The Williams Companies, Inc. (WMB) 10-K 21 Feb 19 2018 FY Annual report Financial data

Document and Entity Information

Document and Entity Information - USD ($)	12 Months Ended
	Dec. 31, 2018	Feb. 15, 2019	Jun. 29, 2018
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, 2018
Amendment Flag	false
Document Fiscal Year Focus	2,018
Document Fiscal Period Focus	FY
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Entity Shell Company	false
Entity Small Business	false
Entity Emerging Growth Company	false
Entity Common Stock, Shares Outstanding		1,210,981,263
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Public Float			$ 21,489,112,717

Consolidated Statement of Opera

Consolidated Statement of Operations - USD ($) shares in Thousands, $ in Millions	12 Months Ended
	Dec. 31, 2018		Dec. 31, 2017	Dec. 31, 2016
Revenues:
Revenue from Contract with Customer, Excluding Assessed Tax	$ 8,604
Service revenues - commodity consideration (Note 1)	400		$ 0	$ 0
Total revenues	8,686		8,031	7,499
Costs and expenses:
Processing commodity expenses (Note 1)	137		0	0
Operating and maintenance expenses	1,507		1,576	1,592
Depreciation and amortization expenses	1,725		1,736	1,763
Selling, general, and administrative expenses	569		594	722
Impairment of certain assets (Note 17)	1,915		1,248	873
Gain on sale of certain assets (Note 3)	(692)		(1,095)	0
Regulatory Charges resulting From Tax Reform (Note 1)	(17)		674	0
Other (income) expense – net	67		71	135
Total costs and expenses	7,918		7,104	6,810
Operating income (loss)	768		927	689
Equity earnings (losses)	396		434	397
Impairment of equity-method investments (Note 17)	(32)		0	(430)
Other investing income (loss) – net	219		282	63
Interest incurred	(1,160)		(1,116)	(1,217)
Interest capitalized	48		33	38
Other income (expense) – net	92		(25)	85
Income (loss) before income taxes	331		535	(375)
Provision (benefit) for income taxes	138		(1,974)	(25)
Net income (loss)	193		2,509	(350)
Less: Net income (loss) attributable to noncontrolling interests	348		335	74
Amounts attributable to The Williams Companies, Inc.:
Net income (loss) attributable to The Williams Companies, Inc.	(155)		2,174	(424)
Preferred stock dividends (Note 15)	1		0	0
Net income (loss) available to common stockholders	$ (156)		$ 2,174	$ (424)
Basic earnings (loss) per common share:
Net income (loss)	$ (0.16)		$ 2.63	$ (0.57)
Weighted-average shares (thousands)	973,626		826,177	750,673
Diluted earnings (loss) per common share:
Net income (loss)	$ (0.16)		$ 2.62	$ (0.57)
Weighted-average shares (thousands)	973,626	[1]	828,518	750,673	[1]
Service [Member]
Revenues:
Revenue from Contract with Customer, Excluding Assessed Tax	$ 5,502		$ 5,312	$ 5,171
Product [Member]
Revenues:
Revenue from Contract with Customer, Excluding Assessed Tax	2,784		2,719	2,328
Oil and Gas, Purchased [Member]
Costs and expenses:
Product costs	$ 2,707		$ 2,300	$ 1,725
[1]	For the years ended December 31, 2018 and December 31, 2016, 2.0 million and 0.6 million weighted-average nonvested restricted stock units, respectively, and 0.5 million and 0.5 million weighted-average stock options, respectively, have been excluded from the computation of diluted earnings (loss) per common share as their inclusion would be antidilutive due to our loss attributable to The Williams Companies, Inc.

Consolidated Statement of Compr

Consolidated Statement of Comprehensive Income (Loss) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Comprehensive income (loss):
Net income (loss)	$ 193	$ 2,509	$ (350)
Cash flow hedging activities:
Net unrealized gain (loss) from derivative instruments, net of taxes of $1, $2, and ($1) in 2018, 2017, and 2016, respectively	(7)	(9)	4
Reclassifications into earnings of net derivative instruments (gain) loss, net of taxes of ($1), ($1), and $1 in 2018, 2017, and 2016, respectively	8	6	(2)
Foreign currency translation activities:
Foreign currency translation adjustments, net of taxes of ($37) in 2016	0	1	50
Reclassification into earnings upon sale of foreign entities, net of taxes of ($36) in 2016	0	0	119
Pension and other postretirement benefits:
Amortization of prior service cost (credit) included in net periodic benefit cost (credit), net of taxes of $2 and $2 in 2017, and 2016, respectively	0	(3)	(4)
Net actuarial gain (loss) arising during the year, net of taxes of $3, ($15), and $8 in 2018, 2017 and 2016, respectively	(6)	44	(15)
Amortization of actuarial (gain) loss and net actuarial loss from settlements included in net periodic benefit cost (credit), net of taxes of ($11), ($37), and ($12) in 2018, 2017, and 2016, respectively (Note 10)	35	61	20
Other comprehensive income (loss)	30	100	172
Comprehensive income (loss)	223	2,609	(178)
Less: Comprehensive income (loss) attributable to noncontrolling interests	346	334	143
Comprehensive Income (loss) attributable to The Williams Companies, Inc.	$ (123)	$ 2,275	$ (321)

Consolidated Statement of Com_2

Consolidated Statement of Comprehensive Income (Loss) (Parenthetical) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Cash flow hedging activities:
Other Comprehensive Income, Net Unrealized Gain (Loss) from Derivatives, Tax	$ 1	$ 2	$ (1)
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	0	(37)
Other Comprehensive Income (Loss), Foreign Currency Translation Reclassification into Earnings upon Sale, Tax	0	0	(36)
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	0	2	2
Other Comprehensive Income (Loss), Defined Benefit Plan, Net Actuarial Gain (Loss) Arising During Period, Tax	3	(15)	8
Other Comprehensive Income Loss, Reclassification Pension And Other Postretirement Benefit Plans Net Gain Loss Included In Net Periodic Benefit Cost (Credit), Tax	$ (11)	$ (37)	$ (12)

Consolidated Balance Sheet

Consolidated Balance Sheet - USD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
Current assets:
Cash and cash equivalents	$ 168	$ 899
Trade accounts and other receivables (net of allowance of $9 at December 31, 2018 and $9 at December 31, 2017)	992	976
Inventories	130	113
Other current assets and deferred charges	174	191
Total current assets	1,464	2,179
Investments	7,821	6,552
Property, plant, and equipment – net	27,504	28,211
Intangible assets – net of accumulated amortization	7,767	8,791
Regulatory assets, deferred charges, and other	746	619
Total assets	45,302	46,352
Current liabilities:
Accounts payable	662	978
Accrued liabilities	1,102	1,167
Long-term debt due within one year	47	501
Total current liabilities	1,811	2,646
Long-term debt	22,367	20,434
Deferred income tax liabilities	1,524	3,147
Regulatory liabilities, deferred income, and other	3,603	3,950
Contingent liabilities and commitments (Note 18)
Preferred Stock (Note 15)	35	0
Stockholders’ equity:
Common stock ($1 par value; 1,470 million shares authorized at December 31, 2018 and 960 million shares authorized at December 31, 2017; 1,245 million shares issued at December 31, 2018 and 861 million shares issued at December 31, 2017)	1,245	861
Capital in excess of par value	24,693	18,508
Retained deficit	(10,002)	(8,434)
Accumulated other comprehensive income (loss)	(270)	(238)
Treasury stock, at cost (35 million shares of common stock)	(1,041)	(1,041)
Total stockholders’ equity	14,660	9,656
Noncontrolling interests in consolidated subsidiaries	1,337	6,519
Total equity	15,997	16,175
Total liabilities and equity	$ 45,302	$ 46,352

Consolidated Balance Sheet (Par

Consolidated Balance Sheet (Parenthetical) - USD ($) shares in Millions, $ in Millions	Dec. 31, 2018	Dec. 31, 2017
Stockholders’ equity:
Common stock, shares authorized	1,470	960
Common stock, par value per share	$ 1	$ 1
Common Stock, shares issued	1,245	861
Treasury stock, shares of common stock	35	35
Allowance for trade accounts and other receivables	$ 9	$ 9

Consolidated Statement of Chang

Consolidated Statement of Changes in Equity - USD ($) $ in Millions	Total	Preferred Stock	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, 2015	$ 16,225	$ 0	$ 784	$ 14,807	$ (7,960)	$ (442)	$ (1,041)	$ 6,148	$ 10,077
Net income (loss)	(350)	0	0	0	(424)	0	0	(424)	74
Other comprehensive income (loss)	172	0	0	0	0	103	0	103	69
Cash dividends – common stock	(1,261)	0	0	0	(1,261)	0	0	(1,261)	0
Dividends and distributions to noncontrolling interests	(940)	0	0	0	0	0	0	0	(940)
Stock-based compensation and related common stock issuances, net of tax	57	0	1	56	0	0	0	57	0
Sales of limited partner units of Williams Partners L.P.	114	0	0	0	0	0	0	0	114
Changes in ownership of consolidated subsidiaries, net	(6)	0	0	12	0	0	0	12	(18)
Contributions from noncontrolling interests	29	0	0	0	0	0	0	0	29
Other	6	0	0	12	(4)	0	0	8	(2)
Net increase (decrease) in equity	(2,179)	0	1	80	(1,689)	103	0	(1,505)	(674)
Ending balance at Dec. 31, 2016	14,046	0	785	14,887	(9,649)	(339)	(1,041)	4,643	9,403
New Accounting Pronouncement or Change in Accounting Principle, Effect of Adoption, Quantification	37	0	0	1	36	0	0	37	0
Net income (loss)	2,509	0	0	0	2,174	0	0	2,174	335
Other comprehensive income (loss)	100	0	0	0	0	101	0	101	(1)
Stock Issued During Period, Value, New Issues	2,118	0	75	2,043	0	0	0	2,118	0
Cash dividends – common stock	(992)	0	0	0	(992)	0	0	(992)	0
Dividends and distributions to noncontrolling interests	(883)	0	0	0	0	0	0	0	(883)
Stock-based compensation and related common stock issuances, net of tax	74	0	1	73	0	0	0	74	0
Sales of limited partner units of Williams Partners L.P.	61	0	0	0	0	0	0	0	61
Changes in ownership of consolidated subsidiaries, net	(910)	0	0	1,497	0	0	0	1,497	(2,407)
Contributions from noncontrolling interests	17	0	0	0	0	0	0	0	17
Other	(2)	0	0	7	(3)	0	0	4	(6)
Net increase (decrease) in equity	2,129	0	76	3,621	1,215	101	0	5,013	(2,884)
Ending balance at Dec. 31, 2017	16,175	0	861	18,508	(8,434)	(238)	(1,041)	9,656	6,519
New Accounting Pronouncement or Change in Accounting Principle, Effect of Adoption, Quantification	(121)	0	0	0	(23)	(61)	0	(84)	(37)
Net income (loss)	193	0	0	0	(155)	0	0	(155)	348
Other comprehensive income (loss)	30	0	0	0	0	32	0	32	(2)
Noncontrolling Interest, Decrease from Redemptions or Purchase of Interests	1,862	0	382	6,112	0	(3)	0	6,491	(4,629)
Stock Issued During Period, Value, New Issues	35	35	0	0	0	0	0	35	0
Cash dividends – common stock	(1,386)	0	0	0	(1,386)	0	0	(1,386)	0
Dividends and distributions to noncontrolling interests	(637)	0	0	0	0	0	0	0	(637)
Stock-based compensation and related common stock issuances, net of tax	61	0	1	60	0	0	0	61	0
Sales of limited partner units of Williams Partners L.P.	46	0	0	0	0	0	0	0	46
Changes in ownership of consolidated subsidiaries, net	(4)	0	0	14	0	0	0	14	(18)
Contributions from noncontrolling interests	15	0	0	0	0	0	0	0	15
Noncontrolling Interest, Decrease from Deconsolidation	(267)	0	0	0	0	0	0	0	(267)
Other	(5)	0	1	(1)	(4)	0	0	(4)	(1)
Net increase (decrease) in equity	(178)	35	384	6,185	(1,568)	(32)	0	5,004	(5,182)
Ending balance at Dec. 31, 2018	$ 15,997	$ 35	$ 1,245	$ 24,693	$ (10,002)	$ (270)	$ (1,041)	$ 14,660	$ 1,337

Consolidated Statement of Cha_2

Consolidated Statement of Changes in Equity (Parenthetical) - $ / shares	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Statement of Stockholders' Equity [Abstract]
Common Stock, Dividends, Per Share, Declared	$ 1.36	$ 1.20	$ 1.68

Consolidated Statement of Cash

Consolidated Statement of Cash Flows - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
OPERATING ACTIVITIES:
Net income (loss)	$ 193	$ 2,509	$ (350)
Adjustments to reconcile to net cash provided (used) by operating activities:
Depreciation and amortization	1,725	1,736	1,763
Provision (benefit) for deferred income taxes	220	(2,012)	(26)
Equity (earnings) losses	(396)	(434)	(397)
Distributions from unconsolidated affiliates	693	784	742
Net (gain) loss on disposition of equity-method investments	0	(269)	(27)
Impairment of equity-method investments (Note 17)	32	0	430
Gain on sale of certain assets (Note 3)	(692)	(1,095)	0
Impairment of and net (gain) loss on sale of other assets and businesses (Note 17)	1,915	1,249	918
Gain on deconsolidation of businesses (Note 6)	(203)	0	0
Amortization of stock-based awards	55	78	73
Regulatory charges resulting from Tax Reform (Note 1)	(15)	776	0
Cash provided (used) by changes in current assets and liabilities:
Accounts and notes receivable	(36)	(88)	82
Inventories	(16)	8	(25)
Other current assets and deferred charges	17	(21)	(4)
Accounts payable	(93)	118	35
Accrued liabilities	23	(92)	512
Other, including changes in noncurrent assets and liabilities	(129)	(158)	429
Net cash provided (used) by operating activities	3,293	3,089	4,155
FINANCING ACTIVITIES:
Proceeds from (payments of) commercial paper – net	(2)	(93)	(409)
Proceeds from long-term debt	3,926	3,333	6,528
Payments of long-term debt	(3,204)	(5,925)	(7,091)
Proceeds from issuance of common stock	15	2,131	9
Proceeds from sale of limited partner units of consolidated partnership	0	0	114
Common dividends paid	(1,386)	(992)	(1,261)
Dividends and distributions paid to noncontrolling interests	(591)	(822)	(940)
Contributions from noncontrolling interests	15	17	29
Payments for debt issuance costs	(26)	(17)	(9)
Contribution to Gulfstream for repayment of debt	0	0	(148)
Other – net	(46)	(92)	(16)
Net cash provided (used) by financing activities	(1,299)	(2,460)	(3,194)
INVESTING ACTIVITIES:
Capital expenditures	(3,256)	(2,399)	(2,051)
Dispositions – net	(7)	(41)	30
Contributions in aid of construction	411	426	218
Proceeds from sale of businesses, net of cash divested	1,296	2,067	1,020
Proceeds from dispositions of equity-method investments	0	200	34
Purchases of and contributions to equity-method investments	(1,132)	(132)	(177)
Other – net	(37)	(21)	35
Net cash provided (used) by investing activities	(2,725)	100	(891)
Increase (decrease) in cash and cash equivalents	(731)	729	70
Cash and cash equivalents at beginning of year	899	170	100
Cash and cash equivalents at end of year	168	899	170
(1) Increases to property, plant, and equipment	(3,021)	(2,662)	(1,912)
Changes in related accounts payable and accrued liabilities	(235)	263	(139)
Capital expenditures	$ (3,256)	$ (2,399)	$ (2,051)

General, Description of Busines

General, Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies	12 Months Ended
	Dec. 31, 2018
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. WPZ Merger On August 10, 2018, we completed our merger with Williams Partners L.P. (WPZ), our previously consolidated master limited partnership, pursuant to which we acquired all of the approximately 256 million publicly held outstanding common units of WPZ in exchange for 382 million shares of our common stock (WPZ Merger). Williams continued as the surviving entity. The WPZ Merger was accounted for as a noncash equity transaction resulting in increases to Common stock of $382 million , Capital in excess of par value of $6.112 billion , and Regulatory assets, deferred charges, and other of $33 million and decreases to Accumulated other comprehensive income (loss) (AOCI) of $3 million , Noncontrolling interests in consolidated subsidiaries of $4.629 billion , and Deferred income tax liabilities of $1.829 billion in the Consolidated Balance Sheet . Prior to the completion of the WPZ Merger and pursuant to its distribution reinvestment program, WPZ had issued common units to the public in 2018, 2017, and 2016 associated with reinvested distributions of $46 million , $61 million , and $10 million , respectively. Financial Repositioning In January 2017, we entered into agreements with WPZ, wherein we permanently waived the general partner’s incentive distribution rights and converted our 2 percent general partner interest in WPZ to a noneconomic interest in exchange for 289 million newly issued WPZ common units. Pursuant to this agreement, we also purchased approximately 277 thousand WPZ common units for $10 million . Additionally, we purchased approximately 59 million common units of WPZ at a price of $36.08586 per unit in a private placement transaction, funded with proceeds from our equity offering (see Note 15 – Stockholders' Equity ). According to the terms of this agreement, concurrent with WPZ’s quarterly distributions in February 2017 and May 2017, we paid additional consideration totaling $56 million to WPZ for these units. Description of Business We are a Delaware corporation whose common stock is listed and traded on the New York Stock Exchange. Our operations are located in the United States. Prior to the WPZ Merger, we had one reportable segment, Williams Partners. Beginning in the third-quarter 2018, consistent with the manner in which our chief operating decision maker evaluates performance and allocates resources, our operations are now presented within the following reportable segments: Northeast G&P, Atlantic-Gulf, and West. Prior period segment disclosures have been recast for the new segment presentation. Northeast G&P is comprised of our midstream gathering and processing businesses in the Marcellus Shale region primarily in Pennsylvania, New York, and West Virginia and the Utica Shale region of eastern Ohio, as well as a 66 percent interest in Cardinal Gas Services, L.L.C. (Cardinal) (a consolidated entity), 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), and Appalachia Midstream Services, LLC, which owns equity-method investments with an approximate average 66 percent interest in multiple gas gathering systems in the Marcellus Shale (Appalachia Midstream Investments). Atlantic-Gulf is comprised of our interstate natural gas pipeline, Transcontinental Gas Pipe Line Company, LLC (Transco), and significant natural gas gathering and processing and crude oil production handling and transportation assets in the Gulf Coast region, including a 51 percent interest in Gulfstar One LLC (Gulfstar One) (a consolidated entity), which is a proprietary floating production system, and various petrochemical and feedstock pipelines in the Gulf Coast region, as well as a 50 percent equity-method investment in Gulfstream Natural Gas System, L.L.C. (Gulfstream), a 60 percent equity-method investment in Discovery Producer Services LLC (Discovery), and a 41 percent interest in Constitution Pipeline Company, LLC (Constitution) (a consolidated entity), which is developing a pipeline project (see Note 4 – Variable Interest Entities ). West is comprised of our interstate natural gas pipeline, Northwest Pipeline LLC (Northwest Pipeline), and our gathering, processing, and treating operations in Colorado, Wyoming, and the Barnett Shale region of north-central Texas, the Eagle Ford Shale region of south Texas, the Haynesville Shale region of northwest Louisiana, and the Mid-Continent region which includes the Anadarko, Arkoma, Delaware, and Permian basins. This segment also includes our natural gas liquid (NGL) and natural gas marketing business, storage facilities, an undivided 50 percent interest in an NGL fractionator near Conway, Kansas, and a 50 percent equity-method investment in Overland Pass Pipeline, LLC (OPPL), a 50 percent interest in Jackalope Gas Gathering Services, L.L.C. (Jackalope) (an equity-method investment following deconsolidation as of June 30, 2018), a 50 percent equity-method investment in Rocky Mountain Midstream Holdings LLC (RMM), a 15 percent equity-method investment in Brazos Permian II, LLC (Brazos Permian II), and our previously owned 50 percent equity-method investment in the Delaware basin gas gathering system (DBJV) in the Mid-Continent region (see Note 6 – Investing Activities ). West also included our former natural gas gathering and processing assets in the Four Corners area of New Mexico and Colorado (see Note 3 – Divestitures ). Other includes our previously owned operations, including our former 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), which was sold in July 2017 (see Note 3 – Divestitures ), and a refinery grade propylene splitter in the Gulf region, which was sold in June 2017. This segment also included our previously owned Canadian assets, which included an oil sands offgas processing plant near Fort McMurray, Alberta, and an NGL/olefin fractionation facility at Redwater, Alberta. In September 2016, these Canadian operations were sold. Other also includes minor business activities that are not operating segments, as well as corporate operations. Basis of Presentation Significant risks and uncertainties We believe that the carrying value of certain of our property, plant, and equipment and other identifiable intangible assets, notably certain acquired assets accounted for as business combinations between 2012 and 2014, may be in excess of current fair value. However, the carrying value of these assets, in our judgment, continues to be recoverable based on our evaluation of undiscounted future cash flows. It is reasonably possible that future strategic decisions, including transactions such as monetizing non-core assets or contributing assets to new ventures with third parties, as well as unfavorable changes in expected producer activities could impact our assumptions and ultimately result in impairments of these assets. Such transactions or developments may also indicate that certain of our equity-method investments have experienced other-than-temporary declines in value, which could also result in impairment. On March 15, 2018, the Federal Energy Regulatory Commission (FERC) issued a revised policy statement (the revised policy statement) regarding the recovery of income tax costs in rates of natural gas pipelines. The FERC found that an impermissible double recovery results from granting a Master Limited Partnership (MLP) pipeline both an income tax allowance and a return on equity pursuant to the discounted cash flow methodology. As a result, the FERC will no longer permit an MLP pipeline to recover an income tax allowance in its cost of service. The FERC further stated it will address the application of this policy to non-MLP partnership forms as those issues arise in subsequent proceedings. One of the benefits of the recent WPZ Merger is to allow our FERC-regulated pipelines to continue to recover an income tax allowance in their cost of service rates. On July 18, 2018, the FERC issued an order dismissing the requests for rehearing and clarification of the revised policy statement. In addition, the FERC provided guidance that an MLP pipeline (or other pass-through entity) no longer recovering an income tax allowance pursuant to the revised policy may eliminate previously accumulated deferred income taxes (ADIT) from its cost of service instead of flowing these ADIT balances to ratepayers. This guidance, if implemented, would significantly mitigate the impact of the revised policy statement. However, the FERC stated that the revised policy statement and such guidance do not establish a binding rule but are instead expressions of general policy intent designed to provide guidance by notifying entities of the course of action the FERC intends to follow in future adjudications. To the extent the FERC addresses these issues in future proceedings, it will consider any arguments regarding not only the application of the revised policy to the facts of the case, but also any arguments regarding the underlying validity of the policy itself. The FERC’s guidance on ADIT likely will be challenged by customers and state commissions, which would result in a long period of revenue uncertainty for pipelines eliminating ADIT from their cost of service. The WPZ Merger has the additional benefit of eliminating this uncertainty. On March 15, 2018, the FERC also issued a Notice of Proposed Rulemaking proposing a filing process that will allow it to determine which natural gas pipelines may be collecting unjust and unreasonable rates in light of the recent reduction in the corporate income tax rate in the Tax Cuts and Jobs Act (Tax Reform) and the revised policy statement. On July 18, 2018, the FERC issued a Final Rule, retaining the filing requirement and reaffirming the options that pipelines have to either reflect the reduced tax rate or explain why no rate change is necessary. The FERC also clarified that a natural gas company organized as a pass-through entity and all of whose income or losses are consolidated on the federal income tax return of its corporate parent is considered to be subject to the federal corporate income tax and is thus eligible for a tax allowance. We believe this Final Rule and the previously discussed WPZ Merger allow for the continued recovery of income tax allowances in Transco’s and Northwest Pipeline’s rates. Transco’s August 31, 2018 general rate case filing reflects a tax allowance based on this clarification, and the FERC’s September 28, 2018 order in that rate case proceeding finds that Transco is exempt from the Final Rule’s Form 501-G filing requirement. In addition, on October 19, 2018, Northwest Pipeline filed a petition requesting that the FERC waive its Form 501-G filing requirement under this Final Rule because (i) the reduction in the corporate income tax is already addressed in Northwest Pipeline’s 2017 rate settlement, and (ii) as discussed above, the WPZ Merger allows for the continued recovery of income tax allowances in Northwest Pipeline’s rates. The FERC agreed and granted Northwest Pipeline’s petition for waiver on November 19, 2018. On October 11, 2018 and December 6, 2018, Discovery Gas Transmission, LLC and Pine Needle LNG Company, LLC, respectively, filed their Form 501-Gs, including explanations as to why no adjustments to rates are needed. On March 15, 2018, the FERC also issued a Notice of Inquiry seeking comments on the additional impacts of Tax Reform on jurisdictional rates, particularly whether, and if so how, the FERC should address changes relating to ADIT amounts after the corporate income tax rate reduction and bonus depreciation rules, as well as whether other features of Tax Reform require FERC action. We are evaluating the impact of these developments on our interstate natural gas pipelines and currently expect any associated impacts would be prospective and determined through subsequent rate proceedings. We also continue to monitor developments that may impact our regulatory liabilities resulting from Tax Reform. It is reasonably possible that future tariff-based rates collected by our interstate natural gas pipelines may be adversely impacted. 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 variable interest entity (VIE); • Determining whether we are the primary beneficiary of a VIE, including evaluating which activities of the VIE most significantly impact its economic performance and the degree of power that we and our related parties have over those activities through our variable interests; • 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, and other identifiable intangible assets; • Litigation-related contingencies; • Environmental remediation obligations; • Depreciation and/or amortization of long-lived assets; • Depreciation and/or amortization of equity-method investment basis differences; • Asset retirement obligations (AROs); • Pension and postretirement valuation variables; • Measurement of regulatory liabilities; • Measurement of deferred income tax assets and liabilities, including assumptions related to the realization of deferred income tax assets. These estimates are discussed further throughout these notes. Regulatory accounting Transco and Northwest Pipeline are regulated by the FERC. Their rates, which are established by the FERC, are designed to recover the costs of providing the regulated services, and their competitive environment makes it probable that such rates can be charged and collected. Therefore, we have determined that it is appropriate under Accounting Standards Codification (ASC) Topic 980, “Regulated Operations,” (ASC 980) to account for and report regulatory assets and liabilities related to these operations consistent with the economic effect of the way in which their rates are established. Accounting for these operations that are regulated can differ from the accounting requirements for nonregulated operations. For example, for regulated operations, allowance for funds used during construction (AFUDC) represents the estimated cost of debt and equity funds applicable to utility plant in the process of construction and is capitalized as a cost of property, plant, and equipment because it constitutes an actual cost of construction under established regulatory practices; nonregulated operations are only allowed to capitalize the cost of debt funds related to construction activities, while a component for equity is prohibited. The components of our regulatory assets and liabilities relate to the effects of deferred taxes on equity funds used during construction, asset retirement obligations, fuel cost differentials, levelized incremental depreciation, negative salvage, pension and other postretirement benefits, and rate allowances for deferred income taxes at a historically higher federal income tax rate. In December 2017, Tax Reform was enacted, which, among other things, reduced the federal corporate income tax rate from 35 percent to 21 percent (see Note 8 – Provision (Benefit) for Income Taxes ). In accordance with ASC 980-740-25-2, Transco and Northwest Pipeline have recognized regulatory liabilities to reflect the probable return to customers through future rates of the future decrease in income taxes payable associated with Tax Reform. These liabilities represent an obligation to return amounts directly to our customers. While a majority of our customers have entered into tariff rates based on our cost-of-service proceedings and related rate base therein, certain other contracts with customers reflect contractually-based rates that are designed to recover the cost of providing those services, including an allowance for income taxes, with no expected future rate adjustment for the term of those contracts. This relative mix of contracts for services was considered in determining the probable amount to be returned to customers through future rates. The regulatory liabilities were recorded in December 2017 through regulatory charges to operating income totaling $674 million . As of December 31, 2018, the balance of these regulatory liabilities totaled $657 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 for 2017 were reduced by $11 million related to our proportionate share of the associated regulatory charges. Our regulatory assets associated with the effects of deferred taxes on equity funds used during construction were also impacted by Tax Reform and were reduced by $102 million in December 2017 through a charge to Other income (expense) – net below Operating income (loss) in the Consolidated Statement of Operations (see Note 7 – Other Income and Expenses ). This amount, along with the previously described charges for establishing the regulatory liabilities resulting from Tax Reform, is reported within Regulatory charges resulting from Tax Reform within the Consolidated Statement of Cash Flows . Our current and noncurrent regulatory asset and liability balances for the years ended December 31, 2018 and 2017 are as follows: December 31, 2018 2017 (Millions) Current assets reported within Other current assets and deferred charges $ 103 $ 102 Noncurrent assets reported within Regulatory assets, deferred charges, and other 495 376 Total regulated assets $ 598 $ 478 Current liabilities reported within Accrued liabilities $ 5 $ 18 Noncurrent liabilities reported within Regulatory liabilities, deferred income, and other 1,321 1,250 Total regulated liabilities $ 1,326 $ 1,268 Cash and cash equivalents Cash and cash equivalents consist of highly liquid investments with original maturities of three months or less when acquired. Accounts receivable Accounts receivable are carried on a gross basis, with no discounting, less an allowance for doubtful accounts. We estimate the allowance for doubtful accounts based on existing economic conditions, the financial condition of our customers, and the amount and age of past due accounts. We do not offer extended payment terms and typically receive payment within one month. We consider receivables past due if full payment is not received by the contractual due date. Interest income related to past due accounts receivable is generally recognized at the time full payment is received or collectability is assured. Past due accounts are generally written off against the allowance for doubtful accounts only after all collection attempts have been exhausted. Inventories Inventories in the Consolidated Balance Sheet primarily consist of NGLs, natural gas in underground storage, and materials and supplies and are stated at the lower of cost or net realizable value. The cost of inventories is primarily determined using the average-cost method. Property, plant, and equipment Property, plant, and equipment is initially recorded at cost. We base the carrying value of these assets on estimates, assumptions, and judgments relative to capitalized costs, useful lives, and salvage values. As regulated entities, Northwest Pipeline and Transco provide for depreciation using the straight-line method at FERC-prescribed rates. Depreciation for nonregulated entities is provided primarily on the straight-line method over estimated useful lives, except for certain offshore facilities that apply an accelerated depreciation method. Gains or losses from the ordinary sale or retirement of property, plant, and equipment for regulated pipelines are credited or charged to accumulated depreciation. Other gains or losses are recorded in Other (income) expense – net included in Operating income (loss) in the Consolidated Statement of Operations . Ordinary maintenance and repair costs are generally expensed as incurred. Costs of major renewals and replacements are capitalized as property, plant, and equipment. We record a liability and increase the basis in the underlying asset for the present value of each expected future ARO at the time the liability is initially incurred, typically when the asset is acquired or constructed. As regulated 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. 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. Contingent liabilities We record liabilities for estimated loss contingencies, including environmental matters, when we assess that a loss is probable, and the amount of the loss can be reasonably estimated. These liabilities are calculated based upon our assumptions and estimates with respect to the likelihood or amount of loss and upon advice of legal counsel, engineers, or other third parties regarding the probable outcomes of the matters. These calculations are made without consideration of any potential recovery from third parties. We recognize insurance recoveries or reimbursements from others when realizable. Revisions to these liabilities are generally reflected in income when new or different facts or information become known or circumstances change that affect the previous assumptions or estimates. Cash flows from revolving credit facilities and commercial paper program Proceeds and payments related to borrowings under our credit facilities are reflected in the financing activities in the Consolidated Statement of Cash Flows on a gross basis. Proceeds and payments related to borrowings under our commercial paper program are reflected in the financing activities in the Consolidated Statement of Cash Flows on a net basis, as the outstanding notes generally have maturity dates less than three months from the date of issuance. (See Note 14 – Debt, Banking Arrangements, and Leases .) Treasury stock Treasury stock purchases are accounted for under the cost method whereby the entire cost of the acquired stock is recorded as Treasury stock in the Consolidated Balance Sheet . Gains and losses on the subsequent reissuance of shares are credited or charged to Capital in excess of par value in the Consolidated Balance Sheet using the average-cost method. Derivative instruments and hedging activities We may utilize derivatives to manage a portion of our commodity price risk. These instruments consist primarily of swaps, futures, and forward contracts involving short- and long-term purchases and sales of energy commodities. We report the fair value of derivatives, except those for which the normal purchases and normal sales exception has been elected, in Other current assets and deferred charges ; Regulatory assets, deferred charges, and other ; Accrued liabilities ; or Regulatory liabilities, deferred income, and other in the Consolidated Balance Sheet . We determine the current and noncurrent classification based on the timing of expected future cash flows of individual trades. We report these amounts on a gross basis. Additionally, we report cash collateral receivables and payables with our counterparties on a gross basis. (See Note 17 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk .) The accounting for the changes in fair value of a commodity derivative can be summarized as follows: Derivative Treatment Accounting Method Normal purchases and normal sales exception Accrual accounting Designated in a qualifying hedging relationship Hedge accounting All other derivatives Mark-to-market accounting We may elect the normal purchases and normal sales exception for certain short- and long-term purchases and sales of physical energy commodities. Under accrual accounting, any change in the fair value of these derivatives is not reflected on the balance sheet after the initial election of the exception. We may also designate a hedging relationship for certain commodity derivatives. For a derivative to qualify for designation in a hedging relationship, it must meet specific criteria and we must maintain appropriate documentation. We establish hedging relationships pursuant to our risk management policies. We evaluate the hedging relationships at the inception of the hedge and on an ongoing basis to determine whether the hedging relationship is, and is expected to remain, highly effective in achieving offsetting changes in fair value or cash flows attributable to the underlying risk being hedged. We also regularly assess whether the hedged forecasted transaction is probable of occurring. If a derivative ceases to be or is no longer expected to be highly effective, or if we believe the likelihood of occurrence of the hedged forecasted transaction is no longer probable, hedge accounting is discontinued prospectively, and future changes in the fair value of the derivative are recognized currently in Product sales or Product costs in the Consolidated Statement of Operations . For commodity derivatives designated as a cash flow hedge, the change in fair value of the derivative is reported in AOCI in the Consolidated Balance Sheet and reclassified into earnings in the period in which the hedged item affects earnings. Gains or losses deferred in AOCI associated with terminated derivatives, derivatives that cease to be highly effective hedges, derivatives for which the forecasted transaction is reasonably possible but no longer probable of occurring, and cash flow hedges that have been otherwise discontinued remain in AOCI until the hedged item affects earnings. If it becomes probable that the forecasted transaction designated as the hedged item in a cash flow hedge will not occur, any gain or loss deferred in AOCI is recognized in Product sales or Product costs in the Consolidated Statement of Operations at that time. The change in likelihood of a forecasted transaction is a judgmental decision that includes qualitative assessments made by us. For commodity derivatives that are not designated in a hedging relationship, and for which we have not elected the normal purchases and normal sales exception, we report changes in fair value currently in Product sales or Product costs in the Consolidated Statement of Operations . Certain gains and losses on derivative instruments included in the Consolidated Statem

