corporate bonds | Fixed income securities [Member]
Fair values of plan assets
Total assets at fair value	158	148
Pension Benefits [Member] | Insurance company investment contracts and other
Fair values of plan assets
Total assets at fair value	5	5
Pension Benefits [Member] | Equities - U.S. large cap [Member] | Commingled investment funds - equities [Member]
Fair values of plan assets
Total assets at fair value	265	369
Pension Benefits [Member] | Equities - International small cap [Member] | Commingled investment funds - equities [Member]
Fair values of plan assets
Total assets at fair value	26	27
Pension Benefits [Member] | Equities - International emerging markets [Member] | Commingled investment funds - equities [Member]
Fair values of plan assets
Total assets at fair value	41	50
Pension Benefits [Member] | Equities - International developed markets [Member] | Commingled investment funds - equities [Member]
Fair values of plan assets
Total assets at fair value	110	149
Pension Benefits [Member] | Fixed income - U.S. long duration [Member] | Commingled investment funds - fixed income [Member]
Fair values of plan assets
Total assets at fair value	205	88
Pension Benefits [Member] | Fixed income - Corporate bonds [Member] | Commingled investment funds - fixed income [Member]
Fair values of plan assets
Total assets at fair value	119	82
Pension Benefits [Member] | Level 1 [Member]
Fair values of plan assets
Total assets at fair value	236	246
Pension Benefits [Member] | Level 1 [Member] | Cash management fund
Fair values of plan assets
Total assets at fair value	17	14
Pension Benefits [Member] | Level 1 [Member] | U.S. large cap | Equity securities [Member]
Fair values of plan assets
Total assets at fair value	62	87
Pension Benefits [Member] | Level 1 [Member] | U.S. small cap | Equity securities [Member]
Fair values of plan assets
Total assets at fair value	54	77
Pension Benefits [Member] | Level 1 [Member] | U.S. Treasury securities | Fixed income securities [Member]
Fair values of plan assets
Total assets at fair value	103	68
Pension Benefits [Member] | Level 1 [Member] | Government and municipal bonds | Fixed income securities [Member]
Fair values of plan assets
Total assets at fair value	0	0
Pension Benefits [Member] | Level 1 [Member] | Mortgage and asset-backed securities | Fixed income securities [Member]
Fair values of plan assets
Total assets at fair value	0	0
Pension Benefits [Member] | Level 1 [Member] | Corporate bonds | Fixed income securities [Member]
Fair values of plan assets
Total assets at fair value	0	0
Pension Benefits [Member] | Level 1 [Member] | Insurance company investment contracts and other
Fair values of plan assets
Total assets at fair value	0	0
Pension Benefits [Member] | Level 2 [Member]
Fair values of plan assets
Total assets at fair value	225	243
Pension Benefits [Member] | Level 2 [Member] | Cash management fund
Fair values of plan assets
Total assets at fair value	0	0
Pension Benefits [Member] | Level 2 [Member] | U.S. large cap | Equity securities [Member]
Fair values of plan assets
Total assets at fair value	0	0
Pension Benefits [Member] | Level 2 [Member] | U.S. small cap | Equity securities [Member]
Fair values of plan assets
Total assets at fair value	0	0
Pension Benefits [Member] | Level 2 [Member] | U.S. Treasury securities | Fixed income securities [Member]
Fair values of plan assets
Total assets at fair value	0	0
Pension Benefits [Member] | Level 2 [Member] | Government and municipal bonds | Fixed income securities [Member]
Fair values of plan assets
Total assets at fair value	15	10
Pension Benefits [Member] | Level 2 [Member] | Mortgage and asset-backed securities | Fixed income securities [Member]
Fair values of plan assets
Total assets at fair value	47	80
Pension Benefits [Member] | Level 2 [Member] | Corporate bonds | Fixed income securities [Member]
Fair values of plan assets
Total assets at fair value	158	148
Pension Benefits [Member] | Level 2 [Member] | Insurance company investment contracts and other
Fair values of plan assets
Total assets at fair value	5	5
Pension Benefits [Member] | Level 3 [Member]
Fair values of plan assets
Total assets at fair value	0	0
Pension Benefits [Member] | Level 3 [Member] | Cash management fund
Fair values of plan assets
Total assets at fair value	0	0
Pension Benefits [Member] | Level 3 [Member] | U.S. large cap | Equity securities [Member]
Fair values of plan assets
Total assets at fair value	0	0
Pension Benefits [Member] | Level 3 [Member] | U.S. small cap | Equity securities [Member]
Fair values of plan assets
Total assets at fair value	0	0
Pension Benefits [Member] | Level 3 [Member] | U.S. Treasury securities | Fixed income securities [Member]
Fair values of plan assets
Total assets at fair value	0	0
Pension Benefits [Member] | Level 3 [Member] | Government and municipal bonds | Fixed income securities [Member]
Fair values of plan assets
Total assets at fair value	0	0
Pension Benefits [Member] | Level 3 [Member] | Mortgage and asset-backed securities | Fixed income securities [Member]
Fair values of plan assets
Total assets at fair value	0	0
Pension Benefits [Member] | Level 3 [Member] | Corporate bonds | Fixed income securities [Member]
Fair values of plan assets
Total assets at fair value	0	0
Pension Benefits [Member] | Level 3 [Member] | Insurance company investment contracts and other
Fair values of plan assets
Total assets at fair value	$ 0	0
Other Postretirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Proportion of assets subjected to income tax	37.00%
Fair values of plan assets
Total assets at fair value	$ 227	208	$ 201
Other Postretirement Benefits [Member] | Plan assets within fair value hierarchy [Member]
Fair values of plan assets
Total assets at fair value	137	128
Other Postretirement Benefits [Member] | Cash management fund
Fair values of plan assets
Total assets at fair value	11	11
Other Postretirement Benefits [Member] | U.S. large cap | Equity securities [Member]
Fair values of plan assets
Total assets at fair value	25	24
Other Postretirement Benefits [Member] | U.S. small cap | Equity securities [Member]
Fair values of plan assets
Total assets at fair value	14	15
Other Postretirement Benefits [Member] | International developed markets large cap growth [Member] | Equity securities [Member]
Fair values of plan assets
Total assets at fair value	6	5
Other Postretirement Benefits [Member] | U.S. Treasury securities | Fixed income securities [Member]
Fair values of plan assets
Total assets at fair value	12	7
Other Postretirement Benefits [Member] | Government and municipal bonds | Fixed income securities [Member]
Fair values of plan assets
Total assets at fair value	2	1
Other Postretirement Benefits [Member] | Mortgage and asset-backed securities | Fixed income securities [Member]
Fair values of plan assets
Total assets at fair value	5	8
Other Postretirement Benefits [Member] | Corporate bonds | Fixed income securities [Member]
Fair values of plan assets
Total assets at fair value	19	15
Other Postretirement Benefits [Member] | Equities - U.S. large cap [Member] | Commingled investment funds - equities [Member]
Fair values of plan assets
Total assets at fair value	31	38
Other Postretirement Benefits [Member] | Equities - International small cap [Member] | Commingled investment funds - equities [Member]
Fair values of plan assets
Total assets at fair value	3	3
Other Postretirement Benefits [Member] | Equities - International emerging markets [Member] | Commingled investment funds - equities [Member]
Fair values of plan assets
Total assets at fair value	5	5
Other Postretirement Benefits [Member] | Equities - International developed markets [Member] | Commingled investment funds - equities [Member]
Fair values of plan assets
Total assets at fair value	13	16
Other Postretirement Benefits [Member] | Fixed income - U.S. long duration [Member] | Commingled investment funds - fixed income [Member]
Fair values of plan assets
Total assets at fair value	24	9
Other Postretirement Benefits [Member] | Fixed income - Corporate bonds [Member] | Commingled investment funds - fixed income [Member]
Fair values of plan assets
Total assets at fair value	14	9
Other Postretirement Benefits [Member] | Mutual fund - Municipal bonds [Member]
Fair values of plan assets
Total assets at fair value	43	42
Other Postretirement Benefits [Member] | Level 1 [Member]
Fair values of plan assets
Total assets at fair value	105	99
Other Postretirement Benefits [Member] | Level 1 [Member] | Cash management fund
Fair values of plan assets
Total assets at fair value	11	11
Other Postretirement Benefits [Member] | Level 1 [Member] | U.S. large cap | Equity securities [Member]
Fair values of plan assets
Total assets at fair value	25	24
Other Postretirement Benefits [Member] | Level 1 [Member] | U.S. small cap | Equity securities [Member]
Fair values of plan assets
Total assets at fair value	14	15
Other Postretirement Benefits [Member] | Level 1 [Member] | International developed markets large cap growth [Member] | Equity securities [Member]
Fair values of plan assets
Total assets at fair value	0	0
Other Postretirement Benefits [Member] | Level 1 [Member] | U.S. Treasury securities | Fixed income securities [Member]
Fair values of plan assets
Total assets at fair value	12	7
Other Postretirement Benefits [Member] | Level 1 [Member] | Government and municipal bonds | Fixed income securities [Member]
Fair values of plan assets
Total assets at fair value	0	0
Other Postretirement Benefits [Member] | Level 1 [Member] | Mortgage and asset-backed securities | Fixed income securities [Member]
Fair values of plan assets
Total assets at fair value	0	0
Other Postretirement Benefits [Member] | Level 1 [Member] | Corporate bonds | Fixed income securities [Member]
Fair values of plan assets
Total assets at fair value	0	0
Other Postretirement Benefits [Member] | Level 1 [Member] | Mutual fund - Municipal bonds [Member]
Fair values of plan assets
Total assets at fair value	43	42
Other Postretirement Benefits [Member] | Level 2 [Member]
Fair values of plan assets
Total assets at fair value	32	29
Other Postretirement Benefits [Member] | Level 2 [Member] | Cash management fund
Fair values of plan assets
Total assets at fair value	0	0
Other Postretirement Benefits [Member] | Level 2 [Member] | U.S. large cap | Equity securities [Member]
Fair values of plan assets
Total assets at fair value	0	0
Other Postretirement Benefits [Member] | Level 2 [Member] | U.S. small cap | Equity securities [Member]
Fair values of plan assets
Total assets at fair value	0	0
Other Postretirement Benefits [Member] | Level 2 [Member] | International developed markets large cap growth [Member] | Equity securities [Member]
Fair values of plan assets
Total assets at fair value	6	5
Other Postretirement Benefits [Member] | Level 2 [Member] | U.S. Treasury securities | Fixed income securities [Member]
Fair values of plan assets
Total assets at fair value	0	0
Other Postretirement Benefits [Member] | Level 2 [Member] | Government and municipal bonds | Fixed income securities [Member]
Fair values of plan assets
Total assets at fair value	2	1
Other Postretirement Benefits [Member] | Level 2 [Member] | Mortgage and asset-backed securities | Fixed income securities [Member]
Fair values of plan assets
Total assets at fair value	5	8
Other Postretirement Benefits [Member] | Level 2 [Member] | Corporate bonds | Fixed income securities [Member]
Fair values of plan assets
Total assets at fair value	19	15
Other Postretirement Benefits [Member] | Level 2 [Member] | Mutual fund - Municipal bonds [Member]
Fair values of plan assets
Total assets at fair value	0	0
Other Postretirement Benefits [Member] | Level 3 [Member]
Fair values of plan assets
Total assets at fair value	0	0
Other Postretirement Benefits [Member] | Level 3 [Member] | Cash management fund
Fair values of plan assets
Total assets at fair value	0	0
Other Postretirement Benefits [Member] | Level 3 [Member] | U.S. large cap | Equity securities [Member]
Fair values of plan assets
Total assets at fair value	0	0
Other Postretirement Benefits [Member] | Level 3 [Member] | U.S. small cap | Equity securities [Member]
Fair values of plan assets
Total assets at fair value	0	0
Other Postretirement Benefits [Member] | Level 3 [Member] | International developed markets large cap growth [Member] | Equity securities [Member]
Fair values of plan assets
Total assets at fair value	0	0
Other Postretirement Benefits [Member] | Level 3 [Member] | U.S. Treasury securities | Fixed income securities [Member]
Fair values of plan assets
Total assets at fair value	0	0
Other Postretirement Benefits [Member] | Level 3 [Member] | Government and municipal bonds | Fixed income securities [Member]
Fair values of plan assets
Total assets at fair value	0	0
Other Postretirement Benefits [Member] | Level 3 [Member] | Mortgage and asset-backed securities | Fixed income securities [Member]
Fair values of plan assets
Total assets at fair value	0	0
Other Postretirement Benefits [Member] | Level 3 [Member] | Corporate bonds | Fixed income securities [Member]
Fair values of plan assets
Total assets at fair value	0	0
Other Postretirement Benefits [Member] | Level 3 [Member] | Mutual fund - Municipal bonds [Member]
Fair values of plan assets
Total assets at fair value	$ 0	$ 0