Revenue Recognition

Revenue Recognition	12 Months Ended
	Dec. 31, 2018
Revenue Recognition [Abstract]
Revenue Recognition [Text Block]	Note 2 – Revenue Recognition Revenue by Category The following table presents our revenue disaggregated by major service line: Northeast Midstream Atlantic- Gulf Midstream West Midstream Transco Northwest Pipeline Other Intercompany Eliminations Total (Millions) Year Ended December 31, 2018 Revenues from contracts with customers: Service revenues: Non-regulated gathering, processing, transportation, and storage: Monetary consideration $ 861 $ 541 $ 1,590 $ — $ — $ 2 $ (73 ) $ 2,921 Commodity consideration 20 59 321 — — — — 400 Regulated interstate natural gas transportation and storage — — — 1,921 443 — (2 ) 2,362 Other 94 17 46 2 — — (15 ) 144 Total service revenues 975 617 1,957 1,923 443 2 (90 ) 5,827 Product Sales: NGL and natural gas 287 307 2,421 127 — — (382 ) 2,760 Other — — 21 — — — (4 ) 17 Total product sales 287 307 2,442 127 — — (386 ) 2,777 Total revenues from contracts with customers 1,262 924 4,399 2,050 443 2 (476 ) 8,604 Other revenues (1) 21 18 12 11 — 32 (12 ) 82 Total revenues $ 1,283 $ 942 $ 4,411 $ 2,061 $ 443 $ 34 $ (488 ) $ 8,686 ______________________________ (1) Service revenues in our Consolidated Statement of Operations include leasing revenues associated with our headquarters building and management fees that we receive for certain services we provide to operated joint ventures and other investments. The leasing revenues and the management fees do not constitute revenue from contracts with customers. Product sales in our Consolidated Statement of Operations include amounts associated with our derivative contracts that are not within the scope of ASC 606. Contract Assets The following table presents a reconciliation of our contract assets: Year Ended December 31, 2018 (Millions) Balance at beginning of period $ 4 Revenue recognized in excess of amounts invoiced 66 Minimum volume commitments invoiced (66 ) Balance at end of period $ 4 Contract Liabilities The following table presents a reconciliation of our contract liabilities: Year Ended December 31, 2018 (Millions) Balance at beginning of period $ 1,596 Payments received and deferred 314 Noncash interest expense for significant financing component 16 Deconsolidation of Jackalope interest (Note 4) (52 ) Deconsolidation of certain Permian assets (Note 6) (26 ) Recognized in revenue (451 ) Balance at end of period $ 1,397 The following table presents the amount of the contract liabilities balance as of December 31, 2018 , expected to be recognized as revenue in each of the next five years as performance obligations are expected to be satisfied: (Millions) 2019 $ 271 2020 142 2021 121 2022 102 2023 95 Thereafter 666 Total $ 1,397 Remaining Performance Obligations The following table presents the transaction price allocated to the remaining performance obligations under certain contracts as of December 31, 2018 . These primarily include long-term contracts containing MVCs associated with our midstream businesses, fixed payments associated with offshore production handling, and reservation charges on contracted capacity on our gas pipeline firm transportation contracts with customers, as well as storage capacity contracts. Amounts included in the table below for our interstate natural gas pipeline businesses reflect the rates for such services in our current FERC tariffs for the life of the related contracts; however, these rates may change based on future tariffs approved by the FERC and the amount and timing of these changes is not currently known. As a practical expedient permitted by ASC 606, this table excludes variable consideration as well as consideration in contracts that is recognized in revenue as billed. It also excludes consideration received prior to December 31, 2018 , that will be recognized in future periods (see above for Contract Liabilities and the expected recognition of those amounts within revenue). Certain of our contracts contain evergreen and other renewal provisions for periods beyond the initial term of the contract. The remaining performance obligation amounts as of December 31, 2018 , do not consider potential future performance obligations for which the renewal has not been exercised. The table below also does not include contracts with customers for which the underlying facilities have not received FERC authorization to be placed into service. (Millions) 2019 $ 2,909 2020 2,728 2021 2,622 2022 2,262 2023 2,089 Thereafter 16,916 Total $ 29,526 Accounts Receivable The following is a summary of our Trade accounts and other receivables : December 31, 2018 January 1, 2018 (Millions) Accounts receivable related to revenues from contracts with customers $ 858 $ 958 Other accounts receivable 134 18 Total reflected in Trade accounts and other receivables $ 992 $ 976 Impact of Adoption of ASC 606 The following table depicts the impact of the adoption of ASC 606 on our 2018 financial statements. The adjustment to Intangible assets – net of accumulated amortization in the table below relates to the recognition under ASC 606 of contract assets for MVC-related contracts associated with a 2014 acquisition. The recognition of these contract assets resulted in a lower purchase price allocation to intangible assets. The adoption of ASC 606 did not result in adjustments to total operating, investing, or financing cash flows. As Reported Adjustments resulting from adoption of ASC 606 Balance without adoption of ASC 606 (Millions, except per-share amounts) Consolidated Statement of Operations Year Ended December 31, 2018 Service revenues $ 5,502 $ 89 $ 5,591 Service revenues – commodity consideration 400 (400 ) — Product sales 2,784 135 2,919 Total revenues 8,686 (176 ) 8,510 Product costs 2,707 (124 ) 2,583 Processing commodity expenses 137 (137 ) — Operating and maintenance expenses 1,507 1 1,508 Depreciation and amortization expenses 1,725 2 1,727 Impairment of certain assets 1,915 202 2,117 Total costs and expenses 7,918 (56 ) 7,862 Operating income (loss) 768 (120 ) 648 Equity earnings (losses) 396 1 397 Other investing income (loss) – net 219 84 303 Interest incurred (1,160 ) 16 (1,144 ) As Reported Adjustments resulting from adoption of ASC 606 Balance without adoption of ASC 606 (Millions, except per-share amounts) Interest capitalized 48 (10 ) 38 Income (loss) before income taxes 331 (29 ) 302 Provision (benefit) for income taxes 138 (9 ) 129 Net income (loss) 193 (20 ) 173 Less: Net income (loss) attributable to noncontrolling interests 348 (1 ) 347 Net income (loss) attributable to The Williams Companies, Inc. (155 ) (19 ) (174 ) Basic earnings (loss) per common share $ (0.16 ) $ (0.02 ) $ (0.18 ) Diluted earnings (loss) per common share (0.16 ) (0.02 ) (0.18 ) Consolidated Statement of Comprehensive Income (Loss) Year Ended December 31, 2018 Net income (loss) $ 193 $ (20 ) $ 173 Comprehensive income (loss) 223 (20 ) 203 Less: Comprehensive income (loss) attributable to noncontrolling interests 346 (1 ) 345 Comprehensive income (loss) attributable to The Williams Companies, Inc. (123 ) (19 ) (142 ) Consolidated Balance Sheet December 31, 2018 Inventories $ 130 $ (13 ) $ 117 Total current assets 1,464 (13 ) 1,451 Investments 7,821 1 7,822 Property, plant, and equipment – net 27,504 (212 ) 27,292 Intangible assets – net of accumulated amortization 7,767 61 7,828 Regulatory assets, deferred charges, and other 746 (4 ) 742 Total assets 45,302 (167 ) 45,135 Accrued liabilities 1,102 67 1,169 Total current liabilities 1,811 67 1,878 Deferred income tax liabilities 1,524 20 1,544 Regulatory liabilities, deferred income, and other 3,603 (346 ) 3,257 Retained deficit (10,002 ) 64 (9,938 ) Total stockholders’ equity 14,660 64 14,724 Noncontrolling interests in consolidated subsidiaries 1,337 28 1,365 Total equity 15,997 92 16,089 Total liabilities and equity 45,302 (167 ) 45,135 Consolidated Statement of Changes in Equity December 31, 2018 Adoption of ASC 606 $ (121 ) $ 121 $ — Net income (loss) 193 (20 ) 173 Deconsolidation of subsidiary (267 ) (9 ) (276 ) Net increase (decrease) in equity (178 ) 92 (86 ) Balance at December 31, 2018 15,997 92 16,089

Divestitures

Divestitures	12 Months Ended
	Dec. 31, 2018
Business Combinations [Abstract]
Divestitures [Text Block]	Note 3 – Divestitures Sale of Gulf Coast Pipeline Systems In November 2018, we completed the sale of certain assets and operations located in the Gulf Coast area for $177 million in cash. These assets were designated as held for sale during the third quarter of 2018. As a result of this sale, we recorded a gain of approximately $101 million in the fourth quarter of 2018, consisting of $81 million in our Atlantic-Gulf segment and $20 million in Other. Previous impairments made to a portion of these assets and operations include $66 million related to certain idle pipelines in the second quarter of 2018, as well as $68 million and $23 million related to an NGL pipeline near the Houston Ship Channel region and project development costs associated with an olefins pipeline project, respectively, in 2017. These impairments are reflected in Impairment of certain assets in the Consolidated Statement of Operations . (See Note 17 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk .) The results of operations for this disposal group, excluding the impairments and gains noted, were not significant for the reporting periods. Sale of Four Corners Assets In October 2018, we completed the sale of our natural gas gathering and processing assets in the Four Corners area of New Mexico and Colorado for total consideration of $1.125 billion , subject to customary working capital adjustments. These assets were designated as held for sale during the third quarter of 2018. As a result of this sale, we recorded a gain of approximately $591 million within the West segment in the fourth quarter of 2018. The following table presents the results of operations for the Four Corners area, excluding the gain noted above: Years Ended December 31, 2018 2017 2016 (Millions) Income (loss) before income taxes of Four Corners area $ 52 $ 47 $ 37 Income (loss) before income taxes of Four Corners area attributable to The Williams Companies, Inc. 43 35 23 Sale of Geismar Interest In July 2017, we completed the sale of Williams Olefins, L.L.C., a wholly owned subsidiary which owned our Geismar Interest for total consideration of $2.084 billion in cash. We received a final working capital adjustment of $12 million in October 2017. Upon closing of the sale, we entered into a long-term supply and transportation agreement with the purchaser to provide feedstock to the plant via its Bayou Ethane pipeline system. As a result of this sale, we recorded a gain of $1.095 billion in the third quarter of 2017 in our Other segment. Following this sale, the cash proceeds were used to repay our $850 million term loan. The following table presents the results of operations for the Geismar Interest, excluding the gain noted above: Years Ended December 31, 2018 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 (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. During 2016, we designated these operations as held for sale. As a result, we measured the fair value of the disposal group, resulting in an impairment charge of $747 million , reflected in Impairment of certain assets in the Consolidated Statement of Operations . (See Note 17 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk .) Upon completion of the sale, we also recorded a loss of $66 million in Other, primarily reflecting revisions to the sales price and estimated contingent consideration. This included 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 . For the year ended December 31, 2016, the results of operations for the Canadian disposal group, excluding the impairment and loss noted, were a loss before income taxes of $98 million , and a loss before income taxes attributable to The Williams Companies, Inc. of $95 million , in Other.

Variable Interest Entities

Variable Interest Entities	12 Months Ended
	Dec. 31, 2018
Variable Interest Entity Disclosures [Abstract]
Variable Interest Entities [Text Block]	Note 4 – Variable Interest Entities Consolidated VIEs As of December 31, 2018 , we consolidate the following VIEs: Gulfstar One We own a 51 percent interest in Gulfstar One, a subsidiary that, due to certain risk-sharing provisions in its customer contracts, is a VIE. Gulfstar One includes a proprietary floating-production system, Gulfstar FPS, and associated pipelines which provide production handling and gathering services in the eastern deepwater Gulf of Mexico. We are the primary beneficiary because we have the power to direct the activities that most significantly impact Gulfstar One’s economic performance. Constitution We own 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. We are the primary beneficiary because we have the power to direct the activities that most significantly impact Constitution’s economic performance. We, as operator of Constitution, are 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 us and the other equity partners on a proportional basis. In December 2014, Constitution received approval from the 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 (D.C. 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 2017 the court denied our petition. In October 2017, we 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 our 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. We filed a request for rehearing of the FERC’s decision, but in July 2018 the FERC denied our request. The project’s sponsors remain committed to the project. On November 5, 2018, the FERC granted our request for an extension of time to December 2, 2020, to construct and place into service the Constitution pipeline. And, in September 2018, we filed a petition with the D.C. Circuit for review of the FERC’s denial of our petition for declaratory order. An unfavorable resolution of that appeal could result in the impairment of a significant portion of the capitalized project costs, which total $377 million on a consolidated basis at December 31, 2018 , 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 continued prolonged delay or termination of the project. Cardinal We own a 66 percent interest in Cardinal, a subsidiary that provides gathering services for the Utica Shale region and is a VIE due to certain risks shared with customers. We are the primary beneficiary because we have the power to direct the activities that most significantly impact Cardinal’s economic performance. Future expansion activity is expected to be funded with capital contributions from us and the other equity partner on a proportional basis. The following table presents amounts included in our Consolidated Balance Sheet that are for the use or obligation of our consolidated VIEs: December 31, 2018 2017 (1) Classification (Millions) Assets (liabilities): Cash and cash equivalents $ 33 $ 881 Cash and cash equivalents Trade accounts and other receivables – net 62 972 Trade accounts and other receivables Inventories — 113 Inventories Other current assets 2 176 Other current assets and deferred charges Investments — 6,552 Investments Property, plant, and equipment – net 2,363 27,912 Property, plant, and equipment – net Intangible assets – net 1,177 8,790 Intangible assets – net of accumulated amortization Regulatory assets, deferred charges, and other noncurrent assets — 507 Regulatory assets, deferred charges, and other Accounts payable (15 ) (957 ) Accounts payable Accrued liabilities including current asset retirement obligations (115 ) (857 ) Accrued liabilities Long-term debt due within one year — (501 ) Long-term debt due within one year Long-term debt — (15,996 ) Long-term debt Deferred income tax liabilities — (16 ) Deferred income tax liabilities Noncurrent asset retirement obligations (105 ) (944 ) Regulatory liabilities, deferred income, and other Long-term deferred income (159 ) (1,119 ) Regulatory liabilities, deferred income, and other Regulatory liabilities and other — (1,690 ) Regulatory liabilities, deferred income, and other _________________ (1) Includes WPZ, which was a consolidated VIE at December 31, 2017 (see Note 1 – General, Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies ). Nonconsolidated VIEs Jackalope We own a 50 percent interest in Jackalope, which provides gathering and processing services for the Powder River basin and is a VIE due to certain risks shared with customers. Prior to the second quarter of 2018 we were the primary beneficiary of Jackalope. During the second quarter of 2018, the scope of Jackalope’s planned future activities changed, resulting in a VIE reconsideration event. Upon evaluation, we determined that we are no longer the primary beneficiary, most notably due to changes in the activities that most significantly impact Jackalope’s economic performance and our determination that we do not control the power to direct such activities. These activities are primarily related to the capital decision making process. As a result, we deconsolidated Jackalope on June 30, 2018 and now account for our interest using the equity method of accounting as we exert significant influence over the financial and operational policies of Jackalope (see Note 6 – Investing Activities ). At December 31, 2018 , the carrying value of our investment in Jackalope was $343 million . Our maximum exposure to loss is limited to the carrying value of our investment. Jackalope is currently undertaking an expansion project with a remaining cost up to approximately $350 million as of December 31, 2018, which will be funded on a proportional basis. Brazos Permian II We own a 15 percent interest in Brazos Permian II (see Note 6 – Investing Activities ), which provides gathering and processing services in the Delaware basin and is a VIE due primarily to our limited participating rights as the minority equity holder. At December 31, 2018 , the carrying value of our investment in Brazos Permian II was $191 million . Our maximum exposure to loss is limited to the carrying value of our investment.

Related Party Transactions

Related Party Transactions	12 Months Ended
	Dec. 31, 2018
Related Party Transactions [Abstract]
Related Party Transactions [Text Block]	Note 5 – Related Party Transactions Transactions with Equity-Method Investees We have purchases from our equity-method investees included in Product costs in the Consolidated Statement of Operations of $236 million , $226 million , and $180 million for the years ended 2018, 2017, and 2016, respectively. We have $18 million and $20 million included in Accounts payable in the Consolidated Balance Sheet with our equity-method investees at December 31, 2018 and 2017, respectively. We have operating agreements with certain equity-method investees. These operating agreements typically provide for reimbursement or payment to us for certain direct operational payroll and employee benefit costs, materials, supplies, and other charges and also for management services. The total charges to equity-method investees for these fees are $75 million , $67 million , and $66 million for the years ended 2018 , 2017 , and 2016 , 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 in Service revenues in the Consolidated Statement of Operations from this company for transportation and storage of natural gas for the year ended December 31, 2016.

Investing Activities

Investing Activities	12 Months Ended
	Dec. 31, 2018
Investments [Abstract]
Investing Activities [Text Block]	Note 6 – Investing Activities Brazos Permian II Equity-Method Investment During the fourth quarter of 2018, we contributed the majority of our existing Delaware basin assets and $27 million in cash in exchange for a 15 percent interest in the Brazos Permian II, which consists of gas and crude oil gathering pipelines, natural gas processing, and oil storage facilities. We recorded a deconsolidation gain of $141 million reflected in Other investing income (loss) – net in the Consolidated Statement of Operations reflecting the excess of the fair value of our acquired interest over the carrying value of the assets contributed. We estimated the fair value of our interest to be $192 million primarily using a market approach (a Level 3 measurement within the fair value hierarchy). This approach involved the observation of recent transaction multiples in the Permian basin, including recent acquisitions consummated during 2018. Our interest in Brazos Permian II is considered an equity-method investment due to the fact that we are able to exert significant influence over its operating and financial policies. RMM Equity-Method Investment During the third quarter of 2018, our joint venture, RMM, purchased a natural gas and oil gathering and natural gas processing business in Colorado’s Denver-Julesburg basin. Our initial economic ownership was 40 percent , which has since increased to 50 percent at December 31, 2018, based on additional capital contributions made since the initial purchase. Jackalope Deconsolidation During the second quarter of 2018, we deconsolidated our interest in Jackalope (see Note 4 – Variable Interest Entities ). We recorded our interest in Jackalope as an equity-method investment at its estimated fair value, resulting in a deconsolidation gain of $62 million reflected in Other investing income (loss) – net in the Consolidated Statement of Operations . We estimated the fair value of our interest to be $310 million using an income approach based on expected future cash flows and an appropriate discount rate (a Level 3 measurement within the fair value hierarchy). The determination of expected future cash flows involved significant assumptions regarding gathering and processing volumes and related capital spending. A 10.9 percent discount rate was utilized and reflected our estimate of the cost of capital as impacted by market conditions and risks associated with the underlying business. The deconsolidated carrying value of the net assets of Jackalope included $47 million of goodwill. Acquisition of Additional Interests in Appalachia Midstream Investments During the first quarter of 2017, we exchanged all of our 50 percent interest in DBJV for an increased interest in two natural gas gathering systems that are part of the Appalachia Midstream Investments and $155 million in cash. This transaction was recorded based on our estimate of the fair value of the interests received as we have more insight to this value as we operate the underlying assets. Following this exchange, we have an approximate average 66 percent interest in the Appalachia Midstream Investments. We continue to account for this investment under the equity method of accounting due to the significant participatory rights of our partners such that we do not exercise control. We also sold all of our interest in Ranch Westex JV LLC (Ranch Westex) for $45 million . These transactions resulted in a total gain of $269 million reflected in Other investing income (loss) – net in the Consolidated Statement of Operations . The fair value of the increased interests in the Appalachia Midstream Investments received as consideration was estimated to be $1.1 billion using an income approach based on expected cash flows and an appropriate discount rate (a Level 3 measurement within the fair value hierarchy). The determination of estimated future cash flows involved significant assumptions regarding gathering volumes, rates, and related capital spending. A 9.5 percent discount rate was utilized and reflected our estimate of the cost of capital as impacted by market conditions and risks associated with the underlying business. Impairment of equity-method investments The following table presents other-than-temporary impairment charges related to certain equity-method investments (see Note 17 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk ): Years Ended December 31, 2018 2017 2016 (Millions) Northeast G&P UEOM $ 32 $ — $ — Appalachia Midstream Investments — — 294 Laurel Mountain — — 50 West DBJV — — 59 Ranch Westex — — 24 Other — — 3 $ 32 $ — $ 430 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 of interest income for 2016 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, 2018 December 31, 2018 2017 (Millions) Equity-method investments: Appalachia Midstream Investments (1) $ 3,218 $ 3,104 UEOM 62% 1,293 1,383 RMM 50% 776 — Discovery 60% 507 534 OPPL 50% 415 422 Caiman II 58% 412 429 Jackalope 50% 343 — Laurel Mountain 69% 314 309 Gulfstream 50% 225 244 Brazos Permian II 15% 191 — Other Various 127 127 $ 7,821 $ 6,552 ___________ (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, 2018 and 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. 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, 2018 2017 2016 (Millions) RMM $ 795 $ — $ — Appalachia Midstream Investments 246 70 28 Jackalope 42 — — Brazos Permian II 27 — — Laurel Mountain 16 — — Discovery 5 1 — DBJV — 32 105 Caiman II — 24 22 Other 1 5 22 $ 1,132 $ 132 $ 177 Dividends and distributions The organizational documents of entities in which we have an equity-method investment generally require distribution of available cash to members on at least a quarterly basis. These transactions reduced the carrying value of our investments and included: Years Ended December 31, 2018 2017 2016 (Millions) Appalachia Midstream Investments $ 297 $ 270 $ 211 Gulfstream 93 92 100 OPPL 73 68 69 UEOM 70 80 92 Caiman II 46 49 40 Discovery 45 127 141 DBJV — 39 39 Laurel Mountain 23 32 28 Other 46 27 22 $ 693 $ 784 $ 742 In addition, on September 24, 2015, we received a special distribution of $396 million from Gulfstream reflecting our proportional share of the proceeds from new debt issued by Gulfstream. The new debt was issued to refinance Gulfstream’s debt maturities. Subsequently, we contributed $248 million and $148 million to Gulfstream for our 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, 2018 2017 (Millions) Assets (liabilities): Current assets $ 834 $ 447 Noncurrent assets 13,199 9,181 Current liabilities (605 ) (295 ) Noncurrent liabilities (2,491 ) (1,538 ) Years Ended December 31, 2018 2017 2016 (Millions) Gross revenue $ 2,411 $ 1,961 $ 1,883 Operating income 804 871 799 Net income 795 806 726

Other Income and Expenses

Other Income and Expenses	12 Months Ended
	Dec. 31, 2018
Other Income and Expenses [Abstract]
Other Income and Expenses [Text Block]	Note 7 – Other Income and Expenses The following table presents certain gains or losses reflected in Other (income) expense – net within Costs and expenses in the Consolidated Statement of Operations : Years Ended December 31, 2018 2017 2016 (Millions) Atlantic-Gulf Amortization of regulatory assets associated with asset retirement obligations $ 33 $ 33 $ 33 Accrual of regulatory liability related to overcollection of certain employee expenses 22 22 25 Project development costs related to Constitution (Note 4) 4 16 28 Gains on asset retirements (12 ) — (11 ) West Gains on contract settlements and terminations — (15 ) — Regulatory charge per approved rates related to Tax Reform 24 — — Charge for regulatory liability associated with the decrease in Northwest Pipeline’s estimated deferred state income tax rates following WPZ Merger 12 — — Other Gain on sale of Refinery Grade Propylene Splitter — (12 ) — Loss on sale of Canadian operations (Note 3) — 5 66 Net foreign currency exchange (gains) losses (1) — — 10 Gain on sale of unused pipe — — (10 ) Benefit of regulatory asset associated with increase in Transco’s estimated deferred state income tax rate following WPZ Merger (37 ) — — ________________ (1) Primarily relates to gains and losses incurred on foreign currency transactions and the remeasurement of U.S. dollar-denominated current assets and liabilities within our former Canadian operations (see Note 3 – Divestitures ). Additional Items Certain additional items included in the Consolidated Statement of Operations are as follows: • Service revenues for the year ended December 31, 2016, includes $173 million associated with the amortization of deferred income related to the restructuring of certain gas gathering contracts in the Barnett Shale and Mid-Continent regions within the West segment. • Service revenues for the year ended December 31, 2016 were reduced by $15 million related to potential refunds associated with a ruling received in certain rate case litigation within the Atlantic-Gulf segment. • Selling, general, and administrative expenses for the year ended December 31, 2018, includes a $35 million charge associated with a charitable contribution of preferred stock to The Williams Companies Foundation, Inc. (a not-for-profit corporation) within the Other segment (see Note 15 – Stockholders' Equity ). Selling, general, and administrative expenses for the year ended December 31, 2018, also includes $20 million for WPZ Merger related costs within the Other segment. • Selling, general, and administrative expenses and Operating and maintenance expenses for the year ended December 31, 2017, included $22 million in severance and other related costs within the Other segment. The year ended December 31, 2016, included $42 million in severance and other related costs associated with an approximate 10 percent reduction in workforce in the first quarter of 2016, comprised of $3 million associated with the Northeast G&P segment, $8 million associated with the Atlantic-Gulf segment, $13 million associated with the West segment, and $18 million associated with the Other segment. • Selling, general, and administrative expenses for the years ended December 31, 2017 and 2016 included $9 million and $47 million , respectively, of costs associated with our evaluation of strategic alternatives within the Other segment. Selling, general, and administrative expenses for the year ended December 31, 2016, also included $61 million of project development costs related to a proposed propane dehydrogenation facility in Alberta, Canada within the Other segment. Beginning in the first quarter of 2016, these costs did not qualify for capitalization. • Other income (expense) – net below Operating income (loss) includes $89 million , $71 million , and $66 million for equity AFUDC primarily within the Atlantic-Gulf segment for the years ended December 31, 2018, 2017, and 2016, respectively. Other income (expense) – net below Operating income (loss) also includes $35 million , $52 million , and $23 million for the years ended December 31, 2018, 2017, and 2016, respectively, of income associated with regulatory assets related to the effects of deferred taxes on equity funds used during construction primarily within the Other segment. • Other income (expense) – net below Operating income (loss) for the year ended December 31, 2018, includes a $7 million net loss associated with the March 28, 2018, early retirement of $750 million of 4.875 percent senior unsecured notes that were due in 2024. The net loss within the Other segment reflects $34 million in premiums paid, partially offset by $27 million of unamortized premium. The year ended December 31, 2017, included a net gain of $30 million associated with the February 23, 2017, early retirement of $750 million of 6.125 percent senior unsecured notes that were due in 2022 and a net loss of $3 million associated with the July 3, 2017, early retirement of $1.4 billion of 4.875 percent senior unsecured notes that were due in 2023. The net gain for the February 23, 2017, early retirement within the Other segment reflects $53 million of unamortized premium, partially offset by $23 million in premiums paid. The net loss for the July 3, 2017, early retirement within the Other segment reflects $51 million of unamortized premium, offset by $54 million in premiums paid (see Note 14 – Debt, Banking Arrangements, and Leases ). • Other income (expense) – net below Operating income (loss) includes settlement charge expense related to the program to pay out certain deferred vested pension benefits as follows (see Note 10 – Employee Benefit Plans ): Years Ended December 31, 2018 2017 (Millions) Atlantic-Gulf $ 7 $ 15 Northeast 4 7 West 6 13 Other 5 35 • Other income (expense) – net below Operating income (loss) for the year ended December 31, 2017, included a $102 million charge for regulatory assets associated with the effects of deferred taxes on equity funds used during construction as a result of Tax Reform, comprised of $33 million within the Atlantic-Gulf segment, $6 million within the West segment, and $63 million within the Other segment (see Note 1 – General, Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies ).