EBP Benefit Pymts & Defined Con

EBP Benefit Pymts & Defined Contribution Plans (Details 5) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Expected benefit payments
Employer's contributions charged to expense under defined contribution plans	$ 34	$ 36	$ 39
Other Postretirement Benefits [Member]
Benefit Plan Disclosure [Line Items]
Expected total plans contribution, approximate	6
Expected benefit payments
2,018	13
2,019	13
2,020	14
2,021	13
2,022	13
2023-2027	60
Pension Benefits [Member]
Benefit Plan Disclosure [Line Items]
Expected total plans contribution, approximate	85
Expected benefit payments
2,018	91
2,019	90
2,020	92
2,021	96
2,022	96
2023-2027	486
Nonqualified Plan [Member]
Benefit Plan Disclosure [Line Items]
Expected total plans contribution, approximate	5
Qualified Plan [Member]
Benefit Plan Disclosure [Line Items]
Expected total plans contribution, approximate	$ 80

Property, Plant, and Equipmen68

Property, Plant, and Equipment (Details PPE) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2017	Dec. 31, 2016		Dec. 31, 2015
Property, Plant, and Equipment
Property, plant, and equipment, at cost		$ 39,513	$ 38,912
Accumulated depreciation and amortization		(11,302)	(10,484)
Property, plant, and equipment - net		28,211	28,428
Depreciation and amortization expenses		1,389	1,407		$ 1,382
Nonregulated [Member] | Natural gas gathering and processing facilities [Member]
Property, Plant, and Equipment
Property, plant, and equipment, at cost		$ 18,440	19,523	[1]
Nonregulated [Member] | Natural gas gathering and processing facilities [Member] | Minimum [Member]
Property, Plant, and Equipment
Property, Plant and Equipment, Useful Life	[2]	5 years
Nonregulated [Member] | Natural gas gathering and processing facilities [Member] | Maximum [Member]
Property, Plant, and Equipment
Property, Plant and Equipment, Useful Life	[2]	40 years
Nonregulated [Member] | Construction in Progress [Member]
Property, Plant, and Equipment
Property, plant, and equipment, at cost		$ 566	412
Nonregulated [Member] | Property, Plant and Equipment, Other Types [Member]
Property, Plant, and Equipment
Property, plant, and equipment, at cost			890
Nonregulated [Member] | Other Capitalized Property Plant and Equipment [Member]
Property, Plant, and Equipment
Property, plant, and equipment, at cost		$ 2,776	3,092	[1]
Nonregulated [Member] | Other Capitalized Property Plant and Equipment [Member] | Minimum [Member]
Property, Plant, and Equipment
Property, Plant and Equipment, Useful Life	[2]	2 years
Nonregulated [Member] | Other Capitalized Property Plant and Equipment [Member] | Maximum [Member]
Property, Plant, and Equipment
Property, Plant and Equipment, Useful Life	[2]	45 years
Regulated [Member] | Natural gas transmission facilities [Member]
Property, Plant, and Equipment
Property, plant, and equipment, at cost		$ 14,460	12,692
Regulated [Member] | Natural gas transmission facilities [Member] | Minimum [Member]
Property, Plant, and Equipment
Property, Plant, and Equipment, Depreciation Rate	[2]	1.20%
Regulated [Member] | Natural gas transmission facilities [Member] | Maximum [Member]
Property, Plant, and Equipment
Property, Plant, and Equipment, Depreciation Rate	[2]	6.97%
Regulated [Member] | Construction in Progress [Member]
Property, Plant, and Equipment
Property, plant, and equipment, at cost		$ 1,637	1,603
Regulated [Member] | Acquisition Adjustment Of Regulated Facilities [Member]
Property, Plant, and Equipment
Property, Plant and Equipment, Plant Acquisition Adjustments for Intangible Utility Plants		$ 626	665
Period of straight-line amortization		40 years
Regulated [Member] | Other Capitalized Property Plant and Equipment [Member]
Property, Plant, and Equipment
Property, plant, and equipment, at cost		$ 1,634	$ 1,590
Regulated [Member] | Other Capitalized Property Plant and Equipment [Member] | Minimum [Member]
Property, Plant, and Equipment
Property, Plant and Equipment, Useful Life	[2]	5 years
Property, Plant, and Equipment, Depreciation Rate	[2]	1.35%
Regulated [Member] | Other Capitalized Property Plant and Equipment [Member] | Maximum [Member]
Property, Plant, and Equipment
Property, Plant and Equipment, Useful Life	[2]	45 years
Property, Plant, and Equipment, Depreciation Rate	[2]	33.33%
[1]	(2)The 2016 presentation has been changed to reflect $890 million of right-of-way assets previously presented in Natural gas gathering and processing facilities, now in Other.
[2]	(1)Estimated useful life and depreciation rates are presented as of December 31, 2017. Depreciation rates and estimated useful lives for regulated assets are prescribed by the FERC.

Property, Plant, and Equipmen69

Property, Plant, and Equipment (Details ARO) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2017		Dec. 31, 2016
Asset Retirement Obligations
Asset Retirement Obligations, Noncurrent		$ 946		$ 801
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Beginning balance		862		915
Liabilities incurred		33		24
Liabilities settled		(16)		(8)
Accretion expense		141	[1]	69
Revisions (1)	[2]	(22)		(138)
Ending balance		998		$ 862
Asset Retirement Obligation Costs [Member]
Unusual or Infrequent Item [Line Items]
Transco's annual funding commitment for ARO		$ 36
[1]	(1)The increase in accretion expense for 2017 includes an adjustment associated with obligations identified from certain Transco land agreements.
[2]	(2)Several factors are considered in the annual review process, including inflation rates, current estimates for removal cost, market risk premiums, discount rates, and the estimated remaining useful life of the assets. The 2017 revisions reflect changes in removal cost estimates and decreases in the estimated remaining useful life of certain assets and discount rates used in the annual review process. 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.

Goodwill (Details)

Goodwill (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Goodwill [Line Items]
Impairment of goodwill	$ 0	$ 0	$ 1,098
Williams Partners [Member]
Goodwill [Line Items]
Goodwill	$ 47	$ 47	$ 47

Other Intangible Assets (Detail

Other Intangible Assets (Details) - USD ($) $ in Millions	1 Months Ended	12 Months Ended
	May 31, 2015	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Finite-Lived Intangible Assets [Line Items]
Amortization of Intangible Assets		$ 347	$ 356	$ 353
Finite-Lived Intangible Assets, Amortization Expense, Next Twelve Months		337
Finite-Lived Intangible Assets, Amortization Expense, Year Two		337
Finite-Lived Intangible Assets, Amortization Expense, Year Three		337
Finite-Lived Intangible Assets, Amortization Expense, Year Four		337
Finite-Lived Intangible Assets, Amortization Expense, Year Five		337
Contractual customer relationships [Member]
Finite-Lived Intangible Assets [Line Items]
Finite-Lived Intangible Assets, Gross		10,027	10,635
Finite-Lived Intangible Assets, Accumulated Amortization		$ (1,283)	$ (1,019)
Eagle Ford Gathering System [Member]
Finite-Lived Intangible Assets [Line Items]
Acquired Finite-lived Intangible Asset, Weighted-Average Period before Renewal or Extension	10 years
Williams Partners [Member]
Finite-Lived Intangible Assets [Line Items]
Acquired Finite-lived Intangible Assets, Weighted Average Useful Life	30 years

Accrued Liabilities Table (Deta

Accrued Liabilities Table (Details) - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016
Accrued Liabilities, Current [Abstract]
Deferred income	$ 361	$ 338
Interest on debt	267	310
Employee costs	202	223
Refundable deposits	0	160
Property taxes	63	55
Asset retirement obligations	53	61
Other, including other loss contingencies	221	301
Other accrued liabilities	$ 1,167	$ 1,448

Accrued Liabilities Accrued Lia

Accrued Liabilities Accrued Liabilities Narrative (Details) $ in Millions	12 Months Ended
	Dec. 31, 2017USD ($)
Hillabee Expansion Project [Member]
Deferred Revenue Arrangement [Line Items]
Deferred Revenue, Additions	$ 240

Long-Term Debt (Details)

Long-Term Debt (Details) - USD ($) $ in Millions		Dec. 31, 2017	Sep. 30, 2017	Jul. 03, 2017	Jun. 05, 2017	Apr. 15, 2017	Apr. 03, 2017	Feb. 23, 2017	Feb. 01, 2017	Dec. 31, 2016	Apr. 15, 2016	Jan. 22, 2016
Long-term Debt
Debt issuance costs		$ (122)								$ (119)
Net unamortized debt premium (discount)		(24)		$ (3)				$ (30)		88
Total long-term debt, including current portion		20,935								23,409
Long-term debt due within one year		(501)								(785)
Long-term debt		20,434								22,624
Transcontinental Gas Pipe Line Company, LLC [Member]
Long-term Debt
Other financing obligation		231	$ 237							0
Transcontinental Gas Pipe Line Company, LLC [Member] | 6.4% Senior Unsecured Notes due 2016 [Member]
Long-term Debt
Long-term debt interest rate											6.40%
Transcontinental Gas Pipe Line Company, LLC [Member] | 6.05% Senior Unsecured Notes due 2018 [Member]
Long-term Debt
Long-term debt		$ 250								250
Long-term debt interest rate		6.05%
Transcontinental Gas Pipe Line Company, LLC [Member] | 7.08% Debentures due 2026 [Member]
Long-term Debt
Long-term debt		$ 8								8
Long-term debt interest rate		7.08%
Transcontinental Gas Pipe Line Company, LLC [Member] | 7.25% Debentures due 2026 [Member]
Long-term Debt
Long-term debt		$ 200								200
Long-term debt interest rate		7.25%
Transcontinental Gas Pipe Line Company, LLC [Member] | 7.85% Senior Unsecured Notes Due 2026 [Member]
Long-term Debt
Long-term debt		$ 1,000								1,000
Long-term debt interest rate		7.85%										7.85%
Transcontinental Gas Pipe Line Company, LLC [Member] | 5.4% Senior Unsecured Notes due 2041 [Member]
Long-term Debt
Long-term debt		$ 375								375
Long-term debt interest rate		5.40%
Transcontinental Gas Pipe Line Company, LLC [Member] | 4.45% Senior Unsecured Notes due 2042 [Member]
Long-term Debt
Long-term debt		$ 400								400
Long-term debt interest rate		4.45%
Northwest Pipeline LLC [Member] | 5.95% Senior Unsecured Notes due 2017 [Member]
Long-term Debt
Long-term debt		$ 0								$ 185
Long-term debt interest rate						5.95%				5.95%
Northwest Pipeline LLC [Member] | 6.05% Senior Unsecured Notes due 2018 [Member]
Long-term Debt
Long-term debt		$ 250								$ 250
Long-term debt interest rate		6.05%
Northwest Pipeline LLC [Member] | 7.125% Debentures due 2025 [Member]
Long-term Debt
Long-term debt		$ 85								85
Long-term debt interest rate		7.125%
Northwest Pipeline LLC [Member] | 4% Senior Unsecured Notes Due 2027 [Member]
Long-term Debt
Long-term debt		$ 250								0
Long-term debt interest rate		4.00%					4.00%
Williams Partners L.P. [Member]
Long-term Debt
Credit facility loans	[1]	$ 0
Williams Partners L.P. [Member] | 7.25% Senior Unsecured Notes due 2017 [Member]
Long-term Debt
Long-term debt		0								$ 600
Long-term debt interest rate									7.25%	7.25%
Williams Partners L.P. [Member] | 5.25% Senior Unsecured Notes due 2020 [Member]
Long-term Debt
Long-term debt		$ 1,500								$ 1,500
Long-term debt interest rate		5.25%
Williams Partners L.P. [Member] | 4.125% Senior Unsecured Notes due 2020 [Member]
Long-term Debt
Long-term debt		$ 600								600
Long-term debt interest rate		4.125%
Williams Partners L.P. [Member] | 4% Senior Unsecured Notes due 2021 [Member]
Long-term Debt
Long-term debt		$ 500								500
Long-term debt interest rate		4.00%
Williams Partners L.P. [Member] | 3.6% Senior Unsecured Notes due 2022 [Member]
Long-term Debt
Long-term debt		$ 1,250								1,250
Long-term debt interest rate		3.60%
Williams Partners L.P. [Member] | 3.35% Senior Unsecured Notes due 2022 [Member]
Long-term Debt
Long-term debt		$ 750								750
Long-term debt interest rate		3.35%
Williams Partners L.P. [Member] | 6.125% Senior Unsecured Notes due 2022 [Member]
Long-term Debt
Long-term debt		$ 0								$ 750
Long-term debt interest rate										6.125%
Williams Partners L.P. [Member] | 4.5% Senior Unsecured Notes due 2023 [Member]
Long-term Debt
Long-term debt		$ 600								$ 600
Long-term debt interest rate		4.50%
Williams Partners L.P. [Member] | 4.875% Senior Unsecured Notes due 2023 [Member]
Long-term Debt
Long-term debt		$ 0								$ 1,400
Long-term debt interest rate										4.875%
Williams Partners L.P. [Member] | 4.3% Senior Unsecured Notes Due 2024 [Member]
Long-term Debt
Long-term debt		$ 1,000								$ 1,000
Long-term debt interest rate		4.30%
Williams Partners L.P. [Member] | 4.875% Senior Unsecured Notes due 2024 [Member]
Long-term Debt
Long-term debt		$ 750								750
Long-term debt interest rate		4.875%
Williams Partners L.P. [Member] | 3.9% Senior Unsecured Notes due 2025 [Member]
Long-term Debt
Long-term debt		$ 750								750
Long-term debt interest rate		3.90%
Williams Partners L.P. [Member] | 4% Senior Unsecured Notes due 2025 [Member]
Long-term Debt
Long-term debt		$ 750								750
Long-term debt interest rate		4.00%
Williams Partners L.P. [Member] | 3.75% Senior Unsecured Notes Due 2027 [Member]
Long-term Debt
Long-term debt interest rate		3.75%
Williams Partners L.P. [Member] | 6.3% Senior Unsecured Notes due 2040 [Member]
Long-term Debt
Long-term debt		$ 1,250								1,250
Long-term debt interest rate		6.30%
Williams Partners L.P. [Member] | 5.8% Senior Unsecured Notes due 2043 [Member]
Long-term Debt
Long-term debt		$ 400								400
Long-term debt interest rate		5.80%
Williams Partners L.P. [Member] | 5.4% Senior Unsecured Notes Due 2044 [Member]
Long-term Debt
Long-term debt		$ 500								500
Long-term debt interest rate		5.40%
Williams Partners L.P. [Member] | 4.9% Senior Unsecured Notes due 2045 [Member]
Long-term Debt
Long-term debt		$ 500								500
Long-term debt interest rate		4.90%
Williams Partners L.P. [Member] | 5.1% Senior Unsecured Notes due 2045 [Member]
Long-term Debt
Long-term debt		$ 1,000								1,000
Long-term debt interest rate		5.10%
Williams Partners L.P. [Member] | Variable Interest Term Loan due 2018 [Member]
Long-term Debt
Long-term debt		$ 0								850
Williams Partners L.P. [Member] | 6.125% Senior Unsecured Notes due 2022 [Member]
Long-term Debt
Long-term debt interest rate								6.125%
Williams Partners L.P. [Member] | 4.875% Senior Unsecured Notes due 2023 [Member]
Long-term Debt
Long-term debt interest rate				4.875%
Williams Partners L.P. [Member] | 3.75% Senior Unsecured Notes Due 2027 [Member]
Long-term Debt
Long-term debt		1,450								0
Long-term debt interest rate					3.75%
The Williams Companies, Inc. [Member]
Long-term Debt
Credit facility loans		270								775
The Williams Companies, Inc. [Member] | 7.875% Senior Unsecured Notes due 2021 [Member]
Long-term Debt
Long-term debt		$ 371								371
Long-term debt interest rate		7.875%
The Williams Companies, Inc. [Member] | 3.7% Senior Unsecured Notes due 2023 [Member]
Long-term Debt
Long-term debt		$ 850								850
Long-term debt interest rate		3.70%
The Williams Companies, Inc. [Member] | 4.55% Senior Unsecured Notes due 2024 [Member]
Long-term Debt
Long-term debt		$ 1,250								1,250
Long-term debt interest rate		4.55%
The Williams Companies, Inc. [Member] | 7.5% Debentures due 2031 [Member]
Long-term Debt
Long-term debt		$ 339								339
Long-term debt interest rate		7.50%
The Williams Companies, Inc. [Member] | 7.75% Senior Unsecured Notes due 2031 [Member]
Long-term Debt
Long-term debt		$ 252								252
Long-term debt interest rate		7.75%
The Williams Companies, Inc. [Member] | 8.75% Senior Unsecured Notes due 2032 [Member]
Long-term Debt
Long-term debt		$ 445								445
Long-term debt interest rate		8.75%
The Williams Companies, Inc. [Member] | 5.75% Senior Unsecured Notes due 2044 [Member]
Long-term Debt
Long-term debt		$ 650								650
Long-term debt interest rate		5.75%
The Williams Companies, Inc. [Member] | Various - 7.625% to 10.25% Senior Unsecured Notes and Debentures due 2019 to 2027 Minimum Interest Rate [Member]
Long-term Debt
Long-term debt interest rate		7.625%
The Williams Companies, Inc. [Member] | Various - 5.5% to 10.25% Senior Unsecured Notes and Debentures due 2019 to 2033 Minimum Interest Rate [Member]
Long-term Debt
Long-term debt		$ 55								$ 55
The Williams Companies, Inc. [Member] | Various - 7.625% to 10.25% Senior Unsecured Notes and Debentures due 2019 to 2027 Maximum Interest Rate [Member]
Long-term Debt
Long-term debt interest rate		10.25%
[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.