Provision (Benefit) for Income

Provision (Benefit) for Income Taxes	12 Months Ended
	Dec. 31, 2018
Income Tax Disclosure [Abstract]
Provision (Benefit) for Income Taxes [Text Block]	Note 8 – Provision (Benefit) for Income Taxes The Provision (benefit) for income taxes includes: Years Ended December 31, 2018 2017 2016 (Millions) Current: Federal $ (83 ) $ 15 $ — State 1 23 2 Foreign — — (1 ) (82 ) 38 1 Deferred: Federal 183 (2,004 ) (6 ) State 37 (8 ) 61 Foreign — — (81 ) 220 (2,012 ) (26 ) Provision (benefit) for income taxes $ 138 $ (1,974 ) $ (25 ) Reconciliations from the Provision (benefit) at statutory rate to recorded Provision (benefit) for income taxes are as follows: Years Ended December 31, 2018 2017 2016 (Millions) Provision (benefit) at statutory rate $ 69 $ 187 $ (131 ) Increases (decreases) in taxes resulting from: Impact of nontaxable noncontrolling interests (73 ) (117 ) (22 ) Federal Tax Reform rate change — (1,932 ) — State income taxes (net of federal benefit) (10 ) (17 ) 3 State deferred income tax rate change 38 26 43 Foreign operations – net (including tax effect of Canadian Sale) — (127 ) 78 Valuation allowance 105 — — Translation adjustment of certain unrecognized tax benefits — — (1 ) Other – net 9 6 5 Provision (benefit) for income taxes $ 138 $ (1,974 ) $ (25 ) Income (loss) before income taxes includes $3 million , $7 million , and $885 million of foreign loss in 2018, 2017, and 2016, respectively. Foreign operations – net (including tax effect of Canadian Sale) in 2016 reflects a valuation allowance associated with impairments and losses on the sale of our Canadian operations (see Note 3 – Divestitures ) and the reversal of anticipatory foreign tax credits, partially offset by the tax effect of the impairments associated with our Canadian disposition. 2017 reflects the release of this valuation allowance. On December 22, 2017, Tax Reform was enacted. Most of the provisions of Tax Reform were effective after January 1, 2018. However, the deferred tax impact of reducing the U.S. corporate tax rate from 35 percent to 21 percent was recognized in the period of enactment. This remeasurement resulted in a reduction of our deferred tax liabilities of approximately $1.9 billion, with a corresponding net adjustment to Provision (benefit) for income taxes in 2017. During the course of audits of our business by domestic and foreign tax authorities, we frequently face challenges regarding the amount of taxes due. These challenges include questions regarding the timing and amount of deductions and the allocation of income among various tax jurisdictions. In evaluating the liability associated with our various filing positions, we apply the two-step process of recognition and measurement. In association with this liability, we record an estimate of related interest and tax exposure as a component of our tax provision. The impact of this accrual is included within Other – net in our reconciliation of the Provision (benefit) at statutory rate to recorded Provision (benefit) for income taxes . Significant components of Deferred income tax liabilities and Deferred income tax assets are as follows. Following the WPZ Merger, the attributes below are presented based on the underlying assets. December 31, 2018 2017 (Millions) Deferred income tax liabilities: Property, plant and equipment $ 2,317 $ — Investments 295 3,565 Other 30 19 Total deferred income tax liabilities 2,642 3,584 Deferred income tax assets: Accrued liabilities 667 53 Minimum tax credit 71 155 Foreign tax credit 140 140 Federal loss carryovers 147 — State losses and credits 319 283 Other 94 30 Total deferred income tax assets 1,438 661 Less valuation allowance 320 224 Net deferred income tax assets 1,118 437 Overall net deferred income tax liabilities $ 1,524 $ 3,147 The valuation allowance at December 31, 2018 and 2017 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, which incorporates available tax planning strategies, and management’s estimate of future reversals of existing taxable temporary differences, and have determined that a portion of our deferred income tax assets related to the Foreign tax credit and State losses and credits may not be realized. The Valuation allowance change from 2017 is primarily due to a $105 million valuation allowance associated with foreign tax credits, that expire between 2024 and 2028. The completion of the WPZ Merger (see Note 1 – General, Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies ) was a taxable exchange to the WPZ unit holders, which resulted in an adjustment to the tax basis in the underlying assets deemed acquired. A reduction to the deferred tax liability of $1.829 billion related to the book-tax basis difference in this investment has been recorded. Increased tax depreciation from the additional tax basis will reduce future taxable income, which serves to impact our expected realization of the Foreign tax credit . The amounts presented in the table above are, with respect to state items, before any federal benefit. The change from prior year for the State losses and credits reflects increases in losses and credits generated in the current and prior years less losses and/or credits utilized in the current year. We have loss and credit carryovers in multiple state taxing jurisdictions. Additionally, valuation allowances on state net operating losses decreased by $31 million after the completion of the WPZ Merger. These attributes generally expire between 2019 and 2038 with some carryovers having indefinite carryforward periods. The remaining federal Minimum tax credit of $71 million will be refunded/utilized no later than 2021. Federal loss carryovers includes deferred tax assets of $5 million at the end of 2018 that are expected to be utilized by us prior to expiration between 2019 and 2023. Deferred tax assets on net operating loss carryovers of $142 million have no expiration date. Cash payments for income taxes (net of refunds) were $11 million , $28 million , and $5 million in 2018, 2017, and 2016, respectively. As of December 31, 2018 , we had approximately $51 million of unrecognized tax benefits. If recognized, income tax expense would be reduced by $51 million and $50 million for 2018 and 2017, 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: 2018 2017 (Millions) Balance at beginning of period $ 50 $ 50 Additions for tax positions of prior years 1 — Balance at end of period $ 51 $ 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 expenses of $800 thousand and $300 thousand for 2018 and 2016, respectively, and a benefit of $400 thousand for 2017. Approximately $3 million and $2 million of interest and penalties primarily relating to uncertain tax positions have been accrued as of December 31, 2018 and 2017 , 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 Internal Revenue Service (IRS) examination for years after 2010. As of December 31, 2018, 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 2013. Tax years 2013 through 2016 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.

Earnings (Loss) Per Common Shar

Earnings (Loss) Per Common Share	12 Months Ended
	Dec. 31, 2018
Earnings Per Share [Abstract]
Earnings (Loss) Per Common Share [Text Block]	Note 9 – Earnings (Loss) Per Common Share Years Ended December 31, 2018 2017 2016 (Dollars in millions, except per-share amounts; shares in thousands) Net income (loss) available to common stockholders $ (156 ) $ 2,174 $ (424 ) Basic weighted-average shares 973,626 826,177 750,673 Effect of dilutive securities: Nonvested restricted stock units — 1,704 — Stock options — 637 — Diluted weighted-average shares (1) 973,626 828,518 750,673 Earnings (loss) per common share: Basic $ (.16 ) $ 2.63 $ (.57 ) Diluted $ (.16 ) $ 2.62 $ (.57 ) ________________ (1) For the years ended December 31, 2018 and December 31, 2016, 2.0 million and 0.6 million weighted-average nonvested restricted stock units, respectively, and 0.5 million and 0.5 million weighted-average stock options, respectively, have been excluded from the computation of diluted earnings (loss) per common share as their inclusion would be antidilutive due to our loss attributable to The Williams Companies, Inc.

Employee Benefit Plans

Employee Benefit Plans	12 Months Ended
	Dec. 31, 2018
Retirement Benefits [Abstract]
Employee Benefit Plans [Text Block]	Note 10 – Employee Benefit Plans We have noncontributory defined benefit pension plans in which all eligible employees participate. Currently, eligible employees earn benefits primarily based on a cash balance formula. At the time of retirement, participants may elect, to the extent they are eligible for the various options, to receive annuity payments, a lump-sum payment, or a combination of annuity and lump-sum payments. In addition to our pension plans, we currently provide subsidized retiree medical and life insurance benefits (other postretirement benefits) to certain eligible participants. Generally, employees hired after December 31, 1991, are not eligible for the subsidized retiree medical benefits, except for participants that were employees or retirees of Transco Energy Company on December 31, 1995. Subsidized retiree medical benefits for eligible participants age 65 and older are paid through contributions to health reimbursement accounts. Subsidized retiree medical benefits for eligible participants under age 65 are provided through a self-insured medical plan sponsored by us. The self-insured retiree medical plan provides for retiree contributions and contains other cost-sharing features such as deductibles, co-payments, and co-insurance. The accounting for this plan anticipates estimated future increases to our contribution levels to the health reimbursement accounts for participants age 65 and older, as well as future cost-sharing that is consistent with our expressed intent to increase the retiree contribution level generally in line with health care cost increases for participants under age 65. In November 2018, we announced changes to our defined benefit pension plans and our defined contribution plan. Eligible employees hired or rehired on or after January 1, 2019, will not be eligible to participate in the pension plan, but will be eligible for an additional fixed annual contribution made by us to the defined contribution plan. Additionally, as of January 1, 2020, certain active eligible employees will no longer receive future compensation credits under the defined benefit pension plan, but will be eligible for an additional fixed annual contribution made by us to the defined contribution plan. Also as of January 1, 2020, certain active eligible employees will continue to receive compensation credits under the defined benefit pension plans and these employees will not be eligible to receive the fixed annual contribution under the defined contribution plan. As a result of this amendment, a curtailment gain and a prior service credit were recorded to Accumulated other comprehensive income (loss) . The amounts of the curtailment gain and prior service credit were not significant and are reported in Net actuarial gain (loss) within the subsequent tables of changes in benefit obligations, amounts included in Accumulated other comprehensive income (loss), and other changes in plan assets and benefit obligations recognized in other comprehensive income (loss) before taxes. In 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 and August 2018, lump-sum payments were made, and annuity payments commenced in relation to this program. As a result of these lump-sum payments, as well as lump-sum benefit payments made throughout 2017 and 2018, settlement accounting was required. We settled $103 million in liabilities of our pension plans in 2018 and $261 million in 2017 and recognized pre-tax, noncash settlement charges of $23 million in 2018 and $71 million in 2017, which are substantially reported in Other income (expense) – net below Operating income (loss) in the Consolidated Statement of Operations (see Note 7 – Other Income and Expenses ). These amounts are included within the subsequent tables of 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 2018 2017 2018 2017 (Millions) Change in benefit obligation: Benefit obligation at beginning of year $ 1,319 $ 1,466 $ 206 $ 197 Service cost 50 50 1 1 Interest cost 46 59 7 8 Plan participants’ contributions — — 2 3 Benefits paid (35 ) (35 ) (13 ) (14 ) Net actuarial loss (gain) (90 ) 40 (17 ) 11 Settlements (103 ) (261 ) — — Net increase (decrease) in benefit obligation (132 ) (147 ) (20 ) 9 Benefit obligation at end of year 1,187 1,319 186 206 Change in plan assets: Fair value of plan assets at beginning of year 1,227 1,254 227 208 Actual return on plan assets (45 ) 184 (7 ) 25 Employer contributions 88 85 5 5 Plan participants’ contributions — — 2 3 Benefits paid (35 ) (35 ) (13 ) (14 ) Settlements (103 ) (261 ) — — Net increase (decrease) in fair value of plan assets (95 ) (27 ) (13 ) 19 Fair value of plan assets at end of year 1,132 1,227 214 227 Funded status — overfunded (underfunded) $ (55 ) $ (92 ) $ 28 $ 21 Accumulated benefit obligation $ 1,171 $ 1,294 The overfunded (underfunded) status of our pension plans and other postretirement benefit plan presented in the previous table are recognized in the Consolidated Balance Sheet within the following accounts: December 31, 2018 2017 (Millions) Underfunded pension plans: Current liabilities $ (2 ) $ (2 ) Noncurrent liabilities (53 ) (90 ) Overfunded (underfunded) other postretirement benefit plan: Current liabilities (6 ) (6 ) Noncurrent assets 34 27 The plan assets within our other postretirement benefit plan is intended to be used for the payment of benefits for certain groups of participants. The Current liabilities for the other postretirement benefit plan represent the current portion of benefits expected to be payable in the subsequent year for the groups of participants whose benefits are not expected to be paid from plan assets. The pension plans’ benefit obligation Net actuarial loss (gain) of $ (90) million in 2018 is primarily due to the impact of an increase in the discount rates utilized to calculate the benefit obligation. The pension plans’ benefit obligation Net 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 2018 benefit obligation Net actuarial loss (gain) of $ (17) million for our other postretirement benefit plan is primarily due to an increase in the discount rate used to calculate the benefit obligation. The 2017 benefit obligation Net actuarial loss (gain) of $11 million for our other postretirement benefit plan is primarily due to a decrease in the discount rate used to calculate the benefit obligation. At December 31, 2018 , one of our pension plans had plan assets in excess of its accumulated benefit obligation. For our other pension plans, the accumulated benefit obligation of $367 million exceeded plan assets of $326 million . All of our pension plans had a projected benefit obligation in excess of plan assets at December 31, 2018 . At December 31, 2017 , 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 2018 2017 2018 2017 (Millions) Amounts included in Accumulated other comprehensive income (loss) : Net actuarial loss $ (347 ) $ (375 ) $ (12 ) $ (21 ) Amounts included in regulatory liabilities associated with Transco and Northwest Pipeline: Prior service credit N/A N/A $ — $ 2 Net actuarial gain N/A N/A 4 14 In addition to the regulatory liabilities included in the previous table, differences in the amount of actuarially determined Net periodic benefit cost (credit) for our other postretirement benefit plan and the other postretirement benefit costs recovered in rates for Transco and Northwest Pipeline are deferred as a regulatory asset or liability. We have regulatory liabilities of $116 million at December 31, 2018 and $108 million at December 31, 2017 , 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, 2018 and 2017 , these regulatory liabilities were $49 million and $33 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 2018 2017 2016 2018 2017 2016 (Millions) Components of net periodic benefit cost (credit): Service cost $ 50 $ 50 $ 54 $ 1 $ 1 $ 1 Interest cost 46 59 62 7 8 8 Expected return on plan assets (63 ) (82 ) (85 ) (11 ) (11 ) (12 ) Amortization of prior service credit — — — (2 ) (13 ) (15 ) Amortization of net actuarial loss 23 27 30 — — — Net actuarial loss from settlements 23 71 2 — — — Reclassification to regulatory liability — — — 2 3 4 Net periodic benefit cost (credit) $ 79 $ 125 $ 63 $ (3 ) $ (12 ) $ (14 ) The components of Net periodic benefit cost (credit) other than the service cost component are included in Other income (expense) – net below Operating income (loss) in the Consolidated Statement of Operations . Items Recognized in Other Comprehensive Income (Loss) and Regulatory Assets and Liabilities Other changes in plan assets and benefit obligations recognized in Other comprehensive income (loss) before taxes for the years ended December 31 consist of the following: Pension Benefits Other Postretirement Benefits 2018 2017 2016 2018 2017 2016 (Millions) Other changes in plan assets and benefit obligations recognized in Other comprehensive income (loss) : Net actuarial gain (loss) $ (18 ) $ 62 $ (23 ) $ 9 $ (3 ) $ — Amortization of prior service credit — — — — (5 ) (6 ) Amortization of net actuarial loss 23 27 30 — — — Net actuarial loss from settlements 23 71 2 — — — Other changes in plan assets and benefit obligations recognized in Other comprehensive income (loss) $ 28 $ 160 $ 9 $ 9 $ (8 ) $ (6 ) Other changes in plan assets and benefit obligations for our other postretirement benefit plan associated with Transco and Northwest Pipeline are recognized in regulatory assets and liabilities. Amounts recognized in regulatory assets and liabilities for the years ended December 31 consist of the following: 2018 2017 2016 (Millions) Other changes in plan assets and benefit obligations recognized in regulatory (assets) and liabilities: Net actuarial gain (loss) $ (10 ) $ 6 $ 2 Amortization of prior service credit (2 ) (8 ) (9 ) Key Assumptions The weighted-average assumptions utilized to determine benefit obligations as of December 31 are as follows: Pension Benefits Other Postretirement Benefits 2018 2017 2018 2017 Discount rate 4.34 % 3.66 % 4.39 % 3.71 % Rate of compensation increase 4.83 4.93 N/A N/A Cash balance interest crediting rate 4.25 4.25 N/A N/A The weighted-average assumptions utilized to determine Net periodic benefit cost (credit) for the years ended December 31 are as follows: Pension Benefits Other Postretirement Benefits 2018 2017 2016 2018 2017 2016 Discount rate 3.67 % 4.17 % 4.37 % 3.71 % 4.27 % 4.50 % Expected long-term rate of return on plan assets 5.34 6.45 6.85 4.95 5.53 6.11 Rate of compensation increase 4.93 4.87 4.88 N/A N/A N/A Cash balance interest crediting rate 4.25 4.25 4.25 N/A N/A N/A The mortality assumptions used to determine the benefit obligations for our pension and other postretirement benefit plans reflect generational projection mortality tables. The assumed health care cost trend rate for 2019 is 7.5 percent . This rate decreases to 4.5 percent by 2026 . 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 38 percent of the other postretirement benefit plan assets are subject to income tax; therefore, certain investments are managed in a tax efficient manner. The investment policy for the pension plans includes a general target asset allocation at December 31, 2018 , of 25 percent equity securities and 75 percent fixed income securities. The target allocation includes the investments in equity and fixed income mutual funds and commingled investment funds. 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, 2018 and 2017 by asset class are as follows: 2018 Quoted Prices Significant Significant Total (Millions) Pension assets: Cash management fund $ 10 $ — $ — $ 10 Equity securities: U.S. large cap 30 — — 30 U.S. small cap 22 — — 22 Fixed income securities (1): U.S. Treasury securities 157 — — 157 Government and municipal bonds — 21 — 21 Mortgage and asset-backed securities — 48 — 48 Corporate bonds — 210 — 210 Insurance company investment contracts and other — 6 — 6 $ 219 $ 285 $ — 504 Commingled investment funds measured at net asset value practical expedient (2): Equities — U.S. large cap 123 Equities — International small cap 8 Equities — International emerging markets 19 Equities — International developed markets 51 Fixed income — U.S. long duration 335 Fixed income — Corporate bonds 92 Total assets at fair value at December 31, 2018 $ 1,132 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 The fair values of our other postretirement benefits plan assets at December 31, 2018 and 2017 by asset class are as follows: 2018 Quoted Prices Significant Significant Total (Millions) Other postretirement benefit assets: Cash management funds $ 11 $ — $ — $ 11 Equity securities: U.S. large cap 20 — — 20 U.S. small cap 9 — — 9 International developed markets large cap growth — 5 — 5 Fixed income securities (1): U.S. Treasury securities 19 — — 19 Government and municipal bonds — 2 — 2 Mortgage and asset-backed securities — 6 — 6 Corporate bonds — 25 — 25 Mutual fund — Municipal bonds 43 — — 43 $ 102 $ 38 $ — 140 Commingled investment funds measured at net asset value practical expedient (2): Equities — U.S. large cap 14 Equities — International small cap 1 Equities — International emerging markets 2 Equities — International developed markets 6 Fixed income — U.S. long duration 40 Fixed income — Corporate bonds 11 Total assets at fair value at December 31, 2018 $ 214 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 ____________ (1) The weighted-average credit quality rating of the fixed income security portfolio is investment grade with a weighted-average duration of approximately 13 years for 2018 and 12 years for 2017 . (2) The stated intents of the funds vary based on each commingled fund’s investment objective. These objectives generally include strategies to replicate or outperform various market indices. Certain standard withdrawal restrictions generally apply, which may include redemption notification period restrictions ranging from 10 days to 30 days . Additionally, the fund managers retain the right to restrict withdrawals from and/or purchases into the funds so as not to disadvantage other investors in the funds. Generally, the funds also reserve the right to make all or a portion of the redemption in-kind rather than in cash or a combination of cash and in-kind. 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, 2018 and 2017 . Additionally, there were no transfers or reclassifications of investments between Level 1 and Level 2 from December 2017 to December 2018 . 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) 2019 $ 85 $ 14 2020 87 14 2021 90 13 2022 90 14 2023 89 14 2024-2028 467 59 In 2019 , we expect to contribute approximately $60 million to our tax-qualified pension plans and approximately $3 million to our nonqualified pension plans, for a total of approximately $63 million , and approximately $6 million to our other postretirement benefit plans. Defined Contribution Plan We also maintain a defined contribution plan 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 plan’s guidelines. We match employees’ contributions up to certain limits. Our matching contributions charged to expense were $35 million in 2018 , $34 million in 2017 , and $36 million in 2016 .

Property, Plant, and Equipment

Property, Plant, and Equipment	12 Months Ended
	Dec. 31, 2018
Property, Plant and Equipment [Abstract]
Property, Plant, and Equipment [Text Block]	Note 11 – Property, Plant, and Equipment The following table presents nonregulated and regulated Property, plant, and equipment – net as presented on the Consolidated Balance Sheet for the years ended: Estimated Useful Life (1) (Years) Depreciation Rates (1) (%) December 31, 2018 2017 (Millions) Nonregulated: Natural gas gathering and processing facilities 5 - 40 $ 15,324 $ 18,440 Construction in progress Not applicable 778 566 Other 2 - 45 2,356 2,776 Regulated: Natural gas transmission facilities 1.20 - 6.97 17,312 14,460 Construction in progress Not applicable Not applicable 965 1,637 Other 5 - 45 1.35 - 33.33 1,926 1,634 Total property, plant, and equipment, at cost 38,661 39,513 Accumulated depreciation and amortization (11,157 ) (11,302 ) Property, plant, and equipment — net $ 27,504 $ 28,211 __________ (1) Estimated useful life and depreciation rates are presented as of December 31, 2018 . Depreciation rates and estimated useful lives for regulated assets are prescribed by the FERC. Depreciation and amortization expense for Property, plant, and equipment – net was $1.392 billion , $1.389 billion , and $1.407 billion in 2018 , 2017 , and 2016 , respectively. Regulated Property, plant, and equipment – net includes approximately $586 million and $626 million at December 31, 2018 and 2017 , 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 $968 million and $946 million are included in Regulatory liabilities, deferred income, and other with the remaining current portion in Accrued liabilities at December 31, 2018 and 2017 , respectively. December 31, 2018 2017 (Millions) Beginning balance $ 998 $ 862 Liabilities incurred 21 33 Liabilities settled (19 ) (16 ) Accretion expense (1) 71 141 Revisions (2) (39 ) (22 ) Ending balance $ 1,032 $ 998 ___________ (1) The decrease in accretion expense in 2018 primarily reflects the absence of a 2017 adjustment associated with obligations identified from certain Transco land agreements. (2) Several factors are considered in the annual review process, including inflation rates, current estimates for removal cost, market risk premiums, discount rates, and the estimated remaining useful life of the assets. The 2018 revisions reflect changes in removal cost estimates, decreases in the estimated remaining useful life of certain assets and increases in the discount rates used in the annual review process. The 2017 revisions reflect changes in removal cost estimates and decreases in the estimated remaining useful life of certain assets and discount rates used in the annual review process. The funds Transco collects through a portion of its rates to fund its ARO are deposited into an external trust account dedicated to funding its ARO (ARO Trust). (See Note 17 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk .) Under its current rate settlement, Transco’s annual funding obligation is approximately $36 million , with installments to be deposited monthly.

Other Intangible Assets

Other Intangible Assets	12 Months Ended
	Dec. 31, 2018
Goodwill and Intangible Assets Disclosure [Abstract]
Other Intangible Assets [Text Block]	Note 12 – 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: 2018 2017 Gross Carrying Amount Accumulated Amortization Gross Carrying Amount Accumulated Amortization (Millions) Contractual customer relationships $ 9,232 $ (1,465 ) $ 10,027 $ (1,283 ) Other intangible assets primarily relate to gas gathering, processing, and fractionation contractual customer relationships recognized in acquisitions. The decrease in the gross carrying amount of other intangible assets during 2018 is primarily related to the impairment of certain assets located in the Barnett Shale and the deconsolidation of our interest in Jackalope (see Note 17 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk and Note 6 – Investing Activities , respectively). These decreases are the primary reasons for the difference between the change in accumulated amortization during 2018 indicated above and the amortization expense for 2018 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 (the weighted-average periods prior to the next renewal or extension of the associated contractual customer relationships as estimated at the time of the acquisition). 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 $333 million , $347 million , and $356 million in 2018 , 2017 , and 2016 , respectively. The estimated amortization expense for each of the next five succeeding fiscal years is approximately $312 million .