Long-Term Debt Maturities (Deta

Long-Term Debt Maturities (Details) $ in Millions	Dec. 31, 2017USD ($)
Aggregate minimum maturities of long-term debt
2,018	$ 502
2,019	33
2,020	2,123
2,021	1,143
2,022	$ 2,003

Long-Term Debt Issuances and Re

Long-Term Debt Issuances and Retirements (Details) - USD ($) $ in Millions

Jul. 06, 2017

Jul. 03, 2017

Apr. 15, 2017

Feb. 23, 2017

Feb. 01, 2017

Jun. 15, 2016

Apr. 15, 2016

Sep. 30, 2017

Dec. 31, 2017

Dec. 31, 2016

Dec. 31, 2015

Jun. 05, 2017

Apr. 03, 2017

Jan. 22, 2016

Debt Instrument [Line Items]

Repayments of Long-term Debt

$ 5,925

$ 7,091

$ 6,516

Williams Partners L.P. [Member] | Variable interest Rate [Member]

Debt Instrument [Line Items]

Extinguishment of Debt, Amount

$ 850

Williams Partners L.P. [Member] | 6.125% Senior Unsecured Notes due 2022 [Member]

Debt Instrument [Line Items]

Extinguishment of Debt, Amount

$ 750

Long-term debt interest rate

6.125%

Williams Partners L.P. [Member] | 3.75% Senior Unsecured Notes Due 2027 [Member]

Debt Instrument [Line Items]

Long-term debt face amount

$ 1,450

Long-term debt interest rate

3.75%

Williams Partners L.P. [Member] | 4.875% Senior Unsecured Notes due 2023 [Member]

Debt Instrument [Line Items]

Extinguishment of Debt, Amount

$ 1,400

Long-term debt interest rate

4.875%

The Williams Companies, Inc. [Member] | 4.55% Senior Unsecured Notes due 2024 [Member]

Debt Instrument [Line Items]

Long-term debt interest rate

4.55%

The Williams Companies, Inc. [Member] | 5.75% Senior Unsecured Notes due 2044 [Member]

Debt Instrument [Line Items]

Long-term debt interest rate

5.75%

Williams Partners L.P. [Member] | 3.9% Senior Unsecured Notes due 2025 [Member]

Debt Instrument [Line Items]

Long-term debt interest rate

3.90%

Williams Partners L.P. [Member] | 4.9% Senior Unsecured Notes due 2045 [Member]

Debt Instrument [Line Items]

Long-term debt interest rate

4.90%

Williams Partners L.P. [Member] | 4.3% Senior Unsecured Notes Due 2024 [Member]

Debt Instrument [Line Items]

Long-term debt interest rate

4.30%

Williams Partners L.P. [Member] | 5.4% Senior Unsecured Notes Due 2044 [Member]

Debt Instrument [Line Items]

Long-term debt interest rate

5.40%

Williams Partners L.P. [Member] | 4.5% Senior Unsecured Notes due 2023 [Member]

Debt Instrument [Line Items]

Long-term debt interest rate

4.50%

Williams Partners L.P. [Member] | 5.8% Senior Unsecured Notes due 2043 [Member]

Debt Instrument [Line Items]

Long-term debt interest rate

5.80%

Williams Partners L.P. [Member] | 3.6% Senior Unsecured Notes due 2022 [Member]

Debt Instrument [Line Items]

Long-term debt interest rate

3.60%

Williams Partners L.P. [Member] | 4% Senior Unsecured Notes due 2025 [Member]

Debt Instrument [Line Items]

Long-term debt interest rate

4.00%

Williams Partners L.P. [Member] | 5.1% Senior Unsecured Notes due 2045 [Member]

Debt Instrument [Line Items]

Long-term debt interest rate

5.10%

Williams Partners L.P. [Member] | 6.125% Senior Unsecured Notes due 2022 [Member]

Debt Instrument [Line Items]

Long-term debt interest rate

6.125%

Williams Partners L.P. [Member] | 7.25% Senior Unsecured Notes due 2017 [Member]

Debt Instrument [Line Items]

Extinguishment of Debt, Amount

$ 600

Long-term debt interest rate

7.25%

7.25%

Williams Partners L.P. [Member] | 3.75% Senior Unsecured Notes Due 2027 [Member]

Debt Instrument [Line Items]

Long-term debt interest rate

3.75%

Williams Partners L.P. [Member] | 4.875% Senior Unsecured Notes due 2023 [Member]

Debt Instrument [Line Items]

Long-term debt interest rate

4.875%

Northwest Pipeline LLC [Member] | 7% Senior Unsecured Notes due 2016 [Member]

Debt Instrument [Line Items]

Extinguishment of Debt, Amount

$ 175

Long-term debt interest rate

7.00%

Northwest Pipeline LLC [Member] | 4% Senior Unsecured Notes Due 2027 [Member]

Debt Instrument [Line Items]

Long-term debt face amount

$ 250

Long-term debt interest rate

4.00%

4.00%

Northwest Pipeline LLC [Member] | 5.95% Senior Unsecured Notes due 2017 [Member]

Debt Instrument [Line Items]

Extinguishment of Debt, Amount

$ 185

Long-term debt interest rate

5.95%

5.95%

Transcontinental Gas Pipe Line Company, LLC [Member]

Debt Instrument [Line Items]

Capitalized Construction Costs

100.00%

Other Long-term Debt, Noncurrent

$ 237

$ 231

$ 0

Debt Instrument, Term

35 years

Transcontinental Gas Pipe Line Company, LLC [Member] | 7.85% Senior Unsecured Notes Due 2026 [Member]

Debt Instrument [Line Items]

Long-term debt face amount

$ 1,000

Long-term debt interest rate

7.85%

7.85%

Transcontinental Gas Pipe Line Company, LLC [Member] | 6.4% Senior Unsecured Notes due 2016 [Member]

Debt Instrument [Line Items]

Extinguishment of Debt, Amount

$ 200

Long-term debt interest rate

6.40%

Credit Facilities and Commercia

Credit Facilities and Commercial Paper (Details) - USD ($) $ in Millions		Feb. 02, 2015	Sep. 30, 2017	Dec. 31, 2017		Feb. 20, 2018	Dec. 31, 2016
Credit Facility and Commercial Paper [Line Items]
Commercial paper, outstanding				$ 0			$ 93
Williams Partners L.P. [Member] | Commercial paper [Member]
Credit Facility and Commercial Paper [Line Items]
Commercial paper, outstanding				0
Williams Companies Inc [Member]
Credit Facility and Commercial Paper [Line Items]
Credit facility, capacity		$ 1,500		1,500
Credit facility, loans outstanding				270			775
Additional amount by which credit facility can be increased		$ 500
Maximum ratio of debt to EBITDA		5
Maximum ratio of debt to EBITDA after acquisition		5.5
Williams Companies Inc [Member] | Subsequent Event [Member]
Credit Facility and Commercial Paper [Line Items]
Credit facility, loans outstanding						$ 0
Williams Companies Inc [Member] | Swingline Loan [Member]
Credit Facility and Commercial Paper [Line Items]
Credit facility, capacity		$ 50
Williams Companies Inc [Member] | Letters of credit [Member]
Credit Facility and Commercial Paper [Line Items]
Credit facility, capacity		675
Williams Companies Inc [Member] | Letters Of Credit Under Certain Bilateral Bank Agreements [Member]
Credit Facility and Commercial Paper [Line Items]
Credit facility, letters of credit outstanding				13
Williams Partners L.P. [Member]
Credit Facility and Commercial Paper [Line Items]
Credit facility, capacity		3,500		3,500	[1]
Credit facility, loans outstanding	[1]			$ 0
Additional amount by which credit facility can be increased		$ 500
Maximum ratio of debt to EBITDA		5
Williams Partners L.P. [Member] | Subsequent Event [Member]
Credit Facility and Commercial Paper [Line Items]
Credit facility, loans outstanding						$ 0
Williams Partners L.P. [Member] | Rate addition to London interbank offered rate (LIBOR) [Member]
Credit Facility and Commercial Paper [Line Items]
Credit facility, basis spread on variable rate		1.00%
Williams Partners L.P. [Member] | Swingline Loan [Member]
Credit Facility and Commercial Paper [Line Items]
Credit facility, capacity		$ 150
Williams Partners L.P. [Member] | Commercial paper [Member]
Credit Facility and Commercial Paper [Line Items]
Credit facility, capacity		3,000
Commercial paper, outstanding							$ 93
Commercial paper, weighted average interest rate							1.06%
Commercial paper, maximum maturity				397 days
Williams Partners L.P. [Member] | Letters of credit [Member]
Credit Facility and Commercial Paper [Line Items]
Credit facility, capacity		1,125
Williams Partners L.P. [Member] | Letters Of Credit Under Certain Bilateral Bank Agreements [Member]
Credit Facility and Commercial Paper [Line Items]
Credit facility, letters of credit outstanding				$ 1
Transcontinental Gas Pipe Line Company, LLC [Member]
Credit Facility and Commercial Paper [Line Items]
Credit facility, capacity		$ 500
Commercial paper, maximum maturity			35 years
Maximum ratio of debt to capitalization		65.00%
Northwest Pipeline LLC [Member]
Credit Facility and Commercial Paper [Line Items]
Credit facility, capacity		$ 500
Maximum ratio of debt to capitalization		65.00%
Acquisition [Member] | Williams Partners L.P. [Member]
Credit Facility and Commercial Paper [Line Items]
Maximum ratio of debt to EBITDA after acquisition		5.5
[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.

Cash Payments For Interest (Net

Cash Payments For Interest (Net of Amounts Capitalized) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Debt Disclosure [Abstract]
Cash payments for interest (net of amounts capitalized)	$ 1,110	$ 1,152	$ 1,023

Restricted Net Assets of Subsid

Restricted Net Assets of Subsidiaries (Details) $ in Billions	Dec. 31, 2017USD ($)
Debt Disclosure [Abstract]
Amount of restricted net assets for consolidated and unconsolidated subsidiaries	$ 16
Restricted net assets threshold	25.00%

Leases-Lessee (Details)

Leases-Lessee (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Future minimum annual rentals under noncancelable operating leases
2,018	$ 43
2,019	41
2,020	33
2,021	33
2,022	29
Thereafter	137
Total	316
Operating leases [Abstract]
Total rent expense	$ 62	$ 64	$ 69

Stockholders' Equity (Details)

Stockholders' Equity (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Millions	Feb. 21, 2018	Feb. 01, 2017	Jan. 31, 2017	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Jan. 13, 2017
Stockholders' Equity (Textuals) [Abstract]
Common Stock, Dividends, Per Share, Declared				$ 1.20	$ 1.6800	$ 2.45
Stock Issued During Period, Shares, New Issues		9,750	65,000
Equity Issuance, Per Share Amount							$ 29
Proceeds from Issuance of Common Stock		$ 2,100		$ 2,131	$ 9	$ 27
Accumulated Other Comprehensive Income (Loss) [Line Items]
Total, Beginning Balance			$ (339)	(339)
Other comprehensive income (loss)				100	172	(171)
Total, Ending Balance				(238)	(339)
Accumulated Other Comprehensive Income (Loss) [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Total, Beginning Balance			(339)	(339)
Other Comprehensive Income (Loss), before Reclassifications, Net of Tax				39
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax				62
Other comprehensive income (loss)				101	103	$ (101)
Total, Ending Balance				(238)	(339)
Accumulated Net Gain (Loss) from Designated or Qualifying Cash Flow Hedges [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Total, Beginning Balance			0	0
Other Comprehensive Income (Loss), before Reclassifications, Net of Tax				(6)
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax				4
Other comprehensive income (loss)				(2)
Total, Ending Balance				(2)	0
Foreign currency translation [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Total, Beginning Balance			(2)	(2)
Other Comprehensive Income (Loss), before Reclassifications, Net of Tax				1
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax				0
Other comprehensive income (loss)				1
Total, Ending Balance				(1)	(2)
Accumulated Defined Benefit Plans Adjustment [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Total, Beginning Balance			$ (337)	(337)
Other Comprehensive Income (Loss), before Reclassifications, Net of Tax				44
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax				58
Other comprehensive income (loss)				102
Total, Ending Balance				$ (235)	$ (337)
Subsequent Event [Member]
Stockholders' Equity (Textuals) [Abstract]
Common Stock, Dividends, Per Share, Declared	$ 0.34

Stockholders' Equity Stockholde

Stockholders' Equity Stockholders' Equity Reclassifications from AOCI (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Total cash flow hedges, energy commodity contract reclassifications	$ 535	$ (375)	$ (1,713)
Provision (benefit) for income taxes	(1,974)	(25)	(399)
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest	2,509	(350)	(1,314)
Net Income (Loss) Attributable to Noncontrolling Interest	335	$ 74	$ (743)
Accumulated Net Gain (Loss) from Designated or Qualifying Cash Flow Hedges [Member]
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax	4
Accumulated Defined Benefit Plans Adjustment [Member]
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax	58
Foreign currency translation [Member]
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax	0
Reclassification out of Accumulated Other Comprehensive Income [Member]
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Reclassification from Accumulated Other Comprehensive Income, Current Period, before Tax	100
Provision (benefit) for income taxes	(36)
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest	64
Net Income (Loss) Attributable to Noncontrolling Interest	(2)
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax	62
Reclassification out of Accumulated Other Comprehensive Income [Member] | Accumulated Defined Benefit Plans Adjustment [Member]
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Amortization of prior service (credit) inlcuded in net periodic benefit cost	(5)
Amortization of actuarial (gain) loss included in net periodic benefit cost	98
Reclassification out of Accumulated Other Comprehensive Income [Member] | Energy Commodity Contract [Member] | Accumulated Net Gain (Loss) from Designated or Qualifying Cash Flow Hedges [Member]
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Product sales	$ 7

Equity-Based Compensation (Deta

Equity-Based Compensation (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Millions		12 Months Ended
		Dec. 31, 2017		Dec. 31, 2016	Dec. 31, 2015	May 22, 2014	May 20, 2010	May 17, 2007
Williams Companies Incentive Plan [Member]
Equity-Based Compensation (Textuals) [Abstract]
Shares reserved for issuance		26,000				10,000	11,000	19,000
Shares available for future grants		15,000
Equity-based compensation expense		$ 70		$ 53	$ 56
Tax benefit from equity-based compensation expense		17		$ 20	21
Employee Service Share-based Compensation, Nonvested Awards, Compensation Cost Not yet Recognized [Abstract]
Unrecognized equity-based compensation expense		$ 61
Unrecognized equity-based compensation expense, Weighted-average period of recognition in years		1 year 10 months
Williams Companies Incentive Plan [Member] | Stock options [Member]
Employee Service Share-based Compensation, Nonvested Awards, Compensation Cost Not yet Recognized [Abstract]
Unrecognized equity-based compensation expense - Stock Options		$ 4
Rollforward of stock option activity and related information
Options Outstanding, Beginning Balance		6,200
Options, Granted		1,000
Options, Exercised		(500)
Options, Cancelled		(100)
Options Outstanding, Ending Balance		6,600		6,200
Options Exercisable at Period End		5,100
Options, Aggregate Intrinsic Value, Ending Balance		$ 23
Options, Aggregate Intrinsic Value, Exercisable at Period End		19
Total intrinsic value of options exercised		4		$ 2	37
Tax benefits realized on options exercised		1		1	13
Cash received from the exercise of options		$ 7		$ 4	$ 20
Stock Options Outstanding, Weighted Average Remaining Contractual Life		5 years
Stock Options Exercisable, Weighted Average Remaining Contractual Life		4 years
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding, Weighted Average Exercise Price [Abstract]
Options, Weighted Average Exercise Price, Beginning Balance		$ 31.32
Options, Weighted Average Exercise Price, Granted		28.85
Options, Weighted Average Exercise Price, Exercised		21.33
Options, Weighted Average Exercise Price, Cancelled		36.75
Options, Weighted Average Exercise Price, Ending Balance		31.53		$ 31.32
Options, Weighted Average Exercise Price, Exercisable at Period End		31.85
Estimated fair value at date of grant of options for common stock granted
Weighted-average grant date fair value of options for our common stock granted during the year, per share		$ 6.61		$ 7.90	$ 7.61
Weighted-average assumptions:
Dividend yield		4.20%		3.20%	4.80%
Volatility		35.10%		44.70%	27.80%
Risk-free interest rate		2.10%		1.20%	1.80%
Expected life (years)		6 years		6 years	6 years
Duration Of Base Term For Peer Group Historical Volatility Measurement		10 years
Williams Companies Incentive Plan [Member] | Nonvested Restricted Stock Units [Member]
Equity-Based Compensation (Textuals) [Abstract]
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Period		3 years
Employee Service Share-based Compensation, Nonvested Awards, Compensation Cost Not yet Recognized [Abstract]
Unrecognized equity-based compensation expense - Restricted Stock Units		$ 57
Rollforward of nonvested restricted stock unit activity and related information
Restricted Stock Units, Nonvested shares, Beginning Balance		3,900
Restricted Stock Units, Granted		2,000
Restricted Stock Units, Forfeited		(800)
Restricted Stock Units, Vested		(900)
Restricted Stock Units, Nonvested shares, Ending Balance		4,200		3,900
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value [Abstract]
Restricted Stock Units, Nonvested, Weighted-Average Fair Value, Beginning Balance	[1]	$ 35.19
Weighted-average grant date fair value of restricted stock units granted during the year, per share		29.47	[1]	$ 26.51	$ 40.15
Restricted Stock Units, Forfeited, Weighted-Average Fair Value	[1]	39.21
Restricted Stock Units, Vested, Weighted-Average Fair Value	[1]	38.30
Restricted Stock Units, Nonvested, Weighted-Average Fair Value, Ending Balance	[1]	$ 31.02		$ 35.19
Restricted Stock Units, Vested in Period, Fair Value		$ 33		$ 32	$ 42
Williams Companies Incentive Plan [Member] | Performance Shares [Member]
Rollforward of nonvested restricted stock unit activity and related information
Performance based nonvested restricted stock units as a percent of total nonvested restricted stock units outstanding		31.00%
Williams Companies Incentive Plan [Member] | Performance Shares [Member] | Minimum [Member]
Rollforward of nonvested restricted stock unit activity and related information
Range of vested shares based on extent to which certain financial targets are achieved		0.00%
Williams Companies Incentive Plan [Member] | Performance Shares [Member] | Maximum [Member]
Rollforward of nonvested restricted stock unit activity and related information
Range of vested shares based on extent to which certain financial targets are achieved		200.00%
Employee Stock Purchase Plan [Member]
Equity-Based Compensation (Textuals) [Abstract]
Shares reserved for issuance						1,600		2,000
Shares available for future grants		1,100
No. of shares purchases by employees		272
Average price of shares purchased		$ 25.83
Williams Partners Long Term Incentive Plan [Member] | Nonvested Restricted Stock Units [Member]
Equity-Based Compensation (Textuals) [Abstract]
Equity-based compensation expense		$ 8		20	29
Employee Service Share-based Compensation, Nonvested Awards, Compensation Cost Not yet Recognized [Abstract]
Unrecognized equity-based compensation expense - Restricted Stock Units		$ 1
Rollforward of nonvested restricted stock unit activity and related information
Restricted Stock Units, Granted		0
Restricted Stock Units, Nonvested shares, Ending Balance		76
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value [Abstract]
Restricted Stock Units, Vested in Period, Fair Value		$ 24		$ 34	$ 5
[1]	Performance-based restricted stock units are valued utilizing a Monte Carlo valuation method using measures of total shareholder return. All other restricted stock units are valued at the grant-date market price. Restricted stock units generally vest after three years.