Accrued Liabilities

Accrued Liabilities	12 Months Ended
	Dec. 31, 2018
Accrued Liabilities, Current [Abstract]
Accrued Liabilities [Text Block]	Note 13 – Accrued Liabilities December 31, 2018 2017 (Millions) Interest on debt $ 282 $ 267 Revenue contract liabilities (Note 2) 244 361 Employee costs 205 202 Other, including other loss contingencies 371 337 $ 1,102 $ 1,167

Debt, Banking Arrangements, and

Debt, Banking Arrangements, and Leases	12 Months Ended
	Dec. 31, 2018
Debt Disclosure [Abstract]
Debt, Banking Arrangements, and Leases [Text Block]	Note 14 – Debt, Banking Arrangements, and Leases Long-Term Debt December 31, 2018 2017 (Millions) Transco: 6.05% Notes due 2018 $ — $ 250 7.08% Debentures due 2026 8 8 7.25% Debentures due 2026 200 200 7.85% Notes due 2026 1,000 1,000 4% Notes due 2028 400 — 5.4% Notes due 2041 375 375 4.45% Notes due 2042 400 400 4.6% Notes due 2048 600 — Other financing obligations 1,067 231 Northwest Pipeline: 6.05% Notes due 2018 — 250 7.125% Debentures due 2025 85 85 4% Notes due 2027 500 250 WMB: 4.125% Notes due 2020 600 600 5.25% Notes due 2020 1,500 1,500 4% Notes due 2021 500 500 7.875% Notes due 2021 371 371 3.35% Notes due 2022 750 750 3.6% Notes due 2022 1,250 1,250 3.7% Notes due 2023 850 850 4.5% Notes due 2023 600 600 4.3% Notes due 2024 1,000 1,000 4.55% Notes due 2024 1,250 1,250 4.875% Notes due 2024 — 750 3.9% Notes due 2025 750 750 4% Notes due 2025 750 750 3.75% Notes due 2027 1,450 1,450 7.5% Debentures due 2031 339 339 7.75% Notes due 2031 252 252 8.75% Notes due 2032 445 445 6.3% Notes due 2040 1,250 1,250 5.8% Notes due 2043 400 400 5.4% Notes due 2044 500 500 5.75% Notes due 2044 650 650 4.9% Notes due 2045 500 500 5.1% Notes due 2045 1,000 1,000 4.85% Notes due 2048 800 — Various — 7.625% to 10.25% Notes and Debentures due 2019 to 2027 55 55 Credit facility loans 160 270 Debt issuance costs (131 ) (122 ) Net unamortized debt premium (discount) (62 ) (24 ) Total long-term debt, including current portion 22,414 20,935 Long-term debt due within one year (47 ) (501 ) Long-term debt $ 22,367 $ 20,434 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 and other financing obligations, excluding net unamortized debt premium (discount) and debt issuance costs, for each of the next five years: December 31, 2018 (Millions) 2019 $ 47 2020 2,138 2021 890 2022 2,021 2023 1,633 Issuances and retirements On August 24, 2018, Northwest Pipeline issued $250 million of 4 percent senior unsecured notes to investors in a private debt placement. The notes are an additional issuance of Northwest Pipeline’s existing 4 percent senior unsecured notes due 2027. In the fourth quarter of 2018, Northwest Pipeline filed a registration statement and completed an exchange of these notes for substantially identical new notes that are registered under the Securities Act of 1933, as amended. Northwest Pipeline retired $250 million of 6.05 percent senior unsecured notes that matured on June 15, 2018. On March 5, 2018, WPZ completed a public offering of $800 million of 4.85 percent senior unsecured notes due 2048. WPZ used the net proceeds for general partnership purposes, primarily the March 28, 2018 repayment of $750 million of 4.875 percent senior unsecured notes that were due in 2024. On March 15, 2018, Transco issued $400 million of 4 percent senior unsecured notes due 2028 and $600 million of 4.6 percent senior unsecured notes due 2048 to investors in a private debt placement. Transco used the net proceeds to retire $250 million of 6.05 percent senior unsecured notes that matured on June 15, 2018, and for general corporate purposes, including the funding of capital expenditures. In the third quarter of 2018, Transco filed a registration statement and completed an exchange of these notes for substantially identical new notes that are registered under the Securities Act of 1933, as amended. 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 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. In the first quarter of 2018, Northwest Pipeline completed an exchange of these notes for substantially identical new notes that are registered under the Securities Act of 1933, as amended. 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. Other financing obligations During the construction of the Dalton expansion project, Transco 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 in our Consolidated Balance Sheet . Upon placing the project in service during the third quarter of 2017, Transco began utilizing this partner’s undivided interest in the lateral, including the associated pipeline capacity, and reclassified the 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 . Amounts related to this financing obligation included in debt within our Consolidated Balance Sheet were $260 million and $231 million at December 31, 2018 and 2017, respectively. During the construction of the Atlantic Sunrise project, Transco received funding from a partner for its proportionate share of construction costs related to an undivided ownership interest in certain parts of the project. Amounts received were recorded within noncurrent liabilities and 100 percent of the costs associated with construction were capitalized in our Consolidated Balance Sheet . Upon placing the project in service during the fourth quarter of 2018, Transco began utilizing this partner’s undivided interest in the lateral, including the associated pipeline capacity, and reclassified the 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 20 years . At December 31, 2018, $807 million related to this financing obligation was included in debt within our Consolidated Balance Sheet . Credit Facilities December 31, 2018 Stated Capacity Outstanding (Millions) Long-term credit facility (1) $ 4,500 $ 160 Letters of credit under certain bilateral bank agreements 14 ________________ (1) In managing our available liquidity, we do not expect a maximum outstanding amount in excess of the capacity of our credit facility inclusive of any outstanding amounts under our commercial paper program. Revolving credit facility On July 13, 2018, we along with Transco and Northwest Pipeline, the lenders named therein, and an administrative agent entered into a new credit agreement (Credit Agreement) with aggregate commitments available of $4.5 billion , with up to an additional $500 million increase in aggregate commitments available under certain circumstances. On August 10, 2018, following the completion of the WPZ Merger, the Credit Agreement became effective and we terminated both our and WPZ’s existing credit facilities. The maturity date of the new credit facility is August 10, 2023. However, the co-borrowers may request up to two extensions of the maturity date each for an additional one-year period to allow a maturity date as late as August 10, 2025, under certain circumstances. The Credit Agreement allows for swing line loans up to an aggregate of $200 million , subject to available capacity under the new credit facility, and letters of credit commitments of $1 billion . Transco and Northwest Pipeline are each able to borrow up to $500 million under this credit facility to the extent not otherwise utilized by the other co-borrowers. The Credit Agreement contains the following terms and conditions: • Various covenants may limit, among other things, a borrower’s and its material subsidiaries’ ability to grant certain liens supporting indebtedness, merge or consolidate, sell all or substantially all of its assets, make certain distributions during an event of default, and enter into certain restrictive agreements. • If an event of default with respect to a borrower occurs under the credit facility, the lenders will be able to terminate the commitments and accelerate the maturity of the loans and exercise other rights and remedies. • Other than swing line loans, each time funds are borrowed, the applicable borrower may choose from two methods of calculating interest: a fluctuating base rate equal to Citibank N.A.'s alternate base rate plus an applicable margin or a periodic fixed rate equal to the London Interbank Offered Rate plus an applicable margin. We are required to pay a commitment fee based on the unused portion of the credit facility. The applicable margin and the commitment fee are determined by reference to a pricing schedule based on the applicable borrower’s senior unsecured long-term debt ratings. Significant financial covenants under the Credit Agreement require the ratio of debt to EBITDA (earnings before interest, taxes, depreciation, and amortization), each as defined in the credit facility, to be no greater than: • 5.75 to 1 for each fiscal quarter end through June 30, 2019; • 5.5 to 1 for the fiscal quarters ending September 30, 2019, and December 31, 2019; • 5.0 to 1 for the fiscal quarter ending March 31, 2020, and each subsequent fiscal quarter end, except for the fiscal quarter and the two following fiscal quarters in which one or more acquisitions with a total aggregate purchase price of $25 million or more has been executed, in which case the ratio of debt to EBITDA is to be no greater than 5.5 to 1. The ratio of debt to capitalization (defined as net worth plus debt) must be no greater than 65 percent for each of Transco and Northwest Pipeline. At December 31, 2018, we are in compliance with these covenants. Commercial Paper Program On August 10, 2018, following the consummation of the WPZ Merger, WPZ’s $3 billion commercial paper program was discontinued and we entered into a new $4 billion commercial paper program. The maturities of the commercial paper notes vary but may not exceed 397 days from the date of issuance. The commercial paper notes are sold under customary terms in the commercial paper market and are issued at a discount from par, or, alternatively, are sold at par and bear varying interest rates on a fixed or floating basis. The net proceeds of issuances of the commercial paper notes are expected to be used to fund planned capital expenditures and for other general corporate purposes. At December 31, 2018 and 2017, no Commercial paper was outstanding. At February 19, 2019, no commercial paper was outstanding. Cash Payments for Interest (Net of Amounts Capitalized) Cash payments for interest (net of amounts capitalized) were $1.064 billion in 2018, $1.110 billion in 2017, and $1.152 billion in 2016. Leases-Lessee The future minimum annual rentals under noncancelable operating leases, are payable as follows: December 31, 2018 (Millions) 2019 $ 32 2020 31 2021 28 2022 24 2023 15 Thereafter 86 Total $ 216 Total rent expense was $73 million in 2018, $62 million in 2017, and $64 million in 2016 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, 2018
Stockholders' Equity Note [Abstract]
Stockholders' Equity [Text Block]	Note 15 – Stockholders' Equity On February 20, 2019 , our board of directors approved a regular quarterly dividend of $0.38 per share payable on March 25, 2019 . In July 2018, through a wholly owned subsidiary, we contributed 35,000 shares of newly issued Series B Non-Voting Perpetual Preferred Stock (Preferred Stock) to The Williams Companies Foundation, Inc. (a not-for-profit corporation) for use in future charitable and nonprofit causes. The charitable contribution of Preferred Stock was recorded as an expense in the third quarter of 2018. The Preferred Stock was issued for an aggregate value of $35 million and pays non-cumulative quarterly cash dividends when, as and if declared, at a rate of 7.25 percent per year. We paid dividends totaling $1.1 million on the shares of Preferred Stock in 2018. Our certificate of incorporation authorizes 30 million shares of Preferred Stock, $1 par value per share. In January 2017, we issued 65 million shares of common stock in a public offering at a price of $29.00 per share. In February 2017, we issued 9.75 million shares of common stock pursuant to the full exercise of the underwriter’s option to purchase additional shares. The net proceeds of approximately $2.1 billion were used to purchase newly issued common units in WPZ as part of our Financial Repositioning. (See Note 1 – General, Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies .) AOCI The following table presents the changes in AOCI by component, net of income taxes: Cash Flow Hedges Foreign Currency Translation Pension and Other Post Retirement Benefits Total (Millions) Balance at December 31, 2017 $ (2 ) $ (1 ) $ (235 ) $ (238 ) Adoption of new accounting standard (Note 1) — — (61 ) (61 ) WPZ Merger (Note 1) (3 ) — — (3 ) Other comprehensive income (loss): Other comprehensive income (loss) before reclassifications (2 ) — (6 ) (8 ) Amounts reclassified from accumulated other comprehensive income (loss) 5 — 35 40 Other comprehensive income (loss) 3 — 29 32 Balance at December 31, 2018 $ (2 ) $ (1 ) $ (267 ) $ (270 ) Reclassifications out of AOCI are presented in the following table by component for the year ended December 31, 2018 : Component Reclassifications Classification (Millions) Cash flow hedges: Energy commodity contracts $ 9 Product sales Pension and other postretirement benefits: Amortization of actuarial (gain) loss and net actuarial loss from settlements included in net periodic benefit cost (credit) 46 Note 10 – Employee Benefit Plans Total before tax 55 Income tax benefit (12 ) Provision (benefit) for income taxes Net of income tax 43 Noncontrolling interest (3 ) Net income (loss) attributable to noncontrolling interests Reclassifications during the period $ 40

Equity-Based Compensation

Equity-Based Compensation	12 Months Ended
	Dec. 31, 2018
Share-based Compensation [Abstract]
Equity-Based Compensation [Text Block]	Note 16 – Equity-Based Compensation Williams’ Plan Information On May 17, 2007, our stockholders approved The Williams Companies, Inc. 2007 Incentive Plan (the Plan) that provides common-stock-based awards to both employees and nonmanagement directors and reserved 19 million new shares for issuance. On May 20, 2010 and May 22, 2014, our stockholders approved amendments and restatements of the Plan to increase by 11 million and 10 million , respectively, the number of new shares authorized for making awards under the Plan, among other changes. The Plan permits the granting of various types of awards including, but not limited to, restricted stock units and stock options. At December 31, 2018 , 24 million shares of our common stock were reserved for issuance pursuant to existing and future stock awards, of which 12 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 338 thousand shares at an average price of $20.70 per share during 2018 . Approximately 746 thousand shares were available for purchase under the ESPP at December 31, 2018 . Operating and maintenance expenses and Selling, general, and administrative expenses include equity-based compensation expense for the years ended December 31, 2018 , 2017 , and 2016 of $54 million , $70 million , and $53 million , respectively. Income tax benefit recognized related to the stock-based compensation expense for the years ended December 31, 2018 , 2017 , and 2016 was $14 million , $17 million , and $20 million , respectively. Measured but unrecognized stock-based compensation expense at December 31, 2018 , was $56 million , comprised of $4 million related to stock options and $52 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, 2018 : Stock Options Options Weighted- Average Exercise Price Aggregate Intrinsic Value (Millions) (Millions) Outstanding at December 31, 2017 6.6 $ 31.53 Granted 1.3 $ 29.09 Exercised (0.4 ) $ 23.06 Cancelled (0.2 ) $ 31.45 Outstanding at December 31, 2018 7.3 $ 31.55 $ 6 Exercisable at December 31, 2018 5.3 $ 32.63 $ 6 The following table summarizes additional information related to stock option activity during each of the last three years: Years Ended December 31, 2018 2017 2016 (Millions) Total intrinsic value of options exercised $ 3 $ 4 $ 2 Tax benefits realized on options exercised $ — $ 1 $ 1 Cash received from the exercise of options $ 9 $ 7 $ 4 The weighted-average remaining contractual life for stock options outstanding and exercisable at December 31, 2018 , was 5.1 years and 3.7 years , respectively. The estimated fair value at date of grant of options for our common stock granted in each respective year, using the Black-Scholes option pricing model, is as follows: 2018 2017 2016 Weighted-average grant date fair value of options for our common stock granted during the year, per share $ 5.49 $ 6.61 $ 7.90 Weighted-average assumptions: Dividend yield 4.7 % 4.2 % 3.2 % Volatility 30.1 % 35.1 % 44.7 % Risk-free interest rate 2.7 % 2.1 % 1.2 % Expected life (years) 6.0 6.0 6.0 The 2018 expected dividend yield is based on the 2018 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, 2018 : Restricted Stock Units Outstanding Shares Weighted- Average Fair Value (1) (Millions) Nonvested at December 31, 2017 4.2 $ 31.02 Granted 1.7 $ 30.48 Forfeited (0.5 ) $ 32.97 Vested (0.9 ) $ 39.30 Nonvested at December 31, 2018 4.5 $ 28.96 ______________ (1) Performance-based restricted stock units are valued considering measures of total shareholder return, utilizing a Monte Carlo valuation method, and return on capital employed. All other restricted stock units are valued at the grant-date market price. Restricted stock units generally vest after three years . Value of Restricted Stock Units 2018 2017 2016 Weighted-average grant date fair value of restricted stock units granted during the year, per share $ 30.48 $ 29.47 $ 26.51 Total fair value of restricted stock units vested during the year ($s in millions) $ 35 $ 33 $ 32 Performance-based restricted stock units granted under the Plan represent 34 percent of nonvested restricted stock units outstanding at December 31, 2018 . 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 the general partner of Access Midstream Partners, L.P. (ACMP) 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 February 2, 2015 merger of Williams Partners L.P. with and into Access Midstream Partners, L.P (which was subsequently renamed Williams Partners L.P.). During 2018, no additional grants of restricted common units were awarded through WPZ’s equity-based compensation programs, and all outstanding shares were vested and exercised. Equity-based compensation expense of less than $1 million , $8 million , and $20 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, 2018 , 2017 , and 2016 , respectively. The total fair value of the restricted common units vested during 2018 , 2017 , and 2016 was $5 million , $24 million , and $34 million , respectively. This plan is no longer active.

Fair Value Measurements, Guaran

Fair Value Measurements, Guarantees, and Concentration of Credit Risk	12 Months Ended
	Dec. 31, 2018
Fair Value Disclosures [Abstract]
Fair Value Measurements, Guarantees, and Concentration of Credit Risk [Text Block]	Note 17 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk The following table presents, by level within the fair value hierarchy, certain of our financial assets and liabilities. The carrying values of cash and cash equivalents, accounts receivable, margin deposits, and accounts payable approximate fair value because of the short-term nature of these instruments. Therefore, these assets and liabilities are not presented in the following table. Fair Value Measurements Using Carrying Amount Fair Value Quoted Prices In Active Markets for Identical Assets (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) (Millions) Assets (liabilities) at December 31, 2018: Measured on a recurring basis: ARO Trust investments $ 150 $ 150 $ 150 $ — $ — Energy derivatives assets not designated as hedging instruments 3 3 3 — — Energy derivatives liabilities not designated as hedging instruments (7 ) (7 ) (4 ) — (3 ) Additional disclosures: Long-term debt, including current portion (22,414 ) (23,330 ) — (23,330 ) — Guarantees (43 ) (30 ) — (14 ) (16 ) 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: Long-term debt, including current portion (20,935 ) (23,005 ) — (23,005 ) — Guarantees (43 ) (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 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, 2018 or 2017 . Additional fair value disclosures Long-term debt, including current portion : The disclosed fair value of our long-term debt is determined primarily by a market approach using broker quoted indicative period-end bond prices. The quoted prices are based on observable transactions in less active markets for our debt or similar instruments. The fair values of the financing obligations associated with our Dalton lateral and Atlantic Sunrise projects, which are included within long-term debt, were determined using an income approach (see Note 14 – 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 $29 million at December 31, 2018 . Our exposure declines systematically through the remaining term of WilTel’s obligation. The fair value of the guarantee associated with the indemnification related to a disposed operation was estimated using an income approach that considered probability-weighted scenarios of potential levels of future performance. The terms of the indemnification do not limit the maximum potential future payments associated with the guarantee. The carrying value of this guarantee is reported in Regulatory liabilities, deferred income, and other in the Consolidated Balance Sheet . We are required by our revolving credit agreement to indemnify lenders for certain taxes required to be withheld from payments due to the lenders and for certain tax payments made by the lenders. The maximum potential amount of future payments under these indemnifications is based on the related borrowings and such future payments cannot currently be determined. These indemnifications generally continue indefinitely unless limited by the underlying tax regulations and have no carrying value. We have never been called upon to perform under these indemnifications and have no current expectation of a future claim. Nonrecurring fair value measurements The following table presents impairments of assets and investments associated with certain nonrecurring fair value measurements within Level 3 of the fair value hierarchy, except as specifically noted. Impairments Years Ended December 31, Classification Segment Date of Measurement Fair Value 2018 2017 2016 (Millions) Certain gathering operations (1) Property, plant, and equipment – net and Intangible assets - net of accumulated amortization West December 31, 2018 $ 470 $ 1,849 Certain idle pipeline assets (2) Property, plant, and equipment – net Other June 30, 2018 25 66 Certain gathering operations (3) Property, plant, and equipment – net and Intangible assets - net of accumulated amortization West September 30, 2017 439 $ 1,019 Certain gathering operations (4) Property, plant, and equipment – net and Intangible assets - net of accumulated amortization Northeast G&P September 30, 2017 21 115 Certain NGL pipeline (5) Property, plant, and equipment – net Other September 30, 2017 32 68 Certain olefins pipeline project (6) Property, plant, and equipment – net Other June 30, 2017 18 23 Canadian operations (7) Assets held for sale Other June 30, 2016 1,130 $ 747 Certain gathering operations (8) Property, plant, and equipment – net West June 30, 2016 18 48 Certain idle pipeline assets Property, plant, and equipment – net Other December 31, 2016 73 8 Fair value measurements of certain assets 1,915 1,225 803 Other impairments and write-downs (9) — 23 70 Impairment of certain assets $ 1,915 $ 1,248 $ 873 Equity-method investments (10) Investments Northeast G&P December 31, 2018 $ 1,293 $ 32 Equity-method investments (11) Investments West and Northeast G&P December 31, 2016 1,295 $ 318 Impairments Years Ended December 31, Classification Segment Date of Measurement Fair Value 2018 2017 2016 (Millions) Equity-method investments (12) Investments West and Northeast G&P March 31, 2016 1,294 109 Other equity-method investment Investments West March 31, 2016 — 3 Impairment of equity-method investments $ 32 $ 430 ______________ (1) Relates to our gathering operations in the Barnett Shale. Certain of our contractual gathering rates, primarily those in the Barnett Shale, are based on a percentage of the New York Mercantile Exchange (NYMEX) natural gas prices. During the fourth quarter of 2018, we determined there was a sustained decline in the forward price curves for natural gas. During this same period, a large producer customer in the Barnett Shale removed their remaining drilling rig. These factors gave rise to an impairment evaluation of these assets, which incorporated management’s projections of future drilling activity and gathering rates, taking into consideration the information previously noted as well as recently available information regarding producer drilling cost assumptions in the basin. The resulting estimate of future undiscounted cash flows was less than our carrying value, necessitating the estimation of the fair value of these assets. To arrive at the fair value, we utilized an income approach with a discount rate of 8.5 percent , reflecting an estimated cost of capital and risks associated with the underlying assets. (2) Relates to certain idle pipelines. The estimated fair value was determined by a market approach incorporating information derived from bids received for these assets, which we marketed for sale together with certain other assets. These inputs resulted in a fair value measurement within Level 2 of the fair value hierarchy. We sold these assets in the fourth quarter of 2018. (See Note 3 – Divestitures .) (3) Relates to certain gathering operations in the Mid-Continent region. During the third quarter of 2017, we received solicitations and engaged in negotiations for the sale of certain of these assets which led to our impairment evaluation. The estimated fair value was determined using an income approach and incorporated market inputs based on ongoing negotiations for a potential sale of a portion of the underlying assets. For the income approach, we utilized a discount rate of 10.2 percent , reflecting an estimated cost of capital and risks associated with the underlying assets. (4) Relates to certain gathering operations in the Marcellus South region resulting from an anticipated decline in future volumes following a third-quarter 2017 shut-in by the primary producer. The estimated fair value was determined by the income approach utilizing a discount rate of 11.1 percent , reflecting an estimated cost of capital and risks associated with the underlying assets. (5) Relates to an NGL pipeline near the Houston Ship Channel region which we anticipated would be underutilized for the foreseeable future. The estimated fair value was primarily determined by using a market approach based on our analysis of observable inputs in the principal market. We sold these assets in the fourth quarter of 2018. (See Note 3 – Divestitures .) (6) Relates primarily to project development costs associated with an olefins pipeline project in the Gulf Coast region, the likelihood of completion we considered remote. The estimated fair value of the remaining pipe and equipment considered a market approach based on our analysis of observable inputs in the principal market, as well as an estimate of replacement cost. We sold these assets in the fourth quarter of 2018. (See Note 3 – Divestitures .) (7) Relates to our Canadian operations. We designated these operations as held for sale as of June 30, 2016. As a result, we measured the fair value of the disposal group, resulting in an impairment charge. The estimated fair value was determined by a market approach based primarily on inputs received in the marketing process and reflected our estimate of the potential assumed proceeds. We disposed of our Canadian operations through a sale during the third quarter of 2016. (See Note 3 – Divestitures .) (8) Relates to certain gathering assets within the Mid-Continent region. The estimated fair value was determined by a market approach based on our analysis of observable inputs in the principal market. (9) Reflects multiple individually insignificant impairments and write-downs of other certain assets that may no longer be in use or are surplus in nature for which the fair value was determined to be lower than the carrying value. (10) Relates to Northeast G&P’s equity-method investment in UEOM. The estimated fair value was determined by a market approach based on our analysis of inputs in the principal market. (11) Relates to West’s previously held interest in Ranch Westex and multiple, currently held Appalachia Midstream Investments at Northeast G&P. The historical carrying value of these equity-method investments was initially recorded based on estimated fair value during the third quarter of 2014 in conjunction with the acquisition of ACMP. We estimated the fair value of these Appalachia Midstream Investments using an income approach based on expected future cash flows and appropriate discount rates. The determination of estimated future cash flows involved significant assumptions regarding gathering volumes, rates, and related capital spending. The discount rate utilized for the Appalachia Midstream Investments evaluation was 10.2 percent and reflected an estimated cost of capital as impacted by market conditions and risks associated with the underlying businesses. In addition to utilizing an income approach, we also considered a market approach for certain Appalachia Midstream Investments and Ranch Westex based on an agreement reached in February 2017 to exchange our interests in DBJV and Ranch Westex for additional interests in certain Appalachia Midstream Investments and cash. (See Note 6 – Investing Activities .) (12) Relates to West’s previously held interest in DBJV and Northeast G&P’s currently held equity-method investment in Laurel Mountain. Our carrying values in these equity-method investments had been written down to fair value at December 31, 2015. Our first-quarter 2016 analysis reflected higher discount rates for both of these equity-method investments, along with lower natural gas prices for Laurel Mountain. We estimated the fair value of these equity-method investments using an income approach based on expected future cash flows and appropriate discount rates. The determination of estimated future cash flows involved significant assumptions regarding gathering volumes and related capital spending. Discount rates utilized ranged from 13.0 percent to 13.3 percent and reflected increases in the estimated cost of capital, revised estimates of expected future cash flows, and risks associated with the underlying businesses. Concentration of Credit Risk Trade accounts and other receivables The following table summarizes concentration of receivables, net of allowances: December 31, 2018 2017 (Millions) NGLs, natural gas, and related products and services $ 626 $ 760 Transportation of natural gas and related products 232 212 Other 134 4 Total $ 992 $ 976 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, 2018 and 2017 , Chesapeake Energy Corporation, and its affiliates (Chesapeake), a customer primarily within our Northeast G&P and West segments, accounted for $65 million and $176 million , respectively, of the consolidated Trade accounts and other receivables balances. The increase in Other is primarily due to an increase in our federal income tax receivable. Revenues In 2018 , 2017 , and 2016 , Chesapeake accounted for 8 percent , 10 percent , and 14 percent , respectively, of our consolidated revenues.

Contingent Liabilities and Comm

Contingent Liabilities and Commitments	12 Months Ended
	Dec. 31, 2018
Commitments and Contingencies Disclosure [Abstract]
Contingent Liabilities and Commitments [Text Block]	Note 18 – Contingent Liabilities and Commitments Reporting of Natural Gas-Related Information to Trade Publications Direct and indirect purchasers of natural gas in various states filed individual and class actions against us, our former affiliate WPX Energy, Inc. (WPX) and its subsidiaries, and others alleging the manipulation of published gas price indices and seeking unspecified amounts of damages. Such actions were transferred to the Nevada federal district court for consolidation of discovery and pre-trial issues. We have agreed to indemnify WPX and its subsidiaries related to this matter. In the individual action, filed by Farmland Industries Inc. (Farmland), the court issued an order on May 24, 2016, granting one of our co-defendant’s motion for summary judgment as to Farmland’s claims. On January 5, 2017, the court extended such ruling to us, entering final judgment in our favor. Farmland appealed. On March 27, 2018, the appellate court reversed the district court’s grant of summary judgment, and on April 10, 2018, the defendants filed a petition for rehearing with the appellate court, which was denied on May 9, 2018. The case has been remanded to the Nevada federal district court. In the putative class actions, on March 30, 2017, the court issued an order denying the plaintiffs’ motions for class certification. On June 13, 2017, the United States Court of Appeals for the Ninth Circuit granted the plaintiffs’ petition for permission to appeal the order. On August 6, 2018, the Ninth Circuit reversed the order denying class certification and remanded the case to the Nevada federal district court. Because of the uncertainty around the remaining pending unresolved issues, we cannot reasonably estimate a range of potential exposure at this time. However, it is reasonably possible that the ultimate resolution of these actions and our related indemnification obligation could result in a potential loss that may be material to our results of operations. In connection with this indemnification, we have an accrued liability balance associated with this matter, and as a result, have exposure to future developments. Alaska Refinery Contamination Litigation We are involved in litigation arising from our ownership and operation of the North Pole Refinery in North Pole, Alaska, from 1980 until 2004, through our wholly owned subsidiaries, Williams Alaska Petroleum Inc. (WAPI) and MAPCO Inc. We sold the refinery to Flint Hills Resources Alaska, LLC (FHRA), a subsidiary of Koch Industries, Inc., in 2004. The litigation involves three cases, with filing dates ranging from 2010 to 2014. The actions 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. Several trial dates encompassing all three cases have been scheduled and stricken; we are awaiting a new trial date. 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 intends 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. That customer has reached a tentative settlement to resolve substantially all Pennsylvania royalty cases pending, which settlement would apply to both the customer and us. The settlement as reported would not require any contribution from us. Litigation Against Energy Transfer and Related Parties On April 6, 2016, we filed suit in Delaware Chancery Court against Energy Transfer Equity, L.P. (Energy Transfer) and LE GP, LLC (the general partner for Energy Transfer) alleging willful and material breaches of the Agreement and Plan of Merger (ETE Merger Agreement) with Energy Transfer resulting from the private offering by Energy Transfer on March 8, 2016, of Series A Convertible Preferred Units (Special Offering) to certain Energy Transfer insiders and other accredited investors. The suit seeks, among other things, an injunction ordering the defendants to unwind the Special Offering and to specifically perform their obligations under the ETE Merger Agreement. On April 19, 2016, we filed an amended complaint seeking the same relief. On May 3, 2016, Energy Transfer and LE GP, LLC filed an answer and counterclaims. On May 13, 2016, we filed a separate complaint in Delaware Chancery Court against Energy Transfer, LE GP, LLC, and the other Energy Transfer affiliates that are parties to the ETE Merger Agreement, alleging material breaches of the ETE Merger Agreement for failing to cooperate and use necessary efforts to obtain a tax opinion required under the ETE Merger Agreement (Tax Opinion) and for otherwise failing to use necessary efforts to consummate the merger under the ETE Merger Agreement wherein we would be merged with and into the newly formed Energy Transfer Corp LP (ETC) (ETC Merger). The suit sought, among other things, a declaratory judgment and injunction preventing Energy Transfer from terminating or otherwise avoiding its obligations under the ETE Merger Agreement due to any failure to obtain the Tax Opinion. The Court of Chancery coordinated the Special Offering and Tax Opinion suits. On May 20, 2016, the Energy Transfer defendants filed amended affirmative defenses and verified counterclaims in the Special Offering and Tax Opinion suits, alleging certain breaches of the ETE Merger Agreement by us and seeking, among other things, a declaration that we were not entitled to specific performance, that Energy Transfer could terminate the ETC Merger, and that Energy Transfer is entitled to a $1.48 billion termination fee. On June 24, 2016, following a two-day trial, the court issued a Memorandum Opinion and Order denying our requested relief in the Tax Opinion suit. The court did not rule on the substance of our claims related to the Special Offering or on the substance of Energy Transfer’s counterclaims. On June 27, 2016, we filed an appeal of the court’s decision with the Supreme Court of Delaware, seeking reversal and remand to pursue damages. On March 23, 2017, the Supreme Court of Delaware affirmed the Court of Chancery’s ruling. On March 30, 2017, we filed a motion for reargument with the Supreme Court of Delaware, which was denied on April 5, 2017. On September 16, 2016, we filed an amended complaint with the Court of Chancery seeking damages for breaches of the ETE Merger Agreement by defendants. On September 23, 2016, Energy Transfer filed a second amended and supplemental affirmative defenses and verified counterclaim with the Court of Chancery seeking, among other things, payment of the $1.48 billion termination fee due to our alleged breaches of the ETE Merger Agreement. On December 1, 2017, the court granted our motion to dismiss certain of Energy Transfer’s counterclaims, including its claim seeking payment of the $1.48 billion termination fee. On December 8, 2017, Energy Transfer filed a motion for reargument, which the Court of Chancery denied on April 16, 2018. Although the Court of Chancery scheduled trial for May 20 through May 24, 2019, the parties anticipate trial will be re-scheduled for a later date. 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, 2018 , we have accrued liabilities totaling $35 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, 2018 , 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. These 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. The EPA previously issued its rule regarding National Ambient Air Quality Standards for ground-level ozone. We are monitoring the rule’s implementation as it will trigger additional federal and state regulatory actions that may impact our operations. Implementation of the regulations is expected to result in impacts to our operations and increase the cost of additions to Property, plant, and equipment – net in the Consolidated Balance Sheet for both new and existing facilities in affected areas. We are unable to reasonably estimate the cost of additions that may be required to meet the regulations at this time due to uncertainty created by various legal challenges to these regulations and the need for further specific regulatory guidance. Continuing operations Our interstate gas pipelines are involved in remediation activities related to certain facilities and locations for polychlorinated biphenyls, mercury, and other hazardous substances. These activities have involved the EPA and various state environmental authorities, resulting in our identification as a potentially responsible party at various Superfund waste sites. At December 31, 2018 , we have accrued liabilities of $6 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, 2018 , we have accrued liabilities totaling $7 million for these costs. Former operations We have potential obligations in connection with assets and businesses we no longer operate. These potential obligations include remediation activities at the direction of federal and state environmental authorities and the indemnification of the purchasers of certain of these assets and businesses for environmental and other liabilities existing at the time the sale was consummated. Our responsibilities relate to the operations of the assets and businesses described below. • Former agricultural fertilizer and chemical operations and former retail petroleum and refining operations; • Former petroleum products and natural gas pipelines; • Former petroleum refining facilities; • Former exploration and production and mining operations; • Former electricity and natural gas marketing and trading operations. At December 31, 2018 , we have accrued environmental liabilities of $22 million related to these matters. Other Divestiture Indemnifications Pursuant to various purchase and sale agreements relating to divested businesses and assets, we have indemnified certain purchasers against liabilities that they may incur with respect to the businesses and assets acquired from us. The indemnities provided to the purchasers are customary in sale transactions and are contingent upon the purchasers incurring liabilities that are not otherwise recoverable from third parties. The indemnities generally relate to breach of warranties, tax, historic litigation, personal injury, property damage, environmental matters, right of way, and other representations that we have provided. At December 31, 2018 , 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 $480 million at December 31, 2018 .