Fair Value Measurements Recurri

Fair Value Measurements Recurring Measurements and Additional (Details) - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016
Additional disclosures:
Fair Value, Level 1 to level 2 Transfers, Amount	$ 0	$ 0
Fair Value, Level 2 to level 1 Transfers, Amount	0	0
Wiltel Guarantee [Member]
Additional disclosures:
Guarantor Obligations, Maximum Exposure, Undiscounted	30
Carrying Amount [Member]
Additional disclosures:
Other receivables	7	15
Long-term debt, including current portion	(20,935)	(23,409)
Guarantees	(43)	(44)
Fair Value [Member]
Additional disclosures:
Other receivables	7	15
Long-term debt, including current portion	(23,005)	(24,090)
Guarantees	(30)	(30)
Level 1 [Member]
Additional disclosures:
Other receivables	7	15
Long-term debt, including current portion	0	0
Guarantees	0	0
Level 2 [Member]
Additional disclosures:
Other receivables	0	0
Long-term debt, including current portion	(23,005)	(24,090)
Guarantees	(14)	(14)
Level 3 [Member]
Additional disclosures:
Other receivables	0	0
Long-term debt, including current portion	0	0
Guarantees	(16)	(16)
Fair Value, Measurements, Recurring [Member] | Carrying Amount [Member]
Measured on a recurring basis:
ARO Trust investments	135	96
Fair Value, Measurements, Recurring [Member] | Carrying Amount [Member] | Designated as Hedging Instrument [Member]
Measured on a recurring basis:
Energy derivatives assets		2
Energy derivatives liabilities	(3)
Fair Value, Measurements, Recurring [Member] | Carrying Amount [Member] | Not Designated as Hedging Instrument [Member]
Measured on a recurring basis:
Energy derivatives assets		1
Energy derivatives liabilities	(3)	(6)
Fair Value, Measurements, Recurring [Member] | Fair Value [Member]
Measured on a recurring basis:
ARO Trust investments	135	96
Fair Value, Measurements, Recurring [Member] | Fair Value [Member] | Designated as Hedging Instrument [Member]
Measured on a recurring basis:
Energy derivatives assets		2
Energy derivatives liabilities	(3)
Fair Value, Measurements, Recurring [Member] | Fair Value [Member] | Not Designated as Hedging Instrument [Member]
Measured on a recurring basis:
Energy derivatives assets		1
Energy derivatives liabilities	(3)	(6)
Fair Value, Measurements, Recurring [Member] | Level 1 [Member]
Measured on a recurring basis:
ARO Trust investments	135	96
Fair Value, Measurements, Recurring [Member] | Level 1 [Member] | Designated as Hedging Instrument [Member]
Measured on a recurring basis:
Energy derivatives assets		0
Energy derivatives liabilities	(2)
Fair Value, Measurements, Recurring [Member] | Level 1 [Member] | Not Designated as Hedging Instrument [Member]
Measured on a recurring basis:
Energy derivatives assets		0
Energy derivatives liabilities	0	0
Fair Value, Measurements, Recurring [Member] | Level 2 [Member]
Measured on a recurring basis:
ARO Trust investments	0	0
Fair Value, Measurements, Recurring [Member] | Level 2 [Member] | Designated as Hedging Instrument [Member]
Measured on a recurring basis:
Energy derivatives assets		2
Energy derivatives liabilities	(1)
Fair Value, Measurements, Recurring [Member] | Level 2 [Member] | Not Designated as Hedging Instrument [Member]
Measured on a recurring basis:
Energy derivatives assets		0
Energy derivatives liabilities	0	0
Fair Value, Measurements, Recurring [Member] | Level 3 [Member]
Measured on a recurring basis:
ARO Trust investments	0	0
Fair Value, Measurements, Recurring [Member] | Level 3 [Member] | Designated as Hedging Instrument [Member]
Measured on a recurring basis:
Energy derivatives assets		0
Energy derivatives liabilities	0
Fair Value, Measurements, Recurring [Member] | Level 3 [Member] | Not Designated as Hedging Instrument [Member]
Measured on a recurring basis:
Energy derivatives assets		1
Energy derivatives liabilities	$ (3)	$ (6)

Fair Value Measurements Nonrecu

Fair Value Measurements Nonrecurring Measurements (Details) - USD ($) $ in Millions

3 Months Ended

9 Months Ended

12 Months Ended

Sep. 30, 2017

Jun. 30, 2017

[5]

Dec. 31, 2016

Jun. 30, 2016

Mar. 31, 2016

Dec. 31, 2015

Sep. 30, 2015

Jun. 30, 2015

[3]

Sep. 30, 2015

Dec. 31, 2017

Dec. 31, 2016

Dec. 31, 2015

Fair Value Assets Measured On Nonrecurring Basis [Abstract]

Impairment of goodwill

$ 0

$ 0

$ 1,098

Impairment of equity-method investments

0

430

1,359

Other Asset Impairment Charges

1,248

873

209

Delaware Basin Gas Gathering System [Member]

Fair Value Assets Measured On Nonrecurring Basis [Abstract]

Impairment of equity-method investments

59

503

Appalachia Midstream Investments [Member]

Fair Value Assets Measured On Nonrecurring Basis [Abstract]

Impairment of equity-method investments

294

562

Fair Value, Measurements, Nonrecurring [Member] | Level 3 [Member] | Williams Partners [Member]

Fair Value Assets Measured On Nonrecurring Basis [Abstract]

Impairment of goodwill

$ 0

Fair Value, Measurements, Nonrecurring [Member] | Level 3 [Member] | Williams Partners [Member] | Minimum [Member]

Fair Value Assets Measured On Nonrecurring Basis [Abstract]

Discount rate

10.00%

Fair Value, Measurements, Nonrecurring [Member] | Level 3 [Member] | Williams Partners [Member] | Maximum [Member]

Fair Value Assets Measured On Nonrecurring Basis [Abstract]

Discount rate

13.00%

Fair Value, Measurements, Nonrecurring [Member] | Level 3 [Member] | Property, plant, and equipment, net [Member] | Williams Partners [Member]

Fair Value Assets Measured On Nonrecurring Basis [Abstract]

Fair value of property, plant, and equipment

$ 18

[1]

$ 13

[2]

$ 17

13

[2]

Fair Value, Measurements, Nonrecurring [Member] | Level 3 [Member] | Property, plant, and equipment, net [Member] | Other [Member]

Fair Value Assets Measured On Nonrecurring Basis [Abstract]

Fair value of property, plant, and equipment

$ 32

[4]

$ 18

$ 73

40

[6]

73

40

[6]

Fair Value, Measurements, Nonrecurring [Member] | Level 3 [Member] | Investments [Member]

Fair Value Assets Measured On Nonrecurring Basis [Abstract]

Fair value of investment

$ 0

58

58

Fair Value, Measurements, Nonrecurring [Member] | Level 3 [Member] | Investments [Member] | Williams Partners [Member]

Fair Value Assets Measured On Nonrecurring Basis [Abstract]

Fair value of investment

$ 1,295

[7]

$ 1,294

[8]

$ 4,017

[9]

$ 1,203

[10]

$ 1,203

[10]

1,295

[7]

4,017

[9]

Fair Value, Measurements, Nonrecurring [Member] | Level 3 [Member] | Investments [Member] | Williams Partners [Member] | Minimum [Member]

Fair Value Assets Measured On Nonrecurring Basis [Abstract]

Discount rate

13.00%

10.80%

Fair Value, Measurements, Nonrecurring [Member] | Level 3 [Member] | Investments [Member] | Williams Partners [Member] | Maximum [Member]

Fair Value Assets Measured On Nonrecurring Basis [Abstract]

Discount rate

13.30%

14.40%

Fair Value, Measurements, Nonrecurring [Member] | Level 3 [Member] | Investments [Member] | Williams Partners [Member] | Delaware Basin Gas Gathering System [Member]

Fair Value Assets Measured On Nonrecurring Basis [Abstract]

Discount rate

11.80%

Fair Value, Measurements, Nonrecurring [Member] | Level 3 [Member] | Investments [Member] | Williams Partners [Member] | Appalachia Midstream Investments [Member]

Fair Value Assets Measured On Nonrecurring Basis [Abstract]

Discount rate

10.20%

8.80%

Canadian Operations [Member] | Fair Value, Measurements, Nonrecurring [Member] | Level 3 [Member] | Assets Held For Sale [Member] | Williams Partners [Member]

Fair Value Assets Measured On Nonrecurring Basis [Abstract]

Assets Held-for-sale, Long Lived, Fair Value Disclosure

[11]

924

Canadian Operations [Member] | Fair Value, Measurements, Nonrecurring [Member] | Level 3 [Member] | Assets Held For Sale [Member] | Other [Member]

Fair Value Assets Measured On Nonrecurring Basis [Abstract]

Assets Held-for-sale, Long Lived, Fair Value Disclosure

[11]

206

Impairment Of Goodwill [Member] | Fair Value, Measurements, Nonrecurring [Member] | Level 3 [Member] | Williams Partners [Member]

Fair Value Assets Measured On Nonrecurring Basis [Abstract]

Impairment of goodwill

$ 1,098

Impairment Of Certain Assets [Member]

Fair Value Assets Measured On Nonrecurring Basis [Abstract]

Impairment of certain assets

873

209

Other Asset Impairment Charges

1,248

Impairment Of Certain Assets [Member] | Fair Value, Measurements, Nonrecurring [Member]

Fair Value Assets Measured On Nonrecurring Basis [Abstract]

Impairment of certain assets

[12]

23

70

31

Impairment Of Certain Assets [Member] | Fair Value, Measurements, Nonrecurring [Member] | Level 3 [Member]

Fair Value Assets Measured On Nonrecurring Basis [Abstract]

Impairment of certain assets

803

178

Other Asset Impairment Charges

$ 1,225

Impairment Of Certain Assets [Member] | Fair Value, Measurements, Nonrecurring [Member] | Level 3 [Member] | Williams Partners [Member]

Fair Value Assets Measured On Nonrecurring Basis [Abstract]

Impairment of certain assets

48

[1]

94

[2]