Segment Disclosures

Segment Disclosures	12 Months Ended
	Dec. 31, 2018
Segment Reporting [Abstract]
Segment Disclosures [Text Block]	Note 19 – Segment Disclosures Our reportable segments are Northeast G&P, Atlantic-Gulf, and West. All remaining business activities are included in Other. (See Note 1 – General, Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies .) Performance Measurement We evaluate segment operating performance based upon Modified EBITDA (earnings before interest, taxes, depreciation, and amortization). This measure represents the basis of our internal financial reporting and is the primary performance measure used by our chief operating decision maker in measuring performance and allocating resources among our reportable segments. Intersegment revenues primarily represent the sale of NGLs from our natural gas processing plants to our marketing business. We define Modified EBITDA as follows: • Net income (loss) before: ◦ 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; ◦ 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: United States Canada Total (Millions) Revenues from external customers: 2018 $ 8,686 $ — $ 8,686 2017 8,030 1 8,031 2016 7,425 74 7,499 The following table reflects the reconciliation of Segment revenues to Total revenues as reported in the Consolidated Statement of Operations and Other financial information : Northeast G&P Atlantic-Gulf West Other Eliminations Total (Millions) 2018 Segment revenues: Service revenues External $ 935 $ 2,460 $ 2,085 $ 22 $ — $ 5,502 Internal 41 49 — 12 (102 ) — Total service revenues 976 2,509 2,085 34 (102 ) 5,502 Total service revenues – commodity consideration (external only) 20 59 321 — — 400 Product sales External 245 174 2,365 — — 2,784 Internal 42 261 83 — (386 ) — Total product sales 287 435 2,448 — (386 ) 2,784 Total revenues $ 1,283 $ 3,003 $ 4,854 $ 34 $ (488 ) $ 8,686 Other financial information: Additions to long-lived assets $ 477 $ 2,297 $ 361 $ 36 $ — $ 3,171 Proportional Modified EBITDA of equity-method investments 493 183 94 — — 770 2017 Segment revenues: Service revenues External $ 837 $ 2,202 $ 2,246 $ 27 $ — $ 5,312 Internal 35 37 — 11 (83 ) — Total service revenues 872 2,239 2,246 38 (83 ) 5,312 Product sales External 264 257 1,840 358 — 2,719 Internal 27 227 173 8 (435 ) — Total product sales 291 484 2,013 366 (435 ) 2,719 Total revenues $ 1,163 $ 2,723 $ 4,259 $ 404 $ (518 ) $ 8,031 Other financial information: Additions to long-lived assets $ 460 $ 2,001 $ 321 $ 32 $ — $ 2,814 Proportional Modified EBITDA of equity-method investments 452 264 79 — — 795 2016 Segment revenues: Service revenues External $ 836 $ 1,959 $ 2,328 $ 48 $ — $ 5,171 Internal 34 39 — 11 (84 ) — Total service revenues 870 1,998 2,328 59 (84 ) 5,171 Product sales External 134 245 1,183 766 — 2,328 Internal 28 205 197 22 (452 ) — Total product sales 162 450 1,380 788 (452 ) 2,328 Total revenues $ 1,032 $ 2,448 $ 3,708 $ 847 $ (536 ) $ 7,499 Other financial information: Additions to long-lived assets $ 223 $ 1,608 $ 223 $ 92 $ (1 ) $ 2,145 Proportional Modified EBITDA of equity-method investments 357 287 110 — — 754 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, 2018 2017 2016 (Millions) Modified EBITDA by segment: Northeast G&P $ 1,086 $ 819 $ 853 Atlantic-Gulf 2,023 1,238 1,621 West 308 412 1,544 Other (29 ) 997 (696 ) 3,388 3,466 3,322 Accretion expense associated with asset retirement obligations for nonregulated operations (33 ) (33 ) (31 ) Depreciation and amortization expenses (1,725 ) (1,736 ) (1,763 ) Equity earnings (losses) 396 434 397 Impairment of equity-method investments (32 ) — (430 ) Other investing income (loss) – net 219 282 63 Proportional Modified EBITDA of equity-method investments (770 ) (795 ) (754 ) Interest expense (1,112 ) (1,083 ) (1,179 ) (Provision) benefit for income taxes (138 ) 1,974 25 Net income (loss) $ 193 $ 2,509 $ (350 ) The following table reflects Total assets and Equity-method investments by reportable segments: Total Assets Equity-Method Investments December 31, 2018 December 31, 2017 December 31, 2018 December 31, 2017 (Millions) Northeast G&P $ 14,526 $ 14,397 $ 5,319 $ 5,307 Atlantic-Gulf 16,346 14,989 776 823 West 13,948 16,143 1,726 422 Other (1) 849 1,449 — — Eliminations (2) (367 ) (626 ) — — Total $ 45,302 $ 46,352 $ 7,821 $ 6,552 ______________ (1) Decrease in Other is due primarily to a decreased cash balance. (2) Eliminations primarily relate to the intercompany notes and accounts receivable generated by our cash management program.

Schedule II - Valuation and Qua

Schedule II - Valuation and Qualifying Accounts	12 Months Ended
	Dec. 31, 2018
SEC Schedule, 12-09, 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) 2018 Deferred tax asset valuation allowance (1) $ 224 $ 96 $ — $ — $ 320 2017 Deferred tax asset valuation allowance (1) 334 (110 ) — — 224 2016 Deferred tax asset valuation allowance (1) 190 144 — — 334 __________ (1) Deducted from related assets.

General, Description of Busin_2

General, Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2018	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 variable interest entity (VIE); • Determining whether we are the primary beneficiary of a VIE, including evaluating which activities of the VIE most significantly impact its economic performance and the degree of power that we and our related parties have over those activities through our variable interests; • 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, and other identifiable intangible assets; • Litigation-related contingencies; • Environmental remediation obligations; • Depreciation and/or amortization of long-lived assets; • Depreciation and/or amortization of equity-method investment basis differences; • Asset retirement obligations (AROs); • Pension and postretirement valuation variables; • Measurement of regulatory liabilities; • Measurement of deferred income tax assets and liabilities, including assumptions related to the realization of deferred income tax assets. These estimates are discussed further throughout these notes.
Regulatory accounting [Policy Text Block]	Regulatory accounting Transco and Northwest Pipeline are regulated by the FERC. Their rates, which are established by the FERC, are designed to recover the costs of providing the regulated services, and their competitive environment makes it probable that such rates can be charged and collected. Therefore, we have determined that it is appropriate under Accounting Standards Codification (ASC) Topic 980, “Regulated Operations,” (ASC 980) to account for and report regulatory assets and liabilities related to these operations consistent with the economic effect of the way in which their rates are established. Accounting for these operations that are regulated can differ from the accounting requirements for nonregulated operations. For example, for regulated operations, allowance for funds used during construction (AFUDC) represents the estimated cost of debt and equity funds applicable to utility plant in the process of construction and is capitalized as a cost of property, plant, and equipment because it constitutes an actual cost of construction under established regulatory practices; nonregulated operations are only allowed to capitalize the cost of debt funds related to construction activities, while a component for equity is prohibited. The components of our regulatory assets and liabilities relate to the effects of deferred taxes on equity funds used during construction, asset retirement obligations, fuel cost differentials, levelized incremental depreciation, negative salvage, pension and other postretirement benefits, and rate allowances for deferred income taxes at a historically higher federal income tax rate. In December 2017, Tax Reform was enacted, which, among other things, reduced the federal corporate income tax rate from 35 percent to 21 percent (see Note 8 – Provision (Benefit) for Income Taxes ). In accordance with ASC 980-740-25-2, Transco and Northwest Pipeline have recognized regulatory liabilities to reflect the probable return to customers through future rates of the future decrease in income taxes payable associated with Tax Reform. These liabilities represent an obligation to return amounts directly to our customers. While a majority of our customers have entered into tariff rates based on our cost-of-service proceedings and related rate base therein, certain other contracts with customers reflect contractually-based rates that are designed to recover the cost of providing those services, including an allowance for income taxes, with no expected future rate adjustment for the term of those contracts. This relative mix of contracts for services was considered in determining the probable amount to be returned to customers through future rates. The regulatory liabilities were recorded in December 2017 through regulatory charges to operating income totaling $674 million . As of December 31, 2018, the balance of these regulatory liabilities totaled $657 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 for 2017 were reduced by $11 million related to our proportionate share of the associated regulatory charges. Our regulatory assets associated with the effects of deferred taxes on equity funds used during construction were also impacted by Tax Reform and were reduced by $102 million in December 2017 through a charge to Other income (expense) – net below Operating income (loss) in the Consolidated Statement of Operations (see Note 7 – Other Income and Expenses ). This amount, along with the previously described charges for establishing the regulatory liabilities resulting from Tax Reform, is reported within Regulatory charges resulting from Tax Reform within the Consolidated Statement of Cash Flows . Our current and noncurrent regulatory asset and liability balances for the years ended December 31, 2018 and 2017 are as follows: December 31, 2018 2017 (Millions) Current assets reported within Other current assets and deferred charges $ 103 $ 102 Noncurrent assets reported within Regulatory assets, deferred charges, and other 495 376 Total regulated assets $ 598 $ 478 Current liabilities reported within Accrued liabilities $ 5 $ 18 Noncurrent liabilities reported within Regulatory liabilities, deferred income, and other 1,321 1,250 Total regulated liabilities $ 1,326 $ 1,268
Cash and cash equivalents [Policy Text Block]	Cash and cash equivalents Cash and cash equivalents consist of highly liquid investments with original maturities 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 do not offer extended payment terms and typically receive payment within one month. We consider receivables past due if full payment is not received by the contractual due date. Interest income related to past due accounts receivable is generally recognized at the time full payment is received or collectability is assured. Past due accounts are generally written off against the allowance for doubtful accounts only after all collection attempts have been exhausted.
Inventories [Policy Text Block]	Inventories Inventories in the Consolidated Balance Sheet primarily consist of NGLs, natural gas in underground storage, and materials and supplies and are stated at the lower of cost or net realizable value. The cost of inventories is primarily determined using the average-cost method.
Property, plant, and equipment [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 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.
Other intangible 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.
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 14 – 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 17 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk .) The accounting for the changes in fair value of a commodity derivative can be summarized as follows: Derivative Treatment Accounting Method Normal purchases and normal sales exception Accrual accounting Designated in a qualifying hedging relationship Hedge accounting All other derivatives Mark-to-market accounting We may elect the normal purchases and normal sales exception for certain short- and long-term purchases and sales of physical energy commodities. Under accrual accounting, any change in the fair value of these derivatives is not reflected on the balance sheet after the initial election of the exception. We may also designate a hedging relationship for certain commodity derivatives. For a derivative to qualify for designation in a hedging relationship, it must meet specific criteria and we must maintain appropriate documentation. We establish hedging relationships pursuant to our risk management policies. We evaluate the hedging relationships at the inception of the hedge and on an ongoing basis to determine whether the hedging relationship is, and is expected to remain, highly effective in achieving offsetting changes in fair value or cash flows attributable to the underlying risk being hedged. We also regularly assess whether the hedged forecasted transaction is probable of occurring. If a derivative ceases to be or is no longer expected to be highly effective, or if we believe the likelihood of occurrence of the hedged forecasted transaction is no longer probable, hedge accounting is discontinued prospectively, and future changes in the fair value of the derivative are recognized currently in Product sales or Product costs in the Consolidated Statement of Operations . For commodity derivatives designated as a cash flow hedge, the change in fair value of the derivative is reported in AOCI in the Consolidated Balance Sheet and reclassified into earnings in the period in which the hedged item affects earnings. Gains or losses deferred in AOCI associated with terminated derivatives, derivatives that cease to be highly effective hedges, derivatives for which the forecasted transaction is reasonably possible but no longer probable of occurring, and cash flow hedges that have been otherwise discontinued remain in AOCI until the hedged item affects earnings. If it becomes probable that the forecasted transaction designated as the hedged item in a cash flow hedge will not occur, any gain or loss deferred in AOCI is recognized in Product sales or Product costs in the Consolidated Statement of Operations at that time. The change in likelihood of a forecasted transaction is a judgmental decision that includes qualitative assessments made by us. For commodity derivatives that are not designated in a hedging relationship, and for which we have not elected the normal purchases and normal sales exception, we report changes in fair value currently in Product sales or Product costs in the Consolidated Statement of Operations . Certain gains and losses on derivative instruments included in the Consolidated Statement of Operations are netted together to a single net gain or loss, while other gains and losses are reported on a gross basis. Gains and losses recorded on a net basis include unrealized gains and losses on all derivatives that are not designated as hedges and for which we have not elected the normal purchases and normal sales exception. Realized gains and losses on derivatives that require physical delivery, as well as natural gas derivatives for NGL processing activities and which are not held for trading purposes nor were entered into as a pre-contemplated buy/sell arrangement, are recorded on a gross basis.
Revenue recognition [Policy Text Block]	Revenue recognition (subsequent to the adoption of ASC 606) Customers in our gas pipeline businesses are comprised of public utilities, municipalities, gas marketers and producers, intrastate pipelines, direct industrial users, and electrical generators. Customers in our midstream businesses are comprised of oil and natural gas producer counterparties. Customers for our product sales are comprised of public utilities, gas marketers, and direct industrial users. A performance obligation is a promise in a contract to transfer a distinct good or service (or integrated package of goods or services) to the customer. A contract’s transaction price is allocated to each distinct performance obligation and recognized as revenue, when, or as, the performance obligation is satisfied. A performance obligation is distinct if the service is separately identifiable from other items in the integrated package of services and if a customer can benefit from it on its own or with other resources that are readily available to the customer. An integrated package of services typically represents a single performance obligation if the services are contained within the same contract or within multiple contracts entered into in contemplation with one another that are highly interdependent or highly interrelated, meaning each of the services is significantly affected by one or more of the other services in the contract. Service revenue contracts from our gas pipeline and midstream businesses contain a series of distinct services, with the majority of our contracts having a single performance obligation that is satisfied over time as the customer simultaneously receives and consumes the benefits provided by our performance. Most of our product sales contracts have a single performance obligation with revenue recognized at a point in time when the products have been sold and delivered to the customer. Certain customers reimburse us for costs we incur associated with construction of property, plant, and equipment utilized in our operations. For our rate-regulated gas pipeline businesses that apply ASC 980, we follow FERC guidelines with respect to reimbursement of construction costs. FERC tariffs only allow for cost reimbursement and are non-negotiable in nature; thus, the construction activities do not represent an ongoing major and central operation of our gas pipeline businesses and are not within the scope of ASC Topic 606, “Revenue from Contracts with Customers” (ASC 606). Accordingly, cost reimbursements are treated as a reduction to the cost of the constructed asset. For our midstream businesses, reimbursement and service contracts with customers are viewed together as providing the same commercial objective, as we have the ability to negotiate the mix of consideration between reimbursements and amounts billed over time. Accordingly, we generally recognize reimbursements of construction costs from customers on a gross basis as a contract liability separate from the associated costs included within property, plant, and equipment. The contract liability is recognized into service revenues as the underlying performance obligations are satisfied. Service Revenues Gas pipeline businesses: Revenues from our regulated interstate natural gas pipeline businesses, which are subject to regulation by certain state and federal authorities, including the FERC, include both firm and interruptible transportation and storage contracts. Firm transportation and storage agreements provide for a fixed reservation charge based on the pipeline or storage capacity reserved, and a commodity charge based on the volume of natural gas delivered/stored, each at rates specified in our FERC tariffs or based on negotiated contractual rates, with contract terms that are generally long-term in nature. Most of our long-term contracts contain an evergreen provision, which allows the contracts to be extended for periods primarily up to one year in length an indefinite number of times following the specified contract term and until terminated generally by either us or the customer. Interruptible transportation and storage agreements provide for a volumetric charge based on actual commodity transportation or storage utilized in the period in which those services are provided, and the contracts are generally limited to one-month periods or less. Our performance obligations related to our interstate natural gas pipeline businesses include the following: • Firm transportation or storage under firm transportation and storage contracts—an integrated package of services typically constituting a single performance obligation, which includes standing ready to provide such services and receiving, transporting or storing (as applicable), and redelivering commodities; • Interruptible transportation and storage under interruptible transportation and storage contracts—an integrated package of services typically constituting a single performance obligation once scheduled, which includes receiving, transporting or storing (as applicable), and redelivering commodities. In situations where, in our judgment, we consider the integrated package of services as a single performance obligation, which represents a majority of our interstate natural gas pipeline contracts with customers, we do not consider there to be multiple performance obligations because the nature of the overall promise in the contract is to stand ready (with regard to firm transportation and storage contracts), receive, transport or store, and redeliver natural gas to the customer; therefore, revenue is recognized over time upon satisfaction of our daily stand ready performance obligation. We recognize revenues for reservation charges over the performance obligation period, which is the contract term, regardless of the volume of natural gas that is transported or stored. Revenues for commodity charges from both firm and interruptible transportation services and storage services are recognized when natural gas is delivered at the agreed upon delivery point or when natural gas is injected or withdrawn from the storage facility because they specifically relate to our efforts to provide these distinct services. Generally, reservation charges and commodity charges in our interstate natural gas pipeline businesses are recognized as revenue in the same period they are invoiced to our customers. As a result of the ratemaking process, certain amounts collected by us may be subject to refund upon the issuance of final orders by the FERC in pending rate proceedings. We use judgment to record estimates of rate refund liabilities considering our and other third-party regulatory proceedings, advice of counsel, and other risks. Midstream businesses: Revenues from our non-regulated gathering, processing, transportation, and storage midstream businesses include contracts for natural gas gathering, processing, treating, compression, transportation, and other related services with contract terms that are generally long-term in nature and may extend up to the production life of the associated reservoir. Additionally, our midstream businesses generate revenues from fees charged for storing customers’ natural gas and NGLs, generally under prepaid contracted storage capacity contracts. In situations where, in our judgment, we provide an integrated package of services combined into a single performance obligation, which represents a majority of this class of contracts with customers, we do not consider there to be multiple performance obligations because the nature of the overall promise in the contract is to provide gathering, processing, transportation, storage, and related services resulting in the delivery, or redelivery in the context of storage services, of pipeline-quality natural gas and NGLs to the customer. As such, revenue is recognized at the daily completion of the integrated package of services as the integrated package represents a single performance obligation. Additionally, certain contracts in our midstream businesses contain fixed or upfront payment terms that result in the deferral of revenues until such services have been performed or such capacity has been made available. We also earn revenues from offshore crude oil and natural gas gathering and transportation and offshore production handling. These services represent an integrated package of services and are considered a single distinct performance obligation for which we recognize revenues as the services are provided to the customer. We generally earn a contractually stated fee per unit for the volume of product transported, gathered, processed, or stored. The rate is generally fixed; however, certain contracts contain variable rates that are subject to change based on commodity prices, levels of throughput, or an annual adjustment based on a formulaic cost of service calculation. In addition, we have contracts with contractually stated fees that decline over the contract term, such as declines based on the passage of time periods or achievement of cumulative throughput amounts. For all of our contracts, we allocate the transaction price to each performance obligation based on the judgmentally determined relative standalone selling price. The excess of consideration received over revenue recognized results in the deferral of those amounts until future periods based on a units of production or straight-line methodology as these methods appropriately match the consumption of services provided to the customer. The units of production methodology requires the use of production estimates that are uncertain and the use of judgment when developing estimates of future production volumes, thus impacting the rate of revenue recognition. Production estimates are monitored as circumstances and events warrant. Certain of our gas gathering and processing agreements have minimum volume commitments (MVC). If a customer under such an agreement fails to meet its MVC for a specified period (thus not exercising all the contractual rights to gathering and processing services within the specified period, herein referred to as “breakage”), it is obligated to pay a contractually determined fee based upon the shortfall between the actual gathered or processed volumes and the MVC for the period contained in the contract. When we conclude, based on management’s judgment, it is probable that the customer will not exercise all or a portion of its remaining rights, we recognize revenue associated with such breakage amount in proportion to the pattern of exercised rights within the respective MVC period. Under keep-whole and percent-of-liquids processing contracts, we receive commodity consideration in the form of NGLs and take title to the NGLs at the tailgate of the plant. We recognize such commodity consideration as service revenue based on the market value of the NGLs retained at the time the processing is provided. The current market value, as opposed to the market value at the contract inception date, is used due to a combination of factors, including the fact that the volume, mix, and market price of NGL consideration to be received is unknown at the time of contract execution and is not specified in our contracts with customers. Additionally, product sales revenue (discussed below) is recognized upon the sale of the NGLs to a third party based on the sales price at the time of sale. As a result, revenue is recognized both at the time the processing service is provided in Service revenues – commodity consideration and at the time the NGLs retained as part of the processing service are sold in Product sales . The recognition of revenue related to commodity consideration has the impact of increasing the book value of NGL inventory, resulting in higher cost of goods sold at the time of sale. Given that most inventory is sold in the same period that it is generated, the impact of these transactions is expected to have little impact to operating income. Product Sales In the course of providing transportation services to customers of our gas pipeline businesses and gathering and processing services to customers of our midstream businesses, we may receive different quantities of natural gas from customers than the quantities delivered on behalf of those customers. The resulting imbalances are primarily settled through the purchase or sale of natural gas with each customer under terms provided for in our FERC tariffs or gathering and processing agreements, respectively. Revenue is recognized from the sale of natural gas upon settlement of imbalances. In certain instances, we purchase NGLs, crude oil, and natural gas from our oil and natural gas producer customers. In addition, we retain NGLs as consideration in certain processing arrangements, as discussed above in the Service Revenues - Midstream businesses section. We recognize revenue from the sale of these commodities when the products have been sold and delivered. Our product sales contracts are primarily short-term contracts based on prevailing market rates at the time of the transaction. Contract Assets Our contract assets primarily consist of revenue recognized under contracts containing MVC features whereby management has concluded it is probable there will be a short-fall payment at the end of the current MVC period, which typically follows the calendar year, and that a significant reversal of revenue recognized currently for the future MVC payment will not occur. As a result, our contract assets related to our future MVC payments are generally expected to be collected within the next 12 months and are included within Other current assets and deferred charges in our Consolidated Balance Sheet until such time as the MVC short-fall payments are invoiced to the customer. Contract Liabilities Our contract liabilities consist of advance payments primarily from midstream business customers which include construction reimbursements, prepayments, and other billings for which future services are to be provided under the contract. These amounts are deferred until recognized in revenue when the associated performance obligation has been satisfied, which is primarily based on a units of production methodology over the remaining contractual service periods, and are classified as current or noncurrent according to when such amounts are expected to be recognized. Current and noncurrent contract liabilities are included within Accrued liabilities and Regulatory liabilities, deferred income, and other , respectively, in our Consolidated Balance Sheet . Contracts requiring advance payments and the recognition of contract liabilities are evaluated to determine whether the advance payments provide us with a significant financing benefit. This determination is based on the combined effect of the expected length of time between when we transfer the promised good or service to the customer, when the customer pays for those goods or services, and the prevailing interest rates. We have assessed our contracts for significant financing components and determined, in our judgment, that one group of contracts entered into in contemplation of one another for certain capital reimbursements contains a significant financing component. As a result, we recognize noncash interest expense based on the effective interest method and revenue (noncash) is recognized when the underlying asset is placed into service utilizing a units of production or straight-line methodology over the life of the corresponding customer contract.	Revenue recognition (prior to the adoption of ASC 606) Revenues As a result of the ratemaking process, certain revenues collected by us may be subject to refunds upon the issuance of final orders by the FERC in pending rate proceedings. We record estimates of rate refund liabilities considering our and other third-party regulatory proceedings, advice of counsel, and other risks. Service revenues Revenues from our interstate natural gas pipeline businesses include services pursuant to long-term firm transportation and storage agreements. These agreements provide for a reservation charge based on the volume of contracted capacity and a commodity charge based on the volume of gas delivered, both at rates specified in our FERC tariffs. We recognize revenues for reservation charges ratably over the contract period regardless of the volume of natural gas that is transported or stored. Revenues for commodity charges, from both firm and interruptible transportation services and storage injection and withdrawal services, are recognized when natural gas is delivered at the agreed upon delivery point or when natural gas is injected or withdrawn from the storage facility. 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 16 – 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 10 – Employee Benefit Plans .) The discount rates are determined separately for each of our pension and other postretirement benefit plans based on an approach specific to our plans. The year-end discount rates are determined considering a yield curve comprised of high-quality corporate bonds and the timing of the expected benefit cash flows of each plan. The expected long-term rates of return on plan assets are determined by combining a review of the historical returns within the portfolio, the investment strategy included in the plans’ investment policy statement, and capital market projections for the asset classes in which the portfolio is invested, as well as the weighting of each asset class. Unrecognized actuarial gains and losses and unrecognized prior service costs and credits are deferred and recorded in AOCI or, for Transco and Northwest Pipeline, as a regulatory asset or liability, until amortized as a component of net periodic benefit cost (credit). Unrecognized actuarial gains and losses in excess of 10 percent of the greater of the benefit obligation or the market-related value of plan assets are amortized over the participants’ average remaining future years of service, which is approximately 13 years for our pension plans and approximately 7 years for our other postretirement benefit 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.
New Accounting Pronouncements and Changes in Accounting Principles [Text Block]	Accounting standards issued and adopted During the first quarter of 2018, we early adopted Accounting Standards Update (ASU) 2018-02 “Income Statement - Reporting Comprehensive Income (Topic 220): Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income” (ASU 2018-02). As a result of Tax Reform lowering the federal income tax rate and prior to adopting this standard, the tax effects of items within accumulated other comprehensive income may not have reflected the appropriate tax rate. ASU 2018-02 allows for the reclassification from accumulated other comprehensive income to retained earnings for stranded tax effects resulting from Tax Reform. The adoption of ASU 2018-02 resulted in the reclassification of $61 million from Accumulated other comprehensive income (loss) to Retained deficit on our Consolidated Balance Sheet . Effective January 1, 2018, we adopted ASU 2017-12 “Derivatives and Hedging (Topic 815): Targeted Improvements to Accounting for Hedging Activities” (ASU 2017-12). ASU 2017-12 applies to entities that elect hedge accounting in accordance with ASC 815. The ASU affects both the designation and measurement guidance for hedging relationships and the presentation of hedging results. ASU 2017-12 was applied using a modified retrospective approach for cash flow and net investment hedges existing at the date of adoption and prospectively for the presentation and disclosure guidance. The adoption of ASU 2017-12 did not have a significant impact on our consolidated financial statements. In May 2014, the Financial Accounting Standards Board (FASB) issued ASU 2014-09 establishing ASC 606. ASC 606 establishes a comprehensive new revenue recognition model designed to depict the transfer of goods or services to a customer in an amount that reflects the consideration the entity expects to be entitled to receive in exchange for those goods or services and requires significantly enhanced revenue disclosures. In August 2015, the FASB issued ASU 2015-14 “Revenue from Contracts with Customers (Topic 606): Deferral of the Effective Date” (ASU 2015-14). Per ASU 2015-14, the standard became effective for interim and annual reporting periods beginning after December 15, 2017. We adopted the provisions of ASC 606 effective January 1, 2018, utilizing the modified retrospective transition method for all contracts with customers, which included applying the provisions of ASC 606 beginning January 1, 2018, to all contracts not completed as of that date with the cumulative effect of applying the standard for periods prior to January 1, 2018, as an adjustment to Total equity , net of tax, upon adoption. As a result of our adoption, the cumulative impact to our Total equity , net of tax, at January 1, 2018, was a decrease of $121 million in the Consolidated Balance Sheet . For each revenue contract type, we conducted a formal contract review process to evaluate the impact of ASC 606. The adjustment to Total equity upon adoption of ASC 606 is primarily comprised of the impact to the timing of recognition of deferred revenue (contract liabilities) associated with certain contracts which underwent modifications in periods prior to January 1, 2018. Under the provisions of ASC 606, when a contract modification does not increase both the scope and price of the contract, and the remaining goods and services are distinct from the goods and services transferred prior to the modification, the modification is treated as a termination of the existing contract and the creation of a new contract. ASC 606 requires that the transaction price, including any remaining contract liabilities from the old contract, be allocated to the performance obligations over the term of the new contract. The contract modification adjustments are partially offset by the impact of changes to the timing of recognizing revenue which is subject to the constraint on estimates of variable consideration of certain contracts. The constraint of variable consideration will result in the acceleration of revenue recognition and corresponding de-recognition of contract liabilities for certain contracts (as compared to the previous revenue recognition model) as a result of our assessment that it is probable such recognition would not result in a significant revenue reversal in the future. Additionally, under ASC 606, our revenues will increase in situations where we receive noncash consideration, which exists primarily in certain of our gas processing contracts where we receive commodities as full or partial consideration for services provided. This increase in revenues will be offset by a similar increase in costs and expenses when the commodities received are subsequently sold. Financial systems and internal controls necessary for adoption were implemented effective January 1, 2018. (See Note 2 – Revenue Recognition .) Accounting standards issued but not yet adopted In June 2016, the FASB issued ASU 2016-13 “Financial Instruments - Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments” (ASU 2016-13). ASU 2016-13 changes the impairment model for most financial assets and certain other instruments. For trade and other receivables, held-to-maturity debt securities, loans, and other instruments, entities will be required to use a new forward-looking “expected loss” model that generally will result in the earlier recognition of allowances for losses. The guidance also requires increased disclosures. ASU 2016-13 is effective for interim and annual periods beginning after December 15, 2019. Early adoption is permitted. The standard requires varying transition methods for the different categories of amendments. Although we do not expect ASU 2016-13 to have a significant impact, it could impact our trade receivables as the related allowance for credit losses will be recognized earlier under the expected loss model. In February 2016, the FASB issued ASU 2016-02 “Leases (Topic 842)” (ASU 2016-02). ASU 2016-02 establishes a comprehensive new lease accounting model. ASU 2016-02 modifies the definition of a lease, requires a dual approach to lease classification similar to current lease accounting, and causes lessees to recognize operating leases on the balance sheet as a lease liability measured as the present value of the future lease payments with a corresponding right-of-use asset, with an exception for leases with a term of one year or less. Additional disclosures will also be required regarding the amount, timing, and uncertainty of cash flows arising from leases. In January 2018, the FASB issued ASU 2018-01 “Leases (Topic 842): Land Easement Practical Expedient for Transition to Topic 842” (ASU 2018-01). Per ASU 2018-01, land easements and rights-of-way are required to be assessed under ASU 2016-02 to determine whether the arrangements are or contain a lease. ASU 2018-01 permits an entity to elect a transition practical expedient to not apply ASU 2016-02 to land easements that exist or expired before the effective date of ASU 2016-02 and that were not previously assessed under the previous lease guidance in ASC Topic 840 “Leases.” In July 2018, the FASB issued ASU 2018-11 “Leases (Topic 842): Targeted Improvements” (ASU 2018-11). Prior to ASU 2018-11, a modified retrospective transition was required for financing or operating leases existing at or entered into after the beginning of the earliest comparative period presented in the financial statements. ASU 2018-11 allows entities an additional transition method to the existing requirements whereby an entity could adopt the provisions of ASU 2016-02 by recognizing a cumulative-effect adjustment to the opening balance of retained earnings in the period of adoption without adjustment to the financial statements for periods prior to adoption. ASU 2018-11 also allows a practical expedient that permits lessors to not separate non-lease components from the associated lease component if certain conditions are present. ASU 2016-02 is effective for interim and annual periods beginning after December 15, 2018. Early adoption is permitted. We are adopting ASU 2016-02 effective January 1, 2019. We are substantially complete with our review of contracts to identify leases based on the modified definition of a lease and implementing changes to our internal controls to support management in the accounting for and disclosure of leasing activities upon adoption of ASU 2016-02. We implemented a financial lease accounting system to assist management in the accounting for leases upon adoption. We are substantially complete with the implementation of ASU 2016-02 and believe the most significant changes to our financial statements relate to the recognition of a lease liability and offsetting right-of-use asset in our Consolidated Balance Sheet for operating leases, which we estimate to be less than 1 percent of total liabilities and total assets, respectively. We have also evaluated ASU 2016-02’s available practical expedients on adoption. We generally elected to adopt the practical expedients, which includes the practical expedient to not separate lease and non-lease components by both lessees and lessors by class of underlying assets and the land easements practical expedient.

General, Description of Busin_3

General, Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies (Tables)	12 Months Ended
	Dec. 31, 2018
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, 2018 and 2017 are as follows: December 31, 2018 2017 (Millions) Current assets reported within Other current assets and deferred charges $ 103 $ 102 Noncurrent assets reported within Regulatory assets, deferred charges, and other 495 376 Total regulated assets $ 598 $ 478 Current liabilities reported within Accrued liabilities $ 5 $ 18 Noncurrent liabilities reported within Regulatory liabilities, deferred income, and other 1,321 1,250 Total regulated liabilities $ 1,326 $ 1,268

Revenue Recognition (Tables)

Revenue Recognition (Tables)	12 Months Ended
	Dec. 31, 2018
Revenue Recognition [Abstract]
Disaggregation of Revenue [Table Text Block]	The following table presents our revenue disaggregated by major service line: Northeast Midstream Atlantic- Gulf Midstream West Midstream Transco Northwest Pipeline Other Intercompany Eliminations Total (Millions) Year Ended December 31, 2018 Revenues from contracts with customers: Service revenues: Non-regulated gathering, processing, transportation, and storage: Monetary consideration $ 861 $ 541 $ 1,590 $ — $ — $ 2 $ (73 ) $ 2,921 Commodity consideration 20 59 321 — — — — 400 Regulated interstate natural gas transportation and storage — — — 1,921 443 — (2 ) 2,362 Other 94 17 46 2 — — (15 ) 144 Total service revenues 975 617 1,957 1,923 443 2 (90 ) 5,827 Product Sales: NGL and natural gas 287 307 2,421 127 — — (382 ) 2,760 Other — — 21 — — — (4 ) 17 Total product sales 287 307 2,442 127 — — (386 ) 2,777 Total revenues from contracts with customers 1,262 924 4,399 2,050 443 2 (476 ) 8,604 Other revenues (1) 21 18 12 11 — 32 (12 ) 82 Total revenues $ 1,283 $ 942 $ 4,411 $ 2,061 $ 443 $ 34 $ (488 ) $ 8,686 ______________________________ (1) Service revenues in our Consolidated Statement of Operations include leasing revenues associated with our headquarters building and management fees that we receive for certain services we provide to operated joint ventures and other investments. The leasing revenues and the management fees do not constitute revenue from contracts with customers. Product sales in our Consolidated Statement of Operations include amounts associated with our derivative contracts that are not within the scope of ASC 606.
Contract with Customer, Asset and Liability [Table Text Block]	The following table presents a reconciliation of our contract assets: Year Ended December 31, 2018 (Millions) Balance at beginning of period $ 4 Revenue recognized in excess of amounts invoiced 66 Minimum volume commitments invoiced (66 ) Balance at end of period $ 4
Contract with Customer, Liability [Table Text Block]	The following table presents a reconciliation of our contract liabilities: Year Ended December 31, 2018 (Millions) Balance at beginning of period $ 1,596 Payments received and deferred 314 Noncash interest expense for significant financing component 16 Deconsolidation of Jackalope interest (Note 4) (52 ) Deconsolidation of certain Permian assets (Note 6) (26 ) Recognized in revenue (451 ) Balance at end of period $ 1,397
Contract with Customer, Liablity Expected Timing of Revenue Recognition [Table Text Block]	The following table presents the amount of the contract liabilities balance as of December 31, 2018 , expected to be recognized as revenue in each of the next five years as performance obligations are expected to be satisfied: (Millions) 2019 $ 271 2020 142 2021 121 2022 102 2023 95 Thereafter 666 Total $ 1,397
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Table Text Block]	The following table presents the transaction price allocated to the remaining performance obligations under certain contracts as of December 31, 2018 . These primarily include long-term contracts containing MVCs associated with our midstream businesses, fixed payments associated with offshore production handling, and reservation charges on contracted capacity on our gas pipeline firm transportation contracts with customers, as well as storage capacity contracts. Amounts included in the table below for our interstate natural gas pipeline businesses reflect the rates for such services in our current FERC tariffs for the life of the related contracts; however, these rates may change based on future tariffs approved by the FERC and the amount and timing of these changes is not currently known. As a practical expedient permitted by ASC 606, this table excludes variable consideration as well as consideration in contracts that is recognized in revenue as billed. It also excludes consideration received prior to December 31, 2018 , that will be recognized in future periods (see above for Contract Liabilities and the expected recognition of those amounts within revenue). Certain of our contracts contain evergreen and other renewal provisions for periods beyond the initial term of the contract. The remaining performance obligation amounts as of December 31, 2018 , do not consider potential future performance obligations for which the renewal has not been exercised. The table below also does not include contracts with customers for which the underlying facilities have not received FERC authorization to be placed into service. (Millions) 2019 $ 2,909 2020 2,728 2021 2,622 2022 2,262 2023 2,089 Thereafter 16,916 Total $ 29,526
Contract With Customer Accounts Receivable [Table Text Block]	The following is a summary of our Trade accounts and other receivables : December 31, 2018 January 1, 2018 (Millions) Accounts receivable related to revenues from contracts with customers $ 858 $ 958 Other accounts receivable 134 18 Total reflected in Trade accounts and other receivables $ 992 $ 976
Revenue Recognition Modified Retrospective Adoption Impact [Table Text Block]	The following table depicts the impact of the adoption of ASC 606 on our 2018 financial statements. The adjustment to Intangible assets – net of accumulated amortization in the table below relates to the recognition under ASC 606 of contract assets for MVC-related contracts associated with a 2014 acquisition. The recognition of these contract assets resulted in a lower purchase price allocation to intangible assets. The adoption of ASC 606 did not result in adjustments to total operating, investing, or financing cash flows. As Reported Adjustments resulting from adoption of ASC 606 Balance without adoption of ASC 606 (Millions, except per-share amounts) Consolidated Statement of Operations Year Ended December 31, 2018 Service revenues $ 5,502 $ 89 $ 5,591 Service revenues – commodity consideration 400 (400 ) — Product sales 2,784 135 2,919 Total revenues 8,686 (176 ) 8,510 Product costs 2,707 (124 ) 2,583 Processing commodity expenses 137 (137 ) — Operating and maintenance expenses 1,507 1 1,508 Depreciation and amortization expenses 1,725 2 1,727 Impairment of certain assets 1,915 202 2,117 Total costs and expenses 7,918 (56 ) 7,862 Operating income (loss) 768 (120 ) 648 Equity earnings (losses) 396 1 397 Other investing income (loss) – net 219 84 303 Interest incurred (1,160 ) 16 (1,144 ) As Reported Adjustments resulting from adoption of ASC 606 Balance without adoption of ASC 606 (Millions, except per-share amounts) Interest capitalized 48 (10 ) 38 Income (loss) before income taxes 331 (29 ) 302 Provision (benefit) for income taxes 138 (9 ) 129 Net income (loss) 193 (20 ) 173 Less: Net income (loss) attributable to noncontrolling interests 348 (1 ) 347 Net income (loss) attributable to The Williams Companies, Inc. (155 ) (19 ) (174 ) Basic earnings (loss) per common share $ (0.16 ) $ (0.02 ) $ (0.18 ) Diluted earnings (loss) per common share (0.16 ) (0.02 ) (0.18 ) Consolidated Statement of Comprehensive Income (Loss) Year Ended December 31, 2018 Net income (loss) $ 193 $ (20 ) $ 173 Comprehensive income (loss) 223 (20 ) 203 Less: Comprehensive income (loss) attributable to noncontrolling interests 346 (1 ) 345 Comprehensive income (loss) attributable to The Williams Companies, Inc. (123 ) (19 ) (142 ) Consolidated Balance Sheet December 31, 2018 Inventories $ 130 $ (13 ) $ 117 Total current assets 1,464 (13 ) 1,451 Investments 7,821 1 7,822 Property, plant, and equipment – net 27,504 (212 ) 27,292 Intangible assets – net of accumulated amortization 7,767 61 7,828 Regulatory assets, deferred charges, and other 746 (4 ) 742 Total assets 45,302 (167 ) 45,135 Accrued liabilities 1,102 67 1,169 Total current liabilities 1,811 67 1,878 Deferred income tax liabilities 1,524 20 1,544 Regulatory liabilities, deferred income, and other 3,603 (346 ) 3,257 Retained deficit (10,002 ) 64 (9,938 ) Total stockholders’ equity 14,660 64 14,724 Noncontrolling interests in consolidated subsidiaries 1,337 28 1,365 Total equity 15,997 92 16,089 Total liabilities and equity 45,302 (167 ) 45,135 Consolidated Statement of Changes in Equity December 31, 2018 Adoption of ASC 606 $ (121 ) $ 121 $ — Net income (loss) 193 (20 ) 173 Deconsolidation of subsidiary (267 ) (9 ) (276 ) Net increase (decrease) in equity (178 ) 92 (86 ) Balance at December 31, 2018 15,997 92 16,089

Divestitures (Tables)

Divestitures (Tables)	12 Months Ended
	Dec. 31, 2018
Four Corners [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 Four Corners area, excluding the gain noted above: Years Ended December 31, 2018 2017 2016 (Millions) Income (loss) before income taxes of Four Corners area $ 52 $ 47 $ 37 Income (loss) before income taxes of Four Corners area attributable to The Williams Companies, Inc. 43 35 23
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, 2018 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

Variable Interest Entities (Tab

Variable Interest Entities (Tables)	12 Months Ended
	Dec. 31, 2018
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 our consolidated VIEs: December 31, 2018 2017 (1) Classification (Millions) Assets (liabilities): Cash and cash equivalents $ 33 $ 881 Cash and cash equivalents Trade accounts and other receivables – net 62 972 Trade accounts and other receivables Inventories — 113 Inventories Other current assets 2 176 Other current assets and deferred charges Investments — 6,552 Investments Property, plant, and equipment – net 2,363 27,912 Property, plant, and equipment – net Intangible assets – net 1,177 8,790 Intangible assets – net of accumulated amortization Regulatory assets, deferred charges, and other noncurrent assets — 507 Regulatory assets, deferred charges, and other Accounts payable (15 ) (957 ) Accounts payable Accrued liabilities including current asset retirement obligations (115 ) (857 ) Accrued liabilities Long-term debt due within one year — (501 ) Long-term debt due within one year Long-term debt — (15,996 ) Long-term debt Deferred income tax liabilities — (16 ) Deferred income tax liabilities Noncurrent asset retirement obligations (105 ) (944 ) Regulatory liabilities, deferred income, and other Long-term deferred income (159 ) (1,119 ) Regulatory liabilities, deferred income, and other Regulatory liabilities and other — (1,690 ) Regulatory liabilities, deferred income, and other _________________ (1) Includes WPZ, which was a consolidated VIE at December 31, 2017 (see Note 1 – General, Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies ).

Investing Activities (Tables)

Investing Activities (Tables)	12 Months Ended
	Dec. 31, 2018
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 17 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk ): Years Ended December 31, 2018 2017 2016 (Millions) Northeast G&P UEOM $ 32 $ — $ — Appalachia Midstream Investments — — 294 Laurel Mountain — — 50 West DBJV — — 59 Ranch Westex — — 24 Other — — 3 $ 32 $ — $ 430
Investments [Table Text Block]	Investments Ownership Interest at December 31, 2018 December 31, 2018 2017 (Millions) Equity-method investments: Appalachia Midstream Investments (1) $ 3,218 $ 3,104 UEOM 62% 1,293 1,383 RMM 50% 776 — Discovery 60% 507 534 OPPL 50% 415 422 Caiman II 58% 412 429 Jackalope 50% 343 — Laurel Mountain 69% 314 309 Gulfstream 50% 225 244 Brazos Permian II 15% 191 — Other Various 127 127 $ 7,821 $ 6,552 ___________ (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, 2018 2017 2016 (Millions) RMM $ 795 $ — $ — Appalachia Midstream Investments 246 70 28 Jackalope 42 — — Brazos Permian II 27 — — Laurel Mountain 16 — — Discovery 5 1 — DBJV — 32 105 Caiman II — 24 22 Other 1 5 22 $ 1,132 $ 132 $ 177
Dividends and distributions [Table Text Block]	Dividends and distributions The organizational documents of entities in which we have an equity-method investment generally require distribution of available cash to members on at least a quarterly basis. These transactions reduced the carrying value of our investments and included: Years Ended December 31, 2018 2017 2016 (Millions) Appalachia Midstream Investments $ 297 $ 270 $ 211 Gulfstream 93 92 100 OPPL 73 68 69 UEOM 70 80 92 Caiman II 46 49 40 Discovery 45 127 141 DBJV — 39 39 Laurel Mountain 23 32 28 Other 46 27 22 $ 693 $ 784 $ 742
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, 2018 2017 (Millions) Assets (liabilities): Current assets $ 834 $ 447 Noncurrent assets 13,199 9,181 Current liabilities (605 ) (295 ) Noncurrent liabilities (2,491 ) (1,538 ) Years Ended December 31, 2018 2017 2016 (Millions) Gross revenue $ 2,411 $ 1,961 $ 1,883 Operating income 804 871 799 Net income 795 806 726

Other Income and Expenses (Tabl

Other Income and Expenses (Tables)	12 Months Ended
	Dec. 31, 2018
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, 2018 2017 2016 (Millions) Atlantic-Gulf Amortization of regulatory assets associated with asset retirement obligations $ 33 $ 33 $ 33 Accrual of regulatory liability related to overcollection of certain employee expenses 22 22 25 Project development costs related to Constitution (Note 4) 4 16 28 Gains on asset retirements (12 ) — (11 ) West Gains on contract settlements and terminations — (15 ) — Regulatory charge per approved rates related to Tax Reform 24 — — Charge for regulatory liability associated with the decrease in Northwest Pipeline’s estimated deferred state income tax rates following WPZ Merger 12 — — Other Gain on sale of Refinery Grade Propylene Splitter — (12 ) — Loss on sale of Canadian operations (Note 3) — 5 66 Net foreign currency exchange (gains) losses (1) — — 10 Gain on sale of unused pipe — — (10 ) Benefit of regulatory asset associated with increase in Transco’s estimated deferred state income tax rate following WPZ Merger (37 ) — — ________________ (1) Primarily relates to gains and losses incurred on foreign currency transactions and the remeasurement of U.S. dollar-denominated current assets and liabilities within our former Canadian operations (see Note 3 – Divestitures ).
Defined Benefit Plan Settlement Charge Expense 1 [Table Text Block]	Other income (expense) – net below Operating income (loss) includes settlement charge expense related to the program to pay out certain deferred vested pension benefits as follows (see Note 10 – Employee Benefit Plans ): Years Ended December 31, 2018 2017 (Millions) Atlantic-Gulf $ 7 $ 15 Northeast 4 7 West 6 13 Other 5 35

Provision (Benefit) for Incom_2

Provision (Benefit) for Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2018
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, 2018 2017 2016 (Millions) Current: Federal $ (83 ) $ 15 $ — State 1 23 2 Foreign — — (1 ) (82 ) 38 1 Deferred: Federal 183 (2,004 ) (6 ) State 37 (8 ) 61 Foreign — — (81 ) 220 (2,012 ) (26 ) Provision (benefit) for income taxes $ 138 $ (1,974 ) $ (25 )
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, 2018 2017 2016 (Millions) Provision (benefit) at statutory rate $ 69 $ 187 $ (131 ) Increases (decreases) in taxes resulting from: Impact of nontaxable noncontrolling interests (73 ) (117 ) (22 ) Federal Tax Reform rate change — (1,932 ) — State income taxes (net of federal benefit) (10 ) (17 ) 3 State deferred income tax rate change 38 26 43 Foreign operations – net (including tax effect of Canadian Sale) — (127 ) 78 Valuation allowance 105 — — Translation adjustment of certain unrecognized tax benefits — — (1 ) Other – net 9 6 5 Provision (benefit) for income taxes $ 138 $ (1,974 ) $ (25 )
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. Following the WPZ Merger, the attributes below are presented based on the underlying assets. December 31, 2018 2017 (Millions) Deferred income tax liabilities: Property, plant and equipment $ 2,317 $ — Investments 295 3,565 Other 30 19 Total deferred income tax liabilities 2,642 3,584 Deferred income tax assets: Accrued liabilities 667 53 Minimum tax credit 71 155 Foreign tax credit 140 140 Federal loss carryovers 147 — State losses and credits 319 283 Other 94 30 Total deferred income tax assets 1,438 661 Less valuation allowance 320 224 Net deferred income tax assets 1,118 437 Overall net deferred income tax liabilities $ 1,524 $ 3,147
Reconciliation of unrecognized tax benefits [Table Text Block]	A reconciliation of the beginning and ending amount of unrecognized tax benefits is as follows: 2018 2017 (Millions) Balance at beginning of period $ 50 $ 50 Additions for tax positions of prior years 1 — Balance at end of period $ 51 $ 50

Earnings (Loss) Per Common Sh_2

Earnings (Loss) Per Common Share (Tables)	12 Months Ended
	Dec. 31, 2018
Earnings Per Share [Abstract]
Earnings (loss) per common share [Table Text Block]	Years Ended December 31, 2018 2017 2016 (Dollars in millions, except per-share amounts; shares in thousands) Net income (loss) available to common stockholders $ (156 ) $ 2,174 $ (424 ) Basic weighted-average shares 973,626 826,177 750,673 Effect of dilutive securities: Nonvested restricted stock units — 1,704 — Stock options — 637 — Diluted weighted-average shares (1) 973,626 828,518 750,673 Earnings (loss) per common share: Basic $ (.16 ) $ 2.63 $ (.57 ) Diluted $ (.16 ) $ 2.62 $ (.57 ) ________________ (1) For the years ended December 31, 2018 and December 31, 2016, 2.0 million and 0.6 million weighted-average nonvested restricted stock units, respectively, and 0.5 million and 0.5 million weighted-average stock options, respectively, have been excluded from the computation of diluted earnings (loss) per common share as their inclusion would be antidilutive due to our loss attributable to The Williams Companies, Inc.

Employee Benefit Plans (Tables)

Employee Benefit Plans (Tables)	12 Months Ended
	Dec. 31, 2018
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 2018 2017 2018 2017 (Millions) Change in benefit obligation: Benefit obligation at beginning of year $ 1,319 $ 1,466 $ 206 $ 197 Service cost 50 50 1 1 Interest cost 46 59 7 8 Plan participants’ contributions — — 2 3 Benefits paid (35 ) (35 ) (13 ) (14 ) Net actuarial loss (gain) (90 ) 40 (17 ) 11 Settlements (103 ) (261 ) — — Net increase (decrease) in benefit obligation (132 ) (147 ) (20 ) 9 Benefit obligation at end of year 1,187 1,319 186 206 Change in plan assets: Fair value of plan assets at beginning of year 1,227 1,254 227 208 Actual return on plan assets (45 ) 184 (7 ) 25 Employer contributions 88 85 5 5 Plan participants’ contributions — — 2 3 Benefits paid (35 ) (35 ) (13 ) (14 ) Settlements (103 ) (261 ) — — Net increase (decrease) in fair value of plan assets (95 ) (27 ) (13 ) 19 Fair value of plan assets at end of year 1,132 1,227 214 227 Funded status — overfunded (underfunded) $ (55 ) $ (92 ) $ 28 $ 21 Accumulated benefit obligation $ 1,171 $ 1,294
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 plan presented in the previous table are recognized in the Consolidated Balance Sheet within the following accounts: December 31, 2018 2017 (Millions) Underfunded pension plans: Current liabilities $ (2 ) $ (2 ) Noncurrent liabilities (53 ) (90 ) Overfunded (underfunded) other postretirement benefit plan: Current liabilities (6 ) (6 ) Noncurrent assets 34 27
Pre-tax amounts not yet recognized in net periodic benefit cost (credit)[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 2018 2017 2018 2017 (Millions) Amounts included in Accumulated other comprehensive income (loss) : Net actuarial loss $ (347 ) $ (375 ) $ (12 ) $ (21 ) Amounts included in regulatory liabilities associated with Transco and Northwest Pipeline: Prior service credit N/A N/A $ — $ 2 Net actuarial gain N/A N/A 4 14
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 2018 2017 2016 2018 2017 2016 (Millions) Components of net periodic benefit cost (credit): Service cost $ 50 $ 50 $ 54 $ 1 $ 1 $ 1 Interest cost 46 59 62 7 8 8 Expected return on plan assets (63 ) (82 ) (85 ) (11 ) (11 ) (12 ) Amortization of prior service credit — — — (2 ) (13 ) (15 ) Amortization of net actuarial loss 23 27 30 — — — Net actuarial loss from settlements 23 71 2 — — — Reclassification to regulatory liability — — — 2 3 4 Net periodic benefit cost (credit) $ 79 $ 125 $ 63 $ (3 ) $ (12 ) $ (14 )
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 2018 2017 2016 2018 2017 2016 (Millions) Other changes in plan assets and benefit obligations recognized in Other comprehensive income (loss) : Net actuarial gain (loss) $ (18 ) $ 62 $ (23 ) $ 9 $ (3 ) $ — Amortization of prior service credit — — — — (5 ) (6 ) Amortization of net actuarial loss 23 27 30 — — — Net actuarial loss from settlements 23 71 2 — — — Other changes in plan assets and benefit obligations recognized in Other comprehensive income (loss) $ 28 $ 160 $ 9 $ 9 $ (8 ) $ (6 )
Schedule of Regulatory Assets / Liabilities [Table Text Block]	Other changes in plan assets and benefit obligations for our other postretirement benefit plan associated with Transco and Northwest Pipeline are recognized in regulatory assets and liabilities. Amounts recognized in regulatory assets and liabilities for the years ended December 31 consist of the following: 2018 2017 2016 (Millions) Other changes in plan assets and benefit obligations recognized in regulatory (assets) and liabilities: Net actuarial gain (loss) $ (10 ) $ 6 $ 2 Amortization of prior service credit (2 ) (8 ) (9 )
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 2018 2017 2018 2017 Discount rate 4.34 % 3.66 % 4.39 % 3.71 % Rate of compensation increase 4.83 4.93 N/A N/A Cash balance interest crediting rate 4.25 4.25 N/A N/A The weighted-average assumptions utilized to determine Net periodic benefit cost (credit) for the years ended December 31 are as follows: Pension Benefits Other Postretirement Benefits 2018 2017 2016 2018 2017 2016 Discount rate 3.67 % 4.17 % 4.37 % 3.71 % 4.27 % 4.50 % Expected long-term rate of return on plan assets 5.34 6.45 6.85 4.95 5.53 6.11 Rate of compensation increase 4.93 4.87 4.88 N/A N/A N/A Cash balance interest crediting rate 4.25 4.25 4.25 N/A N/A N/A
Fair values of plan assets [Table Text Block]	The fair values of our pension plan assets at December 31, 2018 and 2017 by asset class are as follows: 2018 Quoted Prices Significant Significant Total (Millions) Pension assets: Cash management fund $ 10 $ — $ — $ 10 Equity securities: U.S. large cap 30 — — 30 U.S. small cap 22 — — 22 Fixed income securities (1): U.S. Treasury securities 157 — — 157 Government and municipal bonds — 21 — 21 Mortgage and asset-backed securities — 48 — 48 Corporate bonds — 210 — 210 Insurance company investment contracts and other — 6 — 6 $ 219 $ 285 $ — 504 Commingled investment funds measured at net asset value practical expedient (2): Equities — U.S. large cap 123 Equities — International small cap 8 Equities — International emerging markets 19 Equities — International developed markets 51 Fixed income — U.S. long duration 335 Fixed income — Corporate bonds 92 Total assets at fair value at December 31, 2018 $ 1,132 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 The fair values of our other postretirement benefits plan assets at December 31, 2018 and 2017 by asset class are as follows: 2018 Quoted Prices Significant Significant Total (Millions) Other postretirement benefit assets: Cash management funds $ 11 $ — $ — $ 11 Equity securities: U.S. large cap 20 — — 20 U.S. small cap 9 — — 9 International developed markets large cap growth — 5 — 5 Fixed income securities (1): U.S. Treasury securities 19 — — 19 Government and municipal bonds — 2 — 2 Mortgage and asset-backed securities — 6 — 6 Corporate bonds — 25 — 25 Mutual fund — Municipal bonds 43 — — 43 $ 102 $ 38 $ — 140 Commingled investment funds measured at net asset value practical expedient (2): Equities — U.S. large cap 14 Equities — International small cap 1 Equities — International emerging markets 2 Equities — International developed markets 6 Fixed income — U.S. long duration 40 Fixed income — Corporate bonds 11 Total assets at fair value at December 31, 2018 $ 214 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 ____________ (1) The weighted-average credit quality rating of the fixed income security portfolio is investment grade with a weighted-average duration of approximately 13 years for 2018 and 12 years for 2017 . (2) The stated intents of the funds vary based on each commingled fund’s investment objective. These objectives generally include strategies to replicate or outperform various market indices. Certain standard withdrawal restrictions generally apply, which may include redemption notification period restrictions ranging from 10 days to 30 days . Additionally, the fund managers retain the right to restrict withdrawals from and/or purchases into the funds so as not to disadvantage other investors in the funds. Generally, the funds also reserve the right to make all or a portion of the redemption in-kind rather than in cash or a combination of cash and in-kind.
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) 2019 $ 85 $ 14 2020 87 14 2021 90 13 2022 90 14 2023 89 14 2024-2028 467 59

Property, Plant, and Equipment

Property, Plant, and Equipment (Tables)	12 Months Ended
	Dec. 31, 2018
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, 2018 2017 (Millions) Nonregulated: Natural gas gathering and processing facilities 5 - 40 $ 15,324 $ 18,440 Construction in progress Not applicable 778 566 Other 2 - 45 2,356 2,776 Regulated: Natural gas transmission facilities 1.20 - 6.97 17,312 14,460 Construction in progress Not applicable Not applicable 965 1,637 Other 5 - 45 1.35 - 33.33 1,926 1,634 Total property, plant, and equipment, at cost 38,661 39,513 Accumulated depreciation and amortization (11,157 ) (11,302 ) Property, plant, and equipment — net $ 27,504 $ 28,211 __________ (1) Estimated useful life and depreciation rates are presented as of December 31, 2018 . Depreciation rates and estimated useful lives for regulated assets are prescribed by the FERC.
Asset Retirement Obligation [Table Text Block]	The following table presents the significant changes to our ARO, of which $968 million and $946 million are included in Regulatory liabilities, deferred income, and other with the remaining current portion in Accrued liabilities at December 31, 2018 and 2017 , respectively. December 31, 2018 2017 (Millions) Beginning balance $ 998 $ 862 Liabilities incurred 21 33 Liabilities settled (19 ) (16 ) Accretion expense (1) 71 141 Revisions (2) (39 ) (22 ) Ending balance $ 1,032 $ 998 ___________ (1) The decrease in accretion expense in 2018 primarily reflects the absence of a 2017 adjustment associated with obligations identified from certain Transco land agreements. (2) Several factors are considered in the annual review process, including inflation rates, current estimates for removal cost, market risk premiums, discount rates, and the estimated remaining useful life of the assets. The 2018 revisions reflect changes in removal cost estimates, decreases in the estimated remaining useful life of certain assets and increases in the discount rates used in the annual review process. The 2017 revisions reflect changes in removal cost estimates and decreases in the estimated remaining useful life of certain assets and discount rates used in the annual review process.