$ 20

Impairment Of Certain Assets [Member] | Fair Value, Measurements, Nonrecurring [Member] | Level 3 [Member] | Other [Member]

Fair Value Assets Measured On Nonrecurring Basis [Abstract]

Impairment of certain assets

$ 68

[4]

$ 23

$ 8

64

[6]

Impairment Of Certain Assets [Member] | Canadian Operations [Member] | Fair Value, Measurements, Nonrecurring [Member] | Level 3 [Member] | Williams Partners [Member]

Fair Value Assets Measured On Nonrecurring Basis [Abstract]

Disposal Group, Not Discontinued Operation, Loss (Gain) on Write-down

[11]

341

Impairment Of Certain Assets [Member] | Canadian Operations [Member] | Fair Value, Measurements, Nonrecurring [Member] | Level 3 [Member] | Other [Member]

Fair Value Assets Measured On Nonrecurring Basis [Abstract]

Disposal Group, Not Discontinued Operation, Loss (Gain) on Write-down

[11]

$ 406

Impairment Of Equity-Method Investments [Member] | Fair Value, Measurements, Nonrecurring [Member]

Fair Value Assets Measured On Nonrecurring Basis [Abstract]

Impairment of equity-method investments

$ 430

$ 1,359

Impairment Of Equity-Method Investments [Member] | Fair Value, Measurements, Nonrecurring [Member] | Level 3 [Member]

Fair Value Assets Measured On Nonrecurring Basis [Abstract]

Impairment of equity-method investments

$ 3

8

Impairment Of Equity-Method Investments [Member] | Fair Value, Measurements, Nonrecurring [Member] | Level 3 [Member] | Williams Partners [Member]

Fair Value Assets Measured On Nonrecurring Basis [Abstract]

Impairment of equity-method investments

$ 318

[7]

$ 109

[8]

890

[9]

$ 461

[10]

West G And P [Member] | Fair Value, Measurements, Nonrecurring [Member] | Level 3 [Member] | Williams Partners [Member]

Fair Value Assets Measured On Nonrecurring Basis [Abstract]

Impairment of goodwill

$ 0

Marcellus South [Member] | Fair Value, Measurements, Nonrecurring [Member] | Level 3 [Member] | Property Plant And Equipment, Net And Intangible Assets, Net Of Accumulated Amortization [Member] | Williams Partners [Member]

Fair Value Assets Measured On Nonrecurring Basis [Abstract]

Discount rate

11.10%

Property Plant And Equipment And Intangibles, Fair Value Disclosure

[13]

$ 21

Marcellus South [Member] | Impairment Of Certain Assets [Member] | Fair Value, Measurements, Nonrecurring [Member] | Level 3 [Member] | Williams Partners [Member]

Fair Value Assets Measured On Nonrecurring Basis [Abstract]

Other Asset Impairment Charges

[13]

$ 115

Mid Continent [Member] | Fair Value, Measurements, Nonrecurring [Member] | Level 3 [Member] | Property Plant And Equipment, Net And Intangible Assets, Net Of Accumulated Amortization [Member] | Williams Partners [Member]

Fair Value Assets Measured On Nonrecurring Basis [Abstract]

Discount rate

10.20%

Property Plant And Equipment And Intangibles, Fair Value Disclosure

[14]

$ 439

Mid Continent [Member] | Impairment Of Certain Assets [Member] | Fair Value, Measurements, Nonrecurring [Member] | Level 3 [Member] | Williams Partners [Member]

Fair Value Assets Measured On Nonrecurring Basis [Abstract]

Other Asset Impairment Charges

[14]

$ 1,019

[1]

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.

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

[4]

Relates to an NGL pipeline near the Houston Ship Channel region which we anticipate will be underutilized for the foreseeable future. The estimated fair value was primarily determined by using a market approach based on our analysis of observable inputs in the principal market.

[5]

Relates primarily to project development costs associated with an olefins pipeline project in the Gulf Coast region, the likelihood of completion of which is now considered remote. The estimated fair value of the remaining pipe and equipment considered a market approach based on our analysis of observable inputs in the principal market, as well as an estimate of replacement cost.

[6]

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.

[7]

Relates to Williams Partners’ previously held interest in Ranch Westex and multiple Appalachia Midstream Investments currently held. The historical carrying value of these equity-method investments was initially recorded based on estimated fair value during the third quarter of 2014 in conjunction with the acquisition of ACMP. We estimated the fair value of these Appalachia Midstream Investments using an income approach based on expected future cash flows and appropriate discount rates. The determination of estimated future cash flows involved significant assumptions regarding gathering volumes, rates, and related capital spending. The discount rate utilized for the Appalachia Midstream Investments evaluation was 10.2 percent and reflected an estimated cost of capital as impacted by market conditions and risks associated with the underlying businesses. In addition to utilizing an income approach, we also considered a market approach for certain Appalachia Midstream Investments and Ranch Westex based on an agreement reached in February 2017 to exchange our interests in DBJV and Ranch Westex for additional interests in certain Appalachia Midstream Investments and cash. (See Note 5 – Investing Activities).

[8]

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

[9]

Relates to Williams Partners’ previously held interest in DBJV, as well as equity-method investments in certain of the Appalachia Midstream Investments, UEOM, and Laurel Mountain, all of which are currently held. We estimated the fair value of these equity-method investments using an income approach based on expected future cash flows and appropriate discount rates. The determination of estimated future cash flows involved significant assumptions regarding gathering volumes and related capital spending. Discount rates utilized ranged from 10.8 percent to 14.4 percent and reflected further fourth-quarter 2015 increases in the estimated cost of capital, revised estimates of expected future cash flows, and risks associated with the underlying businesses.

[10]

Relates to Williams Partners’ previously held interest in DBJV and certain of the Appalachia Midstream Investments currently held. The historical carrying value of these equity-method investments was initially recorded based on estimated fair value during the third quarter of 2014 in conjunction with the acquisition of ACMP. We estimated the fair value of these equity-method investments using an income approach based on expected future cash flows and appropriate discount rates. The determination of estimated future cash flows involved significant assumptions regarding gathering volumes and related capital spending. Discount rates utilized were 11.8 percent and 8.8 percent for DBJV and certain of the Appalachia Midstream Investments, respectively, and reflected an estimated cost of capital as impacted by market conditions, and risks associated with the underlying businesses.

[11]

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 2 – Acquisitions and Divestitures).

[12]

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

[13]

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

[14]

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

Fair Value Measurements Concent

Fair Value Measurements Concentration of Credit Risk (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Concentration Risk [Line Items]
Trade accounts and other receivables	$ 976	$ 938
NGLs, natural gas, and related products and services [Member]
Concentration Risk [Line Items]
Trade accounts and other receivables	760	736
Transportation of natural gas and related products [Member]
Concentration Risk [Line Items]
Trade accounts and other receivables	212	187
Other Receivable [Member]
Concentration Risk [Line Items]
Trade accounts and other receivables	4	15
Chesapeake Energy Corporation [Member] | Customer Concentration Risk [Member] | Accounts receivable [Member] | Williams Partners [Member]
Concentration Risk [Line Items]
Trade accounts and other receivables	$ 176	$ 133
Chesapeake Energy Corporation [Member] | Customer Concentration Risk [Member] | Sales Revenue, Net [Member] | Williams Partners [Member]
Concentration Risk [Line Items]
Consolidated revenue, major customer, percentage	10.00%	14.00%	18.00%

Contingent Liabilities and Co87

Contingent Liabilities and Commitments (Details) - USD ($) $ in Millions	May 20, 2016	Dec. 31, 2017
Loss Contingencies [Line Items]
Accrued environmental loss liabilities		$ 38
Capital Addition Purchase Commitments [Member]
Loss Contingencies [Line Items]
Commitments for construction and acquisition of property, plant, and equipment		348
Energy Transfer Merger [Member]
Loss Contingencies [Line Items]
Loss contingency, damages sought, value	$ 1,480
Gas Pipeline [Member]
Loss Contingencies [Line Items]
Accrued environmental loss liabilities		7
Natural Gas Underground Storage Facilities [Member]
Loss Contingencies [Line Items]
Accrued environmental loss liabilities		8
Former Operations [Member]
Loss Contingencies [Line Items]
Accrued environmental loss liabilities		23
Maximum [Member] | Former Alaska Refinery [Member]
Loss Contingencies [Line Items]
Loss contingency, range of possible loss, maximum		$ 32

Segment Disclosures Geographic

Segment Disclosures Geographic Information (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Revenues from external customers:
Revenues from external customers	$ 8,031	$ 7,499	$ 7,360
Long-lived assets:
Long-lived assets	37,002	38,091	39,596
United States [Member]
Revenues from external customers:
Revenues from external customers	8,030	7,425	7,247
Long-lived assets:
Long-lived assets	37,002	38,091	38,016
Canada [Member]
Revenues from external customers:
Revenues from external customers	1	74	113
Long-lived assets:
Long-lived assets	$ 0	$ 0	$ 1,580

Segment Disclosures Recon from

Segment Disclosures Recon from Segment to Consolidated - Revenues (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Segment revenues [Line Items]
Service revenues	$ 5,312	$ 5,171	$ 5,164
Product sales	2,719	2,328	2,196
Total revenues	8,031	7,499	7,360
Other financial information:
Additions to long-lived assets	2,814	2,145	3,336
Proportional Modified Ebitda Equity Method Investments	795	754	699
Williams Partners [Member]
Segment revenues [Line Items]
Service revenues	5,291	5,140	5,134
Product sales	2,718	2,318	2,196
Other [Member]
Segment revenues [Line Items]
Service revenues	21	31	30
Product sales	1	10	0
Intersegment Eliminations [Member]
Segment revenues [Line Items]
Service revenues	(12)	(52)	(92)
Product sales	0	(16)	0
Total revenues	(12)	(68)	(92)
Other financial information:
Additions to long-lived assets	0	(1)	(12)
Proportional Modified Ebitda Equity Method Investments	0	0	0
Intersegment Eliminations [Member] | Williams Partners [Member]
Segment revenues [Line Items]
Service revenues	(1)	(33)	(1)
Product sales	0	0	0
Intersegment Eliminations [Member] | Other [Member]
Segment revenues [Line Items]
Service revenues	(11)	(19)	(91)
Product sales	0	(16)	0
Operating Segments [Member] | Williams Partners [Member]
Segment revenues [Line Items]
Service revenues	5,292	5,173	5,135
Product sales	2,718	2,318	2,196
Total revenues	8,010	7,491	7,331
Other financial information:
Additions to long-lived assets	2,792	2,102	2,960
Proportional Modified Ebitda Equity Method Investments	795	754	699
Operating Segments [Member] | Other [Member]
Segment revenues [Line Items]
Service revenues	32	50	121
Product sales	1	26	0
Total revenues	33	76	121
Other financial information:
Additions to long-lived assets	22	44	388
Proportional Modified Ebitda Equity Method Investments	$ 0	$ 0	$ 0