Other Intangible Assets (Tables

Other Intangible Assets (Tables)	12 Months Ended
	Dec. 31, 2018
Goodwill and Intangible Assets Disclosure [Abstract]
Schedule of Finite-Lived Intangible Assets [Table Text Block]	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: 2018 2017 Gross Carrying Amount Accumulated Amortization Gross Carrying Amount Accumulated Amortization (Millions) Contractual customer relationships $ 9,232 $ (1,465 ) $ 10,027 $ (1,283 )

Accrued Liabilities (Tables)

Accrued Liabilities (Tables)	12 Months Ended
	Dec. 31, 2018
Accrued Liabilities, Current [Abstract]
Accrued Liabilities [Table Text Block]	December 31, 2018 2017 (Millions) Interest on debt $ 282 $ 267 Revenue contract liabilities (Note 2) 244 361 Employee costs 205 202 Other, including other loss contingencies 371 337 $ 1,102 $ 1,167

Debt, Banking Arrangements, a_2

Debt, Banking Arrangements, and Leases (Tables)	12 Months Ended
	Dec. 31, 2018
Debt Disclosure [Abstract]
Schedule of Long-term Debt Instruments [Table Text Block]	Long-Term Debt December 31, 2018 2017 (Millions) Transco: 6.05% Notes due 2018 $ — $ 250 7.08% Debentures due 2026 8 8 7.25% Debentures due 2026 200 200 7.85% Notes due 2026 1,000 1,000 4% Notes due 2028 400 — 5.4% Notes due 2041 375 375 4.45% Notes due 2042 400 400 4.6% Notes due 2048 600 — Other financing obligations 1,067 231 Northwest Pipeline: 6.05% Notes due 2018 — 250 7.125% Debentures due 2025 85 85 4% Notes due 2027 500 250 WMB: 4.125% Notes due 2020 600 600 5.25% Notes due 2020 1,500 1,500 4% Notes due 2021 500 500 7.875% Notes due 2021 371 371 3.35% Notes due 2022 750 750 3.6% Notes due 2022 1,250 1,250 3.7% Notes due 2023 850 850 4.5% Notes due 2023 600 600 4.3% Notes due 2024 1,000 1,000 4.55% Notes due 2024 1,250 1,250 4.875% Notes due 2024 — 750 3.9% Notes due 2025 750 750 4% Notes due 2025 750 750 3.75% Notes due 2027 1,450 1,450 7.5% Debentures due 2031 339 339 7.75% Notes due 2031 252 252 8.75% Notes due 2032 445 445 6.3% Notes due 2040 1,250 1,250 5.8% Notes due 2043 400 400 5.4% Notes due 2044 500 500 5.75% Notes due 2044 650 650 4.9% Notes due 2045 500 500 5.1% Notes due 2045 1,000 1,000 4.85% Notes due 2048 800 — Various — 7.625% to 10.25% Notes and Debentures due 2019 to 2027 55 55 Credit facility loans 160 270 Debt issuance costs (131 ) (122 ) Net unamortized debt premium (discount) (62 ) (24 ) Total long-term debt, including current portion 22,414 20,935 Long-term debt due within one year (47 ) (501 ) Long-term debt $ 22,367 $ 20,434
Schedule of Maturities of Long-term Debt [Table Text Block]	The following table presents aggregate minimum maturities of long-term debt and other financing obligations, excluding net unamortized debt premium (discount) and debt issuance costs, for each of the next five years: December 31, 2018 (Millions) 2019 $ 47 2020 2,138 2021 890 2022 2,021 2023 1,633
Schedule of Line of Credit Facilities [Table Text Block]	Credit Facilities December 31, 2018 Stated Capacity Outstanding (Millions) Long-term credit facility (1) $ 4,500 $ 160 Letters of credit under certain bilateral bank agreements 14 ________________ (1) In managing our available liquidity, we do not expect a maximum outstanding amount in excess of the capacity of our credit facility inclusive of any outstanding amounts under our commercial paper program.
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, 2018 (Millions) 2019 $ 32 2020 31 2021 28 2022 24 2023 15 Thereafter 86 Total $ 216

Stockholders' Equity (Tables)

Stockholders' Equity (Tables)	12 Months Ended
	Dec. 31, 2018
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, 2017 $ (2 ) $ (1 ) $ (235 ) $ (238 ) Adoption of new accounting standard (Note 1) — — (61 ) (61 ) WPZ Merger (Note 1) (3 ) — — (3 ) Other comprehensive income (loss): Other comprehensive income (loss) before reclassifications (2 ) — (6 ) (8 ) Amounts reclassified from accumulated other comprehensive income (loss) 5 — 35 40 Other comprehensive income (loss) 3 — 29 32 Balance at December 31, 2018 $ (2 ) $ (1 ) $ (267 ) $ (270 )
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, 2018 : Component Reclassifications Classification (Millions) Cash flow hedges: Energy commodity contracts $ 9 Product sales Pension and other postretirement benefits: Amortization of actuarial (gain) loss and net actuarial loss from settlements included in net periodic benefit cost (credit) 46 Note 10 – Employee Benefit Plans Total before tax 55 Income tax benefit (12 ) Provision (benefit) for income taxes Net of income tax 43 Noncontrolling interest (3 ) Net income (loss) attributable to noncontrolling interests Reclassifications during the period $ 40

Equity-Based Compensation (Tabl

Equity-Based Compensation (Tables) - Williams Companies Incentive Plan [Member]	12 Months Ended
	Dec. 31, 2018
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, 2018 : Stock Options Options Weighted- Average Exercise Price Aggregate Intrinsic Value (Millions) (Millions) Outstanding at December 31, 2017 6.6 $ 31.53 Granted 1.3 $ 29.09 Exercised (0.4 ) $ 23.06 Cancelled (0.2 ) $ 31.45 Outstanding at December 31, 2018 7.3 $ 31.55 $ 6 Exercisable at December 31, 2018 5.3 $ 32.63 $ 6
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, 2018 2017 2016 (Millions) Total intrinsic value of options exercised $ 3 $ 4 $ 2 Tax benefits realized on options exercised $ — $ 1 $ 1 Cash received from the exercise of options $ 9 $ 7 $ 4
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: 2018 2017 2016 Weighted-average grant date fair value of options for our common stock granted during the year, per share $ 5.49 $ 6.61 $ 7.90 Weighted-average assumptions: Dividend yield 4.7 % 4.2 % 3.2 % Volatility 30.1 % 35.1 % 44.7 % Risk-free interest rate 2.7 % 2.1 % 1.2 % 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, 2018 : Restricted Stock Units Outstanding Shares Weighted- Average Fair Value (1) (Millions) Nonvested at December 31, 2017 4.2 $ 31.02 Granted 1.7 $ 30.48 Forfeited (0.5 ) $ 32.97 Vested (0.9 ) $ 39.30 Nonvested at December 31, 2018 4.5 $ 28.96 ______________ (1) Performance-based restricted stock units are valued considering measures of total shareholder return, utilizing a Monte Carlo valuation method, and return on capital employed. All other restricted stock units are valued at the grant-date market price. Restricted stock units generally vest after three years .
Other restricted stock unit information [Table Text Block]	Value of Restricted Stock Units 2018 2017 2016 Weighted-average grant date fair value of restricted stock units granted during the year, per share $ 30.48 $ 29.47 $ 26.51 Total fair value of restricted stock units vested during the year ($s in millions) $ 35 $ 33 $ 32

Fair Value Measurements, Guar_2

Fair Value Measurements, Guarantees, and Concentration of Credit Risk (Tables)	12 Months Ended
	Dec. 31, 2018
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, margin deposits, and accounts payable approximate fair value because of the short-term nature of these instruments. Therefore, these assets and liabilities are not presented in the following table. Fair Value Measurements Using Carrying Amount Fair Value Quoted Prices In Active Markets for Identical Assets (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) (Millions) Assets (liabilities) at December 31, 2018: Measured on a recurring basis: ARO Trust investments $ 150 $ 150 $ 150 $ — $ — Energy derivatives assets not designated as hedging instruments 3 3 3 — — Energy derivatives liabilities not designated as hedging instruments (7 ) (7 ) (4 ) — (3 ) Additional disclosures: Long-term debt, including current portion (22,414 ) (23,330 ) — (23,330 ) — Guarantees (43 ) (30 ) — (14 ) (16 ) 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: Long-term debt, including current portion (20,935 ) (23,005 ) — (23,005 ) — Guarantees (43 ) (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, except as specifically noted. Impairments Years Ended December 31, Classification Segment Date of Measurement Fair Value 2018 2017 2016 (Millions) Certain gathering operations (1) Property, plant, and equipment – net and Intangible assets - net of accumulated amortization West December 31, 2018 $ 470 $ 1,849 Certain idle pipeline assets (2) Property, plant, and equipment – net Other June 30, 2018 25 66 Certain gathering operations (3) Property, plant, and equipment – net and Intangible assets - net of accumulated amortization West September 30, 2017 439 $ 1,019 Certain gathering operations (4) Property, plant, and equipment – net and Intangible assets - net of accumulated amortization Northeast G&P September 30, 2017 21 115 Certain NGL pipeline (5) Property, plant, and equipment – net Other September 30, 2017 32 68 Certain olefins pipeline project (6) Property, plant, and equipment – net Other June 30, 2017 18 23 Canadian operations (7) Assets held for sale Other June 30, 2016 1,130 $ 747 Certain gathering operations (8) Property, plant, and equipment – net West June 30, 2016 18 48 Certain idle pipeline assets Property, plant, and equipment – net Other December 31, 2016 73 8 Fair value measurements of certain assets 1,915 1,225 803 Other impairments and write-downs (9) — 23 70 Impairment of certain assets $ 1,915 $ 1,248 $ 873 Equity-method investments (10) Investments Northeast G&P December 31, 2018 $ 1,293 $ 32 Equity-method investments (11) Investments West and Northeast G&P December 31, 2016 1,295 $ 318 Impairments Years Ended December 31, Classification Segment Date of Measurement Fair Value 2018 2017 2016 (Millions) Equity-method investments (12) Investments West and Northeast G&P March 31, 2016 1,294 109 Other equity-method investment Investments West March 31, 2016 — 3 Impairment of equity-method investments $ 32 $ 430 ______________ (1) Relates to our gathering operations in the Barnett Shale. Certain of our contractual gathering rates, primarily those in the Barnett Shale, are based on a percentage of the New York Mercantile Exchange (NYMEX) natural gas prices. During the fourth quarter of 2018, we determined there was a sustained decline in the forward price curves for natural gas. During this same period, a large producer customer in the Barnett Shale removed their remaining drilling rig. These factors gave rise to an impairment evaluation of these assets, which incorporated management’s projections of future drilling activity and gathering rates, taking into consideration the information previously noted as well as recently available information regarding producer drilling cost assumptions in the basin. The resulting estimate of future undiscounted cash flows was less than our carrying value, necessitating the estimation of the fair value of these assets. To arrive at the fair value, we utilized an income approach with a discount rate of 8.5 percent , reflecting an estimated cost of capital and risks associated with the underlying assets. (2) Relates to certain idle pipelines. The estimated fair value was determined by a market approach incorporating information derived from bids received for these assets, which we marketed for sale together with certain other assets. These inputs resulted in a fair value measurement within Level 2 of the fair value hierarchy. We sold these assets in the fourth quarter of 2018. (See Note 3 – Divestitures .) (3) Relates to certain gathering operations in the Mid-Continent region. During the third quarter of 2017, we received solicitations and engaged in negotiations for the sale of certain of these assets which led to our impairment evaluation. The estimated fair value was determined using an income approach and incorporated market inputs based on ongoing negotiations for a potential sale of a portion of the underlying assets. For the income approach, we utilized a discount rate of 10.2 percent , reflecting an estimated cost of capital and risks associated with the underlying assets. (4) Relates to certain gathering operations in the Marcellus South region resulting from an anticipated decline in future volumes following a third-quarter 2017 shut-in by the primary producer. The estimated fair value was determined by the income approach utilizing a discount rate of 11.1 percent , reflecting an estimated cost of capital and risks associated with the underlying assets. (5) Relates to an NGL pipeline near the Houston Ship Channel region which we anticipated would be underutilized for the foreseeable future. The estimated fair value was primarily determined by using a market approach based on our analysis of observable inputs in the principal market. We sold these assets in the fourth quarter of 2018. (See Note 3 – Divestitures .) (6) Relates primarily to project development costs associated with an olefins pipeline project in the Gulf Coast region, the likelihood of completion we considered remote. The estimated fair value of the remaining pipe and equipment considered a market approach based on our analysis of observable inputs in the principal market, as well as an estimate of replacement cost. We sold these assets in the fourth quarter of 2018. (See Note 3 – Divestitures .) (7) Relates to our Canadian operations. We designated these operations as held for sale as of June 30, 2016. As a result, we measured the fair value of the disposal group, resulting in an impairment charge. The estimated fair value was determined by a market approach based primarily on inputs received in the marketing process and reflected our estimate of the potential assumed proceeds. We disposed of our Canadian operations through a sale during the third quarter of 2016. (See Note 3 – Divestitures .) (8) Relates to certain gathering assets within the Mid-Continent region. The estimated fair value was determined by a market approach based on our analysis of observable inputs in the principal market. (9) Reflects multiple individually insignificant impairments and write-downs of other certain assets that may no longer be in use or are surplus in nature for which the fair value was determined to be lower than the carrying value. (10) Relates to Northeast G&P’s equity-method investment in UEOM. The estimated fair value was determined by a market approach based on our analysis of inputs in the principal market. (11) Relates to West’s previously held interest in Ranch Westex and multiple, currently held Appalachia Midstream Investments at Northeast G&P. The historical carrying value of these equity-method investments was initially recorded based on estimated fair value during the third quarter of 2014 in conjunction with the acquisition of ACMP. We estimated the fair value of these Appalachia Midstream Investments using an income approach based on expected future cash flows and appropriate discount rates. The determination of estimated future cash flows involved significant assumptions regarding gathering volumes, rates, and related capital spending. The discount rate utilized for the Appalachia Midstream Investments evaluation was 10.2 percent and reflected an estimated cost of capital as impacted by market conditions and risks associated with the underlying businesses. In addition to utilizing an income approach, we also considered a market approach for certain Appalachia Midstream Investments and Ranch Westex based on an agreement reached in February 2017 to exchange our interests in DBJV and Ranch Westex for additional interests in certain Appalachia Midstream Investments and cash. (See Note 6 – Investing Activities .) (12) Relates to West’s previously held interest in DBJV and Northeast G&P’s currently held equity-method investment in Laurel Mountain. Our carrying values in these equity-method investments had been written down to fair value at December 31, 2015. Our first-quarter 2016 analysis reflected higher discount rates for both of these equity-method investments, along with lower natural gas prices for Laurel Mountain. We estimated the fair value of these equity-method investments using an income approach based on expected future cash flows and appropriate discount rates. The determination of estimated future cash flows involved significant assumptions regarding gathering volumes and related capital spending. Discount rates utilized ranged from 13.0 percent to 13.3 percent and reflected increases in the estimated cost of capital, revised estimates of expected future cash flows, and risks associated with the underlying businesses.
Concentration of receivables, net of allowances, by product or service [Table Text Block]	The following table summarizes concentration of receivables, net of allowances: December 31, 2018 2017 (Millions) NGLs, natural gas, and related products and services $ 626 $ 760 Transportation of natural gas and related products 232 212 Other 134 4 Total $ 992 $ 976

Segment Disclosures (Tables)

Segment Disclosures (Tables)	12 Months Ended
	Dec. 31, 2018
Segment Reporting [Abstract]
Schedule of Revenue from External Customers, by Geographical Areas [Table Text Block]	The following geographic area data includes Revenues from external customers based on product shipment origin: United States Canada Total (Millions) Revenues from external customers: 2018 $ 8,686 $ — $ 8,686 2017 8,030 1 8,031 2016 7,425 74 7,499
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 : Northeast G&P Atlantic-Gulf West Other Eliminations Total (Millions) 2018 Segment revenues: Service revenues External $ 935 $ 2,460 $ 2,085 $ 22 $ — $ 5,502 Internal 41 49 — 12 (102 ) — Total service revenues 976 2,509 2,085 34 (102 ) 5,502 Total service revenues – commodity consideration (external only) 20 59 321 — — 400 Product sales External 245 174 2,365 — — 2,784 Internal 42 261 83 — (386 ) — Total product sales 287 435 2,448 — (386 ) 2,784 Total revenues $ 1,283 $ 3,003 $ 4,854 $ 34 $ (488 ) $ 8,686 Other financial information: Additions to long-lived assets $ 477 $ 2,297 $ 361 $ 36 $ — $ 3,171 Proportional Modified EBITDA of equity-method investments 493 183 94 — — 770 2017 Segment revenues: Service revenues External $ 837 $ 2,202 $ 2,246 $ 27 $ — $ 5,312 Internal 35 37 — 11 (83 ) — Total service revenues 872 2,239 2,246 38 (83 ) 5,312 Product sales External 264 257 1,840 358 — 2,719 Internal 27 227 173 8 (435 ) — Total product sales 291 484 2,013 366 (435 ) 2,719 Total revenues $ 1,163 $ 2,723 $ 4,259 $ 404 $ (518 ) $ 8,031 Other financial information: Additions to long-lived assets $ 460 $ 2,001 $ 321 $ 32 $ — $ 2,814 Proportional Modified EBITDA of equity-method investments 452 264 79 — — 795 2016 Segment revenues: Service revenues External $ 836 $ 1,959 $ 2,328 $ 48 $ — $ 5,171 Internal 34 39 — 11 (84 ) — Total service revenues 870 1,998 2,328 59 (84 ) 5,171 Product sales External 134 245 1,183 766 — 2,328 Internal 28 205 197 22 (452 ) — Total product sales 162 450 1,380 788 (452 ) 2,328 Total revenues $ 1,032 $ 2,448 $ 3,708 $ 847 $ (536 ) $ 7,499 Other financial information: Additions to long-lived assets $ 223 $ 1,608 $ 223 $ 92 $ (1 ) $ 2,145 Proportional Modified EBITDA of equity-method investments 357 287 110 — — 754
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, 2018 2017 2016 (Millions) Modified EBITDA by segment: Northeast G&P $ 1,086 $ 819 $ 853 Atlantic-Gulf 2,023 1,238 1,621 West 308 412 1,544 Other (29 ) 997 (696 ) 3,388 3,466 3,322 Accretion expense associated with asset retirement obligations for nonregulated operations (33 ) (33 ) (31 ) Depreciation and amortization expenses (1,725 ) (1,736 ) (1,763 ) Equity earnings (losses) 396 434 397 Impairment of equity-method investments (32 ) — (430 ) Other investing income (loss) – net 219 282 63 Proportional Modified EBITDA of equity-method investments (770 ) (795 ) (754 ) Interest expense (1,112 ) (1,083 ) (1,179 ) (Provision) benefit for income taxes (138 ) 1,974 25 Net income (loss) $ 193 $ 2,509 $ (350 )
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, 2018 December 31, 2017 December 31, 2018 December 31, 2017 (Millions) Northeast G&P $ 14,526 $ 14,397 $ 5,319 $ 5,307 Atlantic-Gulf 16,346 14,989 776 823 West 13,948 16,143 1,726 422 Other (1) 849 1,449 — — Eliminations (2) (367 ) (626 ) — — Total $ 45,302 $ 46,352 $ 7,821 $ 6,552 ______________ (1) Decrease in Other is due primarily to a decreased cash balance. (2) Eliminations primarily relate to the intercompany notes and accounts receivable generated by our cash management program.

General, Description of Busin_4

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

Aug. 10, 2018

Feb. 10, 2017

Feb. 01, 2017

Jan. 09, 2017

Feb. 03, 2017

Jan. 31, 2017

Jun. 30, 2018

Sep. 30, 2017

Dec. 31, 2018

Dec. 31, 2017

Dec. 31, 2016

Sep. 30, 2018

Jan. 01, 2018

Mar. 31, 2017

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

Regulatory Charges In Operating Expense Resulting From Tax Reform

$ (17)

$ 674

$ 0

Service revenues

8,604

Operating and maintenance expenses

1,507

1,576

1,592

Selling, General and Administrative Expense

569

594

722

Operating Income (Loss)

768

927

689

Other income (expense) - net below Operating income (loss)

92

(25)

85

Basis Of Presentation [Abstract]

Changes in ownership of consolidated subsidiaries, net

(4)

(910)

(6)

Net Cash Provided (Used) by Operating Activities

3,293

3,089

4,155

Net Cash Provided (Used) by Investing Activities

2,725

(100)

891

Stock Issued During Period, Shares, New Issues

9,750

65,000

Stock Issued During Period, Value, New Issues

35

2,118

Additional Paid in Capital, Common Stock

24,693

18,508

Other Assets, Noncurrent

746

619

Accumulated Other Comprehensive Income (Loss), Net of Tax

270

238

Stockholders' Equity Attributable to Noncontrolling Interest

(1,337)

(6,519)

Deferred Tax Liabilities, Net, Noncurrent

(1,524)

(3,147)

Regulatory Liabilities

1,326

1,268

Financial Repositioning [Member]

Basis Of Presentation [Abstract]

Sale Of Stock Number Of Shares Issued In Transaction

277

59,000

289,000

Payments to Acquire Limited Partnership Interests

$ 56

$ 10

Sale of Stock, Price Per Share

$ 36.08586

Dividend Reinvestment Program [Member]

Basis Of Presentation [Abstract]

Sale of Stock, Consideration Received on Transaction

$ 46

61

10

Noncontrolling Interest [Member]

Basis Of Presentation [Abstract]

Changes in ownership of consolidated subsidiaries, net

(18)

(2,407)

(18)

Stock Issued During Period, Value, New Issues

0

0

Capital in excess of par value [Member]

Basis Of Presentation [Abstract]

Changes in ownership of consolidated subsidiaries, net

14

1,497

$ 12

Stock Issued During Period, Value, New Issues

$ 0

$ 2,043

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%

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%

Jackalope Gas Gathering Services LLC [Member]

General and Description Of Business [Abstract]

Equity Method Investment, Ownership Percentage

50.00%

Rocky Mountain Midstream Holdings LLC [Member]

General and Description Of Business [Abstract]

Equity Method Investment, Ownership Percentage

50.00%

40.00%

Brazos Permian II, LLC [Member]

General and Description Of Business [Abstract]

Equity Method Investment, Ownership Percentage

15.00%

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

Basis Of Presentation [Abstract]

Master limited partnership, general partner ownership percentage

2.00%

Northeast G And P [Member] | Utica East Ohio Midstream, LLC [Member]

General and Description Of Business [Abstract]

Equity Method Investment, Ownership Percentage

62.00%

Northeast G And P [Member] | Laurel Mountain Midstream, LLC [Member]

General and Description Of Business [Abstract]

Equity Method Investment, Ownership Percentage

69.00%

Northeast G And P [Member] | Caiman Energy II [Member]

General and Description Of Business [Abstract]

Equity Method Investment, Ownership Percentage

58.00%

Northeast G And P [Member] | Appalachia Midstream Services, LLC [Member]

General and Description Of Business [Abstract]

Equity Method Investment, Ownership Percentage

66.00%

Northeast G And P [Member] | Cardinal Gas Services LLC [Member]

General and Description Of Business [Abstract]

Variable Interest Entity Ownership Percentage

66.00%

Northeast G And P [Member] | Appalachia Midstream Services, LLC [Member]

General and Description Of Business [Abstract]

Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest

66.00%

Atlantic Gulf [Member] | Gulfstream Natural Gas System, L.L.C.[Member]

General and Description Of Business [Abstract]

Equity Method Investment, Ownership Percentage

50.00%

Atlantic Gulf [Member] | Discovery Producer Services LLC [Member]

General and Description Of Business [Abstract]

Equity Method Investment, Ownership Percentage

60.00%

Atlantic Gulf [Member] | Gulfstar One [Member]

General and Description Of Business [Abstract]

Variable Interest Entity Ownership Percentage

51.00%

Atlantic Gulf [Member] | Constitution Pipeline Company LLC [Member]

General and Description Of Business [Abstract]

Variable Interest Entity Ownership Percentage

41.00%

West [Member] | Delaware Basin Gas Gathering System [Member]

General and Description Of Business [Abstract]

Equity Method Investment, Ownership Percentage

50.00%

West [Member] | Overland Pass Pipeline Company LLC [Member]

General and Description Of Business [Abstract]

Equity Method Investment, Ownership Percentage

50.00%

West [Member] | Jackalope Gas Gathering Services LLC [Member]

General and Description Of Business [Abstract]

Equity Method Investment, Ownership Percentage

50.00%

West [Member] | Rocky Mountain Midstream Holdings LLC [Member]

General and Description Of Business [Abstract]

Equity Method Investment, Ownership Percentage

50.00%

West [Member] | Brazos Permian II, LLC [Member]

General and Description Of Business [Abstract]

Equity Method Investment, Ownership Percentage

15.00%

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

$ (121)

Accounting Standards Update 2014-09 [Member] | Difference between Revenue Guidance in Effect before and after Topic 606 [Member]

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

Operating and maintenance expenses

$ 1

Operating Income (Loss)

(120)

Basis Of Presentation [Abstract]

Other Assets, Noncurrent

(4)

Stockholders' Equity Attributable to Noncontrolling Interest

(28)

Deferred Tax Liabilities, Net, Noncurrent

$ (20)

Conway Fractionator [Member] | West [Member]

General and Description Of Business [Abstract]

Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest

50.00%

Geismar [Member] | Corporate and Other [Member]

General and Description Of Business [Abstract]

Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest

88.50%

WPZ Merger Agreement [Member]

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

Limited Partners' Capital Account, Units Outstanding

256,000

Basis Of Presentation [Abstract]

Stock Issued During Period, Shares, New Issues

382,000

Stock Issued During Period, Value, New Issues

$ 382

Additional Paid in Capital, Common Stock

6,112

Other Assets, Noncurrent

33

Accumulated Other Comprehensive Income (Loss), Net of Tax

3

Stockholders' Equity Attributable to Noncontrolling Interest

4,629

Deferred Tax Liabilities, Net, Noncurrent

$ 1,829

Reclassification out of Accumulated Other Comprehensive Income [Member] | Accounting Standards Update 2018-02 [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

$ (61)

Maximum [Member] | Accounting Standards Update 2016-02 [Member]

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

Operating Lease Right Of Use Asset Percentage Of Total Assets

1.00%

Basis Of Presentation [Abstract]

Operating Lease Liability Percentage Of Total Liabilities

1.00%

Regulatory Charges In Operating Expenses Resulting From Tax Reform [Member]

Basis Of Presentation [Abstract]