Segment Disclosures Recon fro90

Segment Disclosures Recon from Modified EBITDA to Net Income (Loss) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Reconciliation of Modified EBITDA to Net Income (Loss)
Modified EBITDA	$ 3,466	$ 3,322	$ 3,891
Accretion expense associated with asset retirement obligations for nonregulated operations	(33)	(31)	(28)
Depreciation and amortization expenses	(1,736)	(1,763)	(1,738)
Impairment of goodwill	0	0	(1,098)
Equity earnings (losses)	434	397	335
Impairment of equity-method investments	0	(430)	(1,359)
Other investing income (loss) – net	282	63	27
Proportional Modified Ebitda Equity Method Investments	(795)	(754)	(699)
Interest Expense	(1,083)	(1,179)	(1,044)
(Provision) benefit for income taxes	1,974	25	399
Net income (loss)	2,509	(350)	(1,314)
Intersegment Eliminations [Member]
Reconciliation of Modified EBITDA to Net Income (Loss)
Proportional Modified Ebitda Equity Method Investments	0	0	0
Operating Segments [Member] | Williams Partners [Member]
Reconciliation of Modified EBITDA to Net Income (Loss)
Modified EBITDA	3,616	3,864	4,003
Proportional Modified Ebitda Equity Method Investments	(795)	(754)	(699)
Operating Segments [Member] | Other [Member]
Reconciliation of Modified EBITDA to Net Income (Loss)
Modified EBITDA	(150)	(542)	(112)
Proportional Modified Ebitda Equity Method Investments	$ 0	$ 0	$ 0

Segment Disclosures Recon fro91

Segment Disclosures Recon from Segment to Consolidated - Assets and Investments (Details) - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016
Segment Reporting, Asset Reconciling Item [Line Items]
Total assets	$ 46,352	$ 46,835
Equity-method investments	6,552	6,701
Operating Segments [Member] | Williams Partners [Member]
Segment Reporting, Asset Reconciling Item [Line Items]
Total assets	45,903	46,265
Equity-method investments	6,552	6,701
Operating Segments [Member] | Other [Member]
Segment Reporting, Asset Reconciling Item [Line Items]
Total assets	589	685
Equity-method investments	0	0
Intersegment Eliminations [Member]
Segment Reporting, Asset Reconciling Item [Line Items]
Total assets	(140)	(115)
Equity-method investments	$ 0	$ 0

Schedule I - Condensed Financ92

Schedule I - Condensed Financial Information of Registrant (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Millions	Feb. 01, 2017	May 31, 2015	Dec. 31, 2017	Dec. 31, 2016		Dec. 31, 2015		Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Condensed Statement Of Comprehensive Income Parent Company Only [Abstract]
Equity earnings (losses)			$ 434	$ 397		$ 335
Interest incurred - external			(1,116)	(1,217)		(1,118)
Other income (expense) – net			(2)	74		102
Income (loss) before income taxes			535	(375)		(1,713)
Provision (benefit) for income taxes			(1,974)	(25)		(399)
Net income (loss) attributable to The Williams Companies, Inc.			$ 2,174	$ (424)		$ (571)
Basic earnings (loss) per common share:
Net income (loss)			$ 2.63	$ (0.57)		$ (0.76)
Weighted-average shares (thousands)			826,177	750,673		749,271
Diluted earnings (loss) per common share:
Net income (loss)			$ 2.62	$ (0.57)		$ (0.76)
Weighted-average shares (thousands)			828,518	750,673	[1]	749,271	[1]
Other comprehensive income (loss):
Other comprehensive income (loss)			$ 100	$ 172		$ (171)
Comprehensive Income (loss) attributable to The Williams Companies, Inc.			2,275	(321)		(672)
Assets, Current [Abstract]
Cash and cash equivalents			170	100		240		$ 899	$ 170	$ 100
Other current assets and deferred charges								191	216
Total current assets								2,179	1,462
Property, plant, and equipment – net								28,211	28,428
Other noncurrent assets								619	581
Total assets								46,352	46,835
Liabilities, Current [Abstract]
Accounts payable								978	623
Total current liabilities								2,646	2,949
Long-term debt								20,434	22,624
Deferred income taxes								3,147	4,238
Contingent liabilities and commitments
Equity: [Abstract]
Common stock								861	785
Total stockholders’ equity								9,656	4,643
Total liabilities and stockholders' equity								46,352	46,835
Condensed Statement Of Cash Flows Parent Company Only [Abstract]
Net Cash Provided (Used) by Operating Activities			2,556	3,680		2,708
FINANCING ACTIVITIES:
Proceeds from long-term debt			3,333	6,528		9,772
Payments of long-term debt			(5,925)	(7,091)		(6,516)
Proceeds from issuance of common stock	$ 2,100		2,131	9		27
Dividends paid			(992)	(1,261)		(1,836)
Other – net			(92)	(16)		(31)
Net cash provided (used) by financing activities			(2,460)	(3,194)		451
INVESTING ACTIVITIES:
Capital expenditures			(2,814)	(2,145)		(3,336)
Other – net			(17)	38		81
Net cash provided (used) by investing activities			633	(416)		(3,299)
Increase (decrease) in cash and cash equivalents			729	70		(140)
Cash and cash equivalents at beginning of year			170	100		240
Cash and cash equivalents at end of year			899	170		100
Parent Company [Member]
Condensed Statement Of Comprehensive Income Parent Company Only [Abstract]
Equity in earnings of consolidated subsidiaries			898	522		232
Interest incurred - external			(261)	(268)		(255)
Interest incurred - affiliate			(413)	(568)		(828)
Interest income - affiliate			0	0		6
Other income (expense) – net			(23)	(53)		(75)
Income (loss) before income taxes			201	(367)		(920)
Provision (benefit) for income taxes			(1,973)	57		(349)
Net income (loss) attributable to The Williams Companies, Inc.			$ 2,174	$ (424)		$ (571)
Basic earnings (loss) per common share:
Net income (loss)			$ 2.63	$ (0.57)		$ (0.76)
Weighted-average shares (thousands)			826,177	750,673		749,271
Diluted earnings (loss) per common share:
Net income (loss)			$ 2.62	$ (0.57)		$ (0.76)
Weighted-average shares (thousands)			828,518	750,673		749,271
Other comprehensive income (loss):
Equity in other comprehensive income (loss) of consolidated subsidiaries			$ (2)	$ 171		$ (204)
Other comprehensive income (loss) attributable to The Williams Companies, Inc.			102	1		33
Other comprehensive income (loss)			100	172		(171)
Other comprehensive income (loss) attributable to noncontrolling interests			(1)	69		(70)
Comprehensive Income (loss) attributable to The Williams Companies, Inc.			2,275	(321)		(672)
Assets, Current [Abstract]
Cash and cash equivalents			14	12		49		14	14	12
Other current assets and deferred charges								10	16
Total current assets								24	30
Investments in and advances to consolidated subsidiaries								25,268	22,359
Property, plant, and equipment – net								77	77
Other noncurrent assets								6	8
Total assets								25,375	22,474
Liabilities, Current [Abstract]
Accounts payable								20	27
Other current liabilities								187	169
Total current liabilities								207	196
Long-term debt								4,438	4,939
Notes payable - affiliates								7,763	8,171
Pension, other postretirement and other noncurrent liabilities								164	287
Deferred income taxes								3,147	4,238
Equity: [Abstract]
Common stock								861	785
Other stockholders' equity								8,795	3,858
Total stockholders’ equity								9,656	4,643
Total liabilities and stockholders' equity								25,375	22,474
Condensed Statement Of Cash Flows Parent Company Only [Abstract]
Net Cash Provided (Used) by Operating Activities			(648)	(827)		(1,181)
FINANCING ACTIVITIES:
Proceeds from long-term debt			1,635	2,280		2,097
Payments of long-term debt			(2,140)	(2,155)		(1,817)
Changes in notes payable to affiliates			(408)	9		2,211
Proceeds from issuance of common stock			2,131	9		27
Dividends paid			(992)	(1,261)		(1,836)
Other – net			(9)	(6)		(30)
Net cash provided (used) by financing activities			217	(1,124)		652
INVESTING ACTIVITIES:
Capital expenditures			(22)	(13)		(29)
Changes in investments in and advances to consolidated subsidiaries			453	1,966		521
Net cash provided (used) by investing activities			431	1,953		492
Increase (decrease) in cash and cash equivalents			0	2		(37)
Cash and cash equivalents at beginning of year			14	12		49
Cash and cash equivalents at end of year			14	14		12
Guarantees [Abstract]
Guarantor Obligations, Maximum Exposure, Undiscounted								305
Cash Dividends Received [Abstract]
Proceeds from Dividends Received			$ 1,900	$ 1,700		$ 1,800
Williams Partners [Member]
Condensed Financial Statements, Captions [Line Items]
Acquired Finite-lived Intangible Assets, Weighted Average Useful Life		30 years
Goodwill								$ 47	$ 47	$ 47
[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.

Schedule II Valuation and Quali

Schedule II Valuation and Qualifying Accounts (Details) - Deferred Tax Asset Valuation Allowance [Member] - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Valuation And Qualifying Accounts
Beginning Balance	[1]	$ 334	$ 190	$ 206
Additions Charged (Credited) To Cost and Expenses		(110)	144	(16)
Additions Other		0	0	0
Deductions		0	0	0
Ending Balance	[1]	$ 224	$ 334	$ 190
[1]	Deducted from related assets.