Regulatory Liabilities

$ 657

Summary of Significant Accounti

Summary of Significant Accounting Policies (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016	Jan. 01, 2018
Regulatory Assets and Liabilities [Line Items]
Regulatory Charges In Operating Expense Resulting From Tax Reform	$ (17)	$ 674	$ 0
Regulatory Charges Resulting From Tax Reform	(15)	776	$ 0
Regulatory Assets and Liabilities Disclosure [Abstract]
Regulatory Assets, Current	103	102
Regulatory Assets, Noncurrent	495	376
Total regulatory assets	598	478
Regulatory Liabilities, Current	5	18
Regulatory Liabilities, Noncurrent	1,321	1,250
Total regulatory liabilities	$ 1,326	$ 1,268
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
Accounting Standards Update 2014-09 [Member]
Regulatory Assets and Liabilities [Line Items]
New Accounting Pronouncement or Change in Accounting Principle, Cumulative Effect of Change on Equity or Net Assets				$ (121)
Retained Earnings [Member] | Accounting Standards Update 2018-02 [Member]
Regulatory Assets and Liabilities [Line Items]
New Accounting Pronouncement or Change in Accounting Principle, Cumulative Effect of Change on Equity or Net Assets				61
Reclassification out of Accumulated Other Comprehensive Income [Member] | Accounting Standards Update 2018-02 [Member]
Regulatory Assets and Liabilities [Line Items]
New Accounting Pronouncement or Change in Accounting Principle, Cumulative Effect of Change on Equity or Net Assets				$ (61)
Regulatory Charges In Operating Expenses Resulting From Tax Reform [Member]
Regulatory Assets and Liabilities Disclosure [Abstract]
Total regulatory liabilities	$ 657

Revenue by Category (Details)

Revenue by Category (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		$ 8,604
Total revenues		8,686	$ 8,031	$ 7,499
Northeast Midstream [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		1,262
Total revenues		1,283
Atlantic Gulf Midstream [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		924
Total revenues		942
West Midstream [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		4,399
Total revenues		4,411
Transco [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		2,050
Total revenues		2,061
Northwest Pipeline [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		443
Total revenues		443
Other Geographical [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		2
Total revenues		34
Intercompany Eliminations [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		(476)
Total revenues		(488)
NonRegulated Service Monetary Consideration [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		2,921
NonRegulated Service Monetary Consideration [Member] | Northeast Midstream [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		861
NonRegulated Service Monetary Consideration [Member] | Atlantic Gulf Midstream [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		541
NonRegulated Service Monetary Consideration [Member] | West Midstream [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		1,590
NonRegulated Service Monetary Consideration [Member] | Transco [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		0
NonRegulated Service Monetary Consideration [Member] | Northwest Pipeline [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		0
NonRegulated Service Monetary Consideration [Member] | Other Geographical [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		2
NonRegulated Service Monetary Consideration [Member] | Intercompany Eliminations [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		(73)
NonRegulated Service Commodity Consideration [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		400
NonRegulated Service Commodity Consideration [Member] | Northeast Midstream [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		20
NonRegulated Service Commodity Consideration [Member] | Atlantic Gulf Midstream [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		59
NonRegulated Service Commodity Consideration [Member] | West Midstream [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		321
NonRegulated Service Commodity Consideration [Member] | Transco [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		0
NonRegulated Service Commodity Consideration [Member] | Northwest Pipeline [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		0
NonRegulated Service Commodity Consideration [Member] | Other Geographical [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		0
NonRegulated Service Commodity Consideration [Member] | Intercompany Eliminations [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		0
Regulated Service [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		2,362
Regulated Service [Member] | Northeast Midstream [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		0
Regulated Service [Member] | Atlantic Gulf Midstream [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		0
Regulated Service [Member] | West Midstream [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		0
Regulated Service [Member] | Transco [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		1,921
Regulated Service [Member] | Northwest Pipeline [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		443
Regulated Service [Member] | Other Geographical [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		0
Regulated Service [Member] | Intercompany Eliminations [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		(2)
Other Service [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		144
Other Service [Member] | Northeast Midstream [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		94
Other Service [Member] | Atlantic Gulf Midstream [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		17
Other Service [Member] | West Midstream [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		46
Other Service [Member] | Transco [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		2
Other Service [Member] | Northwest Pipeline [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		0
Other Service [Member] | Other Geographical [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		0
Other Service [Member] | Intercompany Eliminations [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		(15)
Total Service Revenues [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		5,827
Total Service Revenues [Member] | Northeast Midstream [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		975
Total Service Revenues [Member] | Atlantic Gulf Midstream [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		617
Total Service Revenues [Member] | West Midstream [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		1,957
Total Service Revenues [Member] | Transco [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		1,923
Total Service Revenues [Member] | Northwest Pipeline [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		443
Total Service Revenues [Member] | Other Geographical [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		2
Total Service Revenues [Member] | Intercompany Eliminations [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		(90)
NGL And Natural Gas Product Sales [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		2,760
NGL And Natural Gas Product Sales [Member] | Northeast Midstream [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		287
NGL And Natural Gas Product Sales [Member] | Atlantic Gulf Midstream [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		307
NGL And Natural Gas Product Sales [Member] | West Midstream [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		2,421
NGL And Natural Gas Product Sales [Member] | Transco [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		127
NGL And Natural Gas Product Sales [Member] | Northwest Pipeline [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		0
NGL And Natural Gas Product Sales [Member] | Other Geographical [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		0
NGL And Natural Gas Product Sales [Member] | Intercompany Eliminations [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		(382)
Other Product Sales [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		17
Other Product Sales [Member] | Northeast Midstream [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		0
Other Product Sales [Member] | Atlantic Gulf Midstream [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		0
Other Product Sales [Member] | West Midstream [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		21
Other Product Sales [Member] | Transco [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		0
Other Product Sales [Member] | Northwest Pipeline [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		0
Other Product Sales [Member] | Other Geographical [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		0
Other Product Sales [Member] | Intercompany Eliminations [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		(4)
Total Product Sales [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		2,777
Total Product Sales [Member] | Northeast Midstream [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		287
Total Product Sales [Member] | Atlantic Gulf Midstream [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		307
Total Product Sales [Member] | West Midstream [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		2,442
Total Product Sales [Member] | Transco [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		127
Total Product Sales [Member] | Northwest Pipeline [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		0
Total Product Sales [Member] | Other Geographical [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		0
Total Product Sales [Member] | Intercompany Eliminations [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		(386)
Product and Service, Other [Member]
Disaggregation of Revenue [Line Items]
Other Revenue Not from Contract with Customer	[1]	82
Product and Service, Other [Member] | Northeast Midstream [Member]
Disaggregation of Revenue [Line Items]
Other Revenue Not from Contract with Customer		21
Product and Service, Other [Member] | Atlantic Gulf Midstream [Member]
Disaggregation of Revenue [Line Items]
Other Revenue Not from Contract with Customer		18
Product and Service, Other [Member] | West Midstream [Member]
Disaggregation of Revenue [Line Items]
Other Revenue Not from Contract with Customer		12
Product and Service, Other [Member] | Transco [Member]
Disaggregation of Revenue [Line Items]
Other Revenue Not from Contract with Customer		11
Product and Service, Other [Member] | Northwest Pipeline [Member]
Disaggregation of Revenue [Line Items]
Other Revenue Not from Contract with Customer		0
Product and Service, Other [Member] | Other Geographical [Member]
Disaggregation of Revenue [Line Items]
Other Revenue Not from Contract with Customer		32
Product and Service, Other [Member] | Intercompany Eliminations [Member]
Disaggregation of Revenue [Line Items]
Other Revenue Not from Contract with Customer		$ (12)
[1]	Service revenues in our Consolidated Statement of Operations include leasing revenues associated with our headquarters building and management fees that we receive for certain services we provide to operated joint ventures and other investments. The leasing revenues and the management fees do not constitute revenue from contracts with customers. Product sales in our Consolidated Statement of Operations include amounts associated with our derivative contracts that are not within the scope of ASC 606.

Revenue Recognition Contract As

Revenue Recognition Contract Assets (Details) $ in Millions	12 Months Ended
	Dec. 31, 2018USD ($)
Revenue Recognition [Abstract]
Contract with Customer, Asset, Net - Beginning of Period	$ 4
Contract with Customer Asset Amounts Recognized In Excess Of Cash Received	66
Contract With Customer Asset Minimum Volume Commitments Invoiced	(66)
Contract with Customer, Asset, Net - End of Period	$ 4

Revenue Recognition Contract Li

Revenue Recognition Contract Liabilities (Details) $ in Millions	12 Months Ended
	Dec. 31, 2018USD ($)
Contract with Customer, Liability [Line Items]
Contract with Customer, Liability - Beginning of Period	$ 1,596
Contract With Customer Liability Payments Received and Deferred	314
ContractLiabilityNoncashInterestExpenseSignificantFinancingObligation	16
Variable Interest Entity Nonconsolidated Contract Liability 1	(26)
Contract with Customer, Liability, Revenue Recognized	(451)
Contract with Customer, Liability - End of Period	1,397
Jackalope Gas Gathering Services LLC [Member]
Contract with Customer, Liability [Line Items]
Variable Interest Entity Nonconsolidated Contract Liability 1	$ (52)

Revenue Recognition Contract _2

Revenue Recognition Contract Liabilities Performance Obligations (Details) - Performance Obligations Related To Contract Liabilities [Member] $ in Millions	Dec. 31, 2018USD ($)
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2018-10-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2019-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, Remaining Performance Obligation, Amount	$ 271
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2020-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, Remaining Performance Obligation, Amount	$ 142
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2021-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, Remaining Performance Obligation, Amount	$ 121
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2022-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, Remaining Performance Obligation, Amount	$ 102
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2023-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, Remaining Performance Obligation, Amount	$ 95
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2024-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, Remaining Performance Obligation, Amount	$ 666
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: (nil)
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, Remaining Performance Obligation, Amount	$ 1,397

Revenue Recognition Remaining P

Revenue Recognition Remaining Performance Obligations (Details) - Remaining Performance Obligations [Member] $ in Millions	Dec. 31, 2018USD ($)
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2018-10-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2019-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, Remaining Performance Obligation, Amount	$ 2,909
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2020-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, Remaining Performance Obligation, Amount	$ 2,728
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2021-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, Remaining Performance Obligation, Amount	$ 2,622
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2022-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, Remaining Performance Obligation, Amount	$ 2,262
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2023-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, Remaining Performance Obligation, Amount	$ 2,089
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2024-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, Remaining Performance Obligation, Amount	$ 16,916
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: (nil)
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, Remaining Performance Obligation, Amount	$ 29,526

Revenue Recognition Accounts Re

Revenue Recognition Accounts Receivable (Details) - USD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
Accounts, Notes, Loans and Financing Receivable [Line Items]
Trade accounts and other receivables	$ 992	$ 976
Accounts Receivable Related To Contracts With Customers [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Trade accounts and other receivables	858	958
Other Accounts Receivable [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Trade accounts and other receivables	$ 134	$ 18

Revenue Recognition Impact of A

Revenue Recognition Impact of Adoption of ASC 606 (Details) - USD ($) $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Revenue, Initial Application Period Cumulative Effect Transition [Line Items]
Service revenues	$ 8,604
Sales revenue services commodity consideration	400	$ 0	$ 0
Total revenues	8,686	8,031	7,499
Processing commodity expenses	137	0	0
Operating and maintenance expenses	1,507	1,576	1,592
Depreciation and amortization	1,725	1,736	1,763
Other Asset Impairment Charges	1,915	1,248	873
Costs and Expenses	7,918	7,104	6,810
Operating Income (Loss)	768	927	689
Income (Loss) from Equity Method Investments	396	434	397
Other investing income (loss) – net	219	282	63
Interest incurred	(1,160)	(1,116)	(1,217)
Interest capitalized	48	33	38
Income (loss) before income taxes	331	535	(375)
Provision (benefit) for income taxes	138	(1,974)	(25)
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest	193	2,509	(350)
Net Income (Loss) Attributable to Noncontrolling Interest	348	335	74
Net income (loss) attributable to The Williams Companies, Inc.	$ (155)	$ 2,174	$ (424)
Net income (loss)	$ (0.16)	$ 2.63	$ (0.57)
Net income (loss)	$ (0.16)	$ 2.62	$ (0.57)
Comprehensive Income (Loss), Net of Tax, Including Portion Attributable to Noncontrolling Interest	$ 223	$ 2,609	$ (178)
Comprehensive Income (Loss), Net of Tax, Attributable to Noncontrolling Interest	346	334	143
Comprehensive Income (Loss), Net of Tax, Attributable to Parent	(123)	2,275	(321)
Inventory, Net	130	113
Other current assets and deferred charges	174	191
Assets, Current	1,464	2,179
Investments	7,821	6,552
Property, Plant and Equipment, Net	27,504	28,211
Intangible assets – net of accumulated amortization	7,767	8,791
Other Assets, Noncurrent	746	619
Total assets	45,302	46,352
Accrued Liabilities, Current	1,102	1,167
Liabilities, Current	1,811	2,646
Deferred income tax liabilities	1,524	3,147
Other Liabilities and Deferred Revenue, Noncurrent	3,603	3,950
Retained Earnings (Accumulated Deficit)	(10,002)	(8,434)
Stockholders' Equity Attributable to Parent	14,660	9,656
Stockholders' Equity Attributable to Noncontrolling Interest	1,337	6,519
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest	15,997	16,175	14,046	$ 16,225
Total liabilities and equity	45,302	46,352
New Accounting Pronouncement or Change in Accounting Principle, Effect of Adoption, Quantification	(121)	37
Noncontrolling Interest, Decrease from Deconsolidation	(267)
Stockholders' Equity, Period Increase (Decrease)	(178)	2,129	(2,179)
Difference between Revenue Guidance in Effect before and after Topic 606 [Member] | Accounting Standards Update 2014-09 [Member]
Revenue, Initial Application Period Cumulative Effect Transition [Line Items]
Sales revenue services commodity consideration	(400)
Total revenues	(176)
Processing commodity expenses	(137)
Operating and maintenance expenses	1
Depreciation and amortization	2
Other Asset Impairment Charges	202
Costs and Expenses	(56)
Operating Income (Loss)	(120)
Income (Loss) from Equity Method Investments	1
Other investing income (loss) – net	84
Interest incurred	16
Interest capitalized	(10)
Income (loss) before income taxes	(29)
Provision (benefit) for income taxes	(9)
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest	(20)
Net Income (Loss) Attributable to Noncontrolling Interest	(1)
Net income (loss) attributable to The Williams Companies, Inc.	$ (19)
Net income (loss)	$ (0.02)
Net income (loss)	$ (0.02)
Comprehensive Income (Loss), Net of Tax, Including Portion Attributable to Noncontrolling Interest	$ (20)
Comprehensive Income (Loss), Net of Tax, Attributable to Noncontrolling Interest	(1)
Comprehensive Income (Loss), Net of Tax, Attributable to Parent	(19)
Inventory, Net	(13)
Assets, Current	(13)
Investments	1
Property, Plant and Equipment, Net	(212)
Intangible assets – net of accumulated amortization	61
Other Assets, Noncurrent	(4)
Total assets	(167)
Accrued Liabilities, Current	67
Liabilities, Current	67
Deferred income tax liabilities	20
Other Liabilities and Deferred Revenue, Noncurrent	(346)
Retained Earnings (Accumulated Deficit)	64
Stockholders' Equity Attributable to Parent	64
Stockholders' Equity Attributable to Noncontrolling Interest	28
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest	92
Total liabilities and equity	(167)
New Accounting Pronouncement or Change in Accounting Principle, Effect of Adoption, Quantification	121
Noncontrolling Interest, Decrease from Deconsolidation	(9)
Stockholders' Equity, Period Increase (Decrease)	92
Calculated under Revenue Guidance in Effect before Topic 606 [Member] | Accounting Standards Update 2014-09 [Member]
Revenue, Initial Application Period Cumulative Effect Transition [Line Items]
Sales revenue services commodity consideration	0
Total revenues	8,510
Processing commodity expenses	0
Operating and maintenance expenses	1,508
Depreciation and amortization	1,727
Other Asset Impairment Charges	2,117
Costs and Expenses	7,862
Operating Income (Loss)	648
Income (Loss) from Equity Method Investments	397
Other investing income (loss) – net	303
Interest incurred	(1,144)
Interest capitalized	38
Income (loss) before income taxes	302
Provision (benefit) for income taxes	129
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest	173
Net Income (Loss) Attributable to Noncontrolling Interest	347
Net income (loss) attributable to The Williams Companies, Inc.	$ (174)
Net income (loss)	$ (0.18)
Net income (loss)	$ (0.18)
Comprehensive Income (Loss), Net of Tax, Including Portion Attributable to Noncontrolling Interest	$ 203
Comprehensive Income (Loss), Net of Tax, Attributable to Noncontrolling Interest	345
Comprehensive Income (Loss), Net of Tax, Attributable to Parent	(142)
Inventory, Net	117
Assets, Current	1,451
Investments	7,822
Property, Plant and Equipment, Net	27,292
Intangible assets – net of accumulated amortization	7,828
Other Assets, Noncurrent	742
Total assets	45,135
Accrued Liabilities, Current	1,169
Liabilities, Current	1,878
Deferred income tax liabilities	1,544
Other Liabilities and Deferred Revenue, Noncurrent	3,257
Retained Earnings (Accumulated Deficit)	(9,938)
Stockholders' Equity Attributable to Parent	14,724
Stockholders' Equity Attributable to Noncontrolling Interest	1,365
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest	16,089
Total liabilities and equity	45,135
New Accounting Pronouncement or Change in Accounting Principle, Effect of Adoption, Quantification	0
Noncontrolling Interest, Decrease from Deconsolidation	(276)
Stockholders' Equity, Period Increase (Decrease)	(86)
Service [Member]
Revenue, Initial Application Period Cumulative Effect Transition [Line Items]
Service revenues	5,502	5,312	5,171
Service [Member] | Difference between Revenue Guidance in Effect before and after Topic 606 [Member] | Accounting Standards Update 2014-09 [Member]
Revenue, Initial Application Period Cumulative Effect Transition [Line Items]
Service revenues	89
Service [Member] | Calculated under Revenue Guidance in Effect before Topic 606 [Member] | Accounting Standards Update 2014-09 [Member]
Revenue, Initial Application Period Cumulative Effect Transition [Line Items]
Service revenues	5,591
Product [Member]
Revenue, Initial Application Period Cumulative Effect Transition [Line Items]
Service revenues	2,784	2,719	2,328
Product [Member] | Difference between Revenue Guidance in Effect before and after Topic 606 [Member] | Accounting Standards Update 2014-09 [Member]
Revenue, Initial Application Period Cumulative Effect Transition [Line Items]
Service revenues	135
Product [Member] | Calculated under Revenue Guidance in Effect before Topic 606 [Member] | Accounting Standards Update 2014-09 [Member]
Revenue, Initial Application Period Cumulative Effect Transition [Line Items]
Service revenues	2,919
Oil and Gas, Purchased [Member]
Revenue, Initial Application Period Cumulative Effect Transition [Line Items]
Product costs	2,707	$ 2,300	$ 1,725
Oil and Gas, Purchased [Member] | Difference between Revenue Guidance in Effect before and after Topic 606 [Member] | Accounting Standards Update 2014-09 [Member]
Revenue, Initial Application Period Cumulative Effect Transition [Line Items]
Product costs	(124)
Oil and Gas, Purchased [Member] | Calculated under Revenue Guidance in Effect before Topic 606 [Member] | Accounting Standards Update 2014-09 [Member]
Revenue, Initial Application Period Cumulative Effect Transition [Line Items]
Product costs	$ 2,583

Divestitures (Details)

Divestitures (Details) - USD ($) $ in Millions

Jul. 06, 2017

Dec. 31, 2018

Jun. 30, 2018

Sep. 30, 2017

Jun. 30, 2017

Sep. 30, 2016

Jun. 30, 2016

Dec. 31, 2018

Dec. 31, 2017

Dec. 31, 2016

Nov. 30, 2018

Oct. 01, 2018

Oct. 26, 2017

Income (Loss) from Individually Significant Component Disposed of, Attributable to Parent, before Income Tax [Abstract]

Gain on sale of certain assets

$ 692

$ 1,095

$ 0

Impairment Of Certain Assets [Member]

Income (Loss) from Individually Significant Component Disposed of, Attributable to Parent, before Income Tax [Abstract]

Tangible Asset Impairment Charges

873

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

Income (Loss) from Individually Significant Component Disposed of, Attributable to Parent, before Income Tax [Abstract]

Tangible Asset Impairment Charges

[1]

0

23

70

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

Income (Loss) from Individually Significant Component Disposed of, Attributable to Parent, before Income Tax [Abstract]

Tangible Asset Impairment Charges

803

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

Income (Loss) from Individually Significant Component Disposed of, Attributable to Parent, before Income Tax [Abstract]

Tangible Asset Impairment Charges

[2]

$ 48

Gulf Coast Pipeline Systems [Member]

Income Statement and Additional Disclosures by Disposal Groups [Line Items]

Disposal Group, Consideration

$ 177

Income (Loss) from Individually Significant Component Disposed of, Attributable to Parent, before Income Tax [Abstract]

Gain on sale of certain assets

$ 101

Gulf Coast Pipeline Systems [Member] | Atlantic Gulf [Member]

Income (Loss) from Individually Significant Component Disposed of, Attributable to Parent, before Income Tax [Abstract]

Gain on sale of certain assets

81

Gulf Coast Pipeline Systems [Member] | Other [Member]

Income (Loss) from Individually Significant Component Disposed of, Attributable to Parent, before Income Tax [Abstract]

Gain on sale of certain assets

20

Gulf Coast Pipeline Systems [Member] | Disposal Group, Not Discontinued Operations [Member] | Impairment Of Certain Assets [Member] | Fair Value, Measurements, Nonrecurring [Member] | Fair Value, Inputs, Level 2 [Member]

Income (Loss) from Individually Significant Component Disposed of, Attributable to Parent, before Income Tax [Abstract]

Tangible Asset Impairment Charges

$ 66

Gulf Coast Pipeline Systems [Member] | Disposal Group, Not Discontinued Operations [Member] | Impairment Of Certain Assets [Member] | Fair Value, Measurements, Nonrecurring [Member] | Level 3 [Member]

Income (Loss) from Individually Significant Component Disposed of, Attributable to Parent, before Income Tax [Abstract]

Tangible Asset Impairment Charges

$ 68

$ 23

Four Corners [Member] | West [Member]

Income Statement and Additional Disclosures by Disposal Groups [Line Items]

Disposal Group, Consideration

$ 1,125

Income (Loss) from Individually Significant Component Disposed of, Attributable to Parent, before Income Tax [Abstract]

Income (Loss) before Income Taxes of Disposal Group

(52)

(47)

(37)

Income (Loss) before Income Taxes of Disposal Group Attributable to the Williams Companies, Inc.

(43)

(35)

(23)

Gain on sale of certain assets

$ 591

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

0

(26)

(141)

Income (Loss) before Income Taxes of Disposal Group Attributable to the Williams Companies, Inc.

$ 0

$ (19)

(85)

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

Income (Loss) from Individually Significant Component Disposed of, Attributable to Parent, before Income Tax [Abstract]

Income (Loss) before Income Taxes of Disposal Group

98

Income (Loss) before Income Taxes of Disposal Group Attributable to the Williams Companies, Inc.

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 3)

66

Gain (Loss) on Foreign Currency Derivative Instruments Not Designated as Hedging Instruments

15

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

Variable Interest Term Loan due 2018 [Member] | Williams Olefins, L.L.C. [Member]

Income (Loss) from Individually Significant Component Disposed of, Attributable to Parent, before Income Tax [Abstract]

Extinguishment of Debt, Amount

$ 850

[1]

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.

[2]

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.

Variable Interest Entities (Det

Variable Interest Entities (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	[1]
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	$ 33	$ 881
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	62	972
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	0	113
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	2	176
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	0	6,552
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	2,363	27,912
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	1,177	8,790
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	0	507
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	(15)	(957)
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	(115)	(857)
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	0	(501)
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	0	(15,996)
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	0	(16)
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	(105)	(944)
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	(159)	(1,119)
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	$ 0	$ (1,690)
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	$ 377
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, Not Primary Beneficiary [Member] | Jackalope Gas Gathering Services LLC [Member]
Variable Interest Entity [Line Items]
Variable Interest Entity Ownership Percentage	50.00%
Variable Interest Entity, Not Primary Beneficiary [Member] | Jackalope Gas Gathering Services LLC [Member] | Investments [Domain]
Variable Interest Entity [Line Items]
Variable Interest Entity, Nonconsolidated, Carrying Amount, Assets and Liabilities, Net	$ 343
Variable Interest Entity, Not Primary Beneficiary [Member] | Jackalope Gas Gathering Services LLC [Member] | Estimated Remaining Construction Costs For Variable Interest Entity [Member]
Variable Interest Entity [Line Items]
Estimated remaining construction costs	$ 350
Variable Interest Entity, Not Primary Beneficiary [Member] | Brazos Permian II, LLC [Member]
Variable Interest Entity [Line Items]
Variable Interest Entity Ownership Percentage	15.00%
Variable Interest Entity, Not Primary Beneficiary [Member] | Brazos Permian II, LLC [Member] | Investments [Domain]
Variable Interest Entity [Line Items]
Variable Interest Entity, Nonconsolidated, Carrying Amount, Assets and Liabilities, Net	$ 191
[1]	Includes WPZ, which was a consolidated VIE at December 31, 2017 (see Note 1 – General, Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies).

Related Party Transactions (Det

Related Party Transactions (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Related Party Transaction [Line Items]
Service revenues	$ 8,604
Equity Method Investee [Member]
Related Party Transaction [Line Items]
Product costs	236	$ 226	$ 180
Accounts payable	18	20
Common Management Transaction [Member]
Related Party Transaction [Line Items]
Service revenues			144
Management Service [Member] | Equity Method Investee [Member]
Related Party Transaction [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	$ 75	$ 67	$ 66

Investing Activities (Details)

Investing Activities (Details) - USD ($) $ in Millions		3 Months Ended	12 Months Ended
		Jun. 30, 2018	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Dec. 15, 2018	Sep. 30, 2018	Mar. 31, 2017
Schedule of Investments [Line Items]
Impairment of equity-method investments (Note 17)			$ 32	$ 0	$ 430
Equity earnings (losses)			396	434	397
Investment income, nonoperating			219	282	63
Gain on sale of equity-method investment			0	269	27
Equity-method investments			7,821	6,552
Gain on deconsolidation of businesses (Note 6)			203	0	0
Proceeds from dispositions of equity-method investments			0	200	34
Equity-method investment, difference between carrying amount and underlying equity			1,800	1,800
Equity-method investment, payments to purchase or contributions			1,132	132	177
Distributions from unconsolidated affiliates			693	784	742
Summarized Financial Position of Equity Method Investments
Current assets			834	447
Noncurrent assets			13,199	9,181
Current liabilities			(605)	(295)
Noncurrent liabilities			(2,491)	(1,538)
Summarized Results of Operations of Equity Method Investments
Gross revenue			2,411	1,961	1,883
Operating income			804	871	799
Net income			795	806	726
Rocky Mountain Midstream Holdings LLC [Member]
Schedule of Investments [Line Items]
Equity-method investments			$ 776	0
Equity-method investment, ownership percentage			50.00%					40.00%
Equity-method investment, payments to purchase or contributions			$ 795	0	0
Jackalope Gas Gathering Services LLC [Member]
Schedule of Investments [Line Items]
Equity-method investments			$ 343	0
Equity-method investment, ownership percentage			50.00%
Equity-method investment, payments to purchase or contributions			$ 42	0	0
Caiman Energy II [Member]
Schedule of Investments [Line Items]
Equity-method investments			$ 412	429
Equity-method investment, ownership percentage			58.00%
Equity-method investment, payments to purchase or contributions			$ 0	24	22
Distributions from unconsolidated affiliates			46	49	40
Delaware Basin Gas Gathering System [Member]
Schedule of Investments [Line Items]
Equity-method investment, payments to purchase or contributions			0	32	105
Distributions from unconsolidated affiliates			0	39	39
Appalachia Midstream Investments [Member]
Schedule of Investments [Line Items]
Gain on sale of equity-method investment					27
Equity-method investments	[1]		$ 3,218	3,104
Equity-method investment, ownership percentage			66.00%
Equity-method investment, payments to purchase or contributions			$ 246	70	28
Distributions from unconsolidated affiliates			297	270	211
Utica East Ohio Midstream, LLC [Member]
Schedule of Investments [Line Items]
Equity-method investments			$ 1,293	1,383
Equity-method investment, ownership percentage			62.00%
Distributions from unconsolidated affiliates			$ 70	80	92
Discovery Producer Services LLC [Member]
Schedule of Investments [Line Items]
Equity-method investments			$ 507	534
Equity-method investment, ownership percentage			60.00%
Equity-method investment, payments to purchase or contributions			$ 5	1	0
Distributions from unconsolidated affiliates			45	127	141
Laurel Mountain Midstream, LLC [Member]
Schedule of Investments [Line Items]
Equity-method investments			$ 314	309
Equity-method investment, ownership percentage			69.00%
Equity-method investment, payments to purchase or contributions			$ 16	0	0
Distributions from unconsolidated affiliates			23	32	28
Overland Pass Pipeline Company LLC [Member]
Schedule of Investments [Line Items]
Equity-method investments			$ 415	422
Equity-method investment, ownership percentage			50.00%
Distributions from unconsolidated affiliates			$ 73	68	69
Gulfstream Natural Gas System, L.L.C.[Member]
Schedule of Investments [Line Items]
Equity-method investments			$ 225	244
Equity-method investment, ownership percentage			50.00%
Distributions from unconsolidated affiliates			$ 93	92	100
Special distribution from equity-method investment						$ 396
Contribution to equity-method investment for repayment of debt					148	248
Brazos Permian II, LLC [Member]
Schedule of Investments [Line Items]
Equity-method investments			$ 191	0
Equity-method investment, ownership percentage			15.00%
Equity-method investment, payments to purchase or contributions			$ 27	0	0
Other [Member]
Schedule of Investments [Line Items]
Equity-method investments			127	127
Equity-method investment, payments to purchase or contributions			1	5	22
Distributions from unconsolidated affiliates			46	27	22
Former Venezuela Operations [Member]
Schedule of Investments [Line Items]
Investment income, nonoperating					36
Total Equity Method Investment [Member]
Schedule of Investments [Line Items]
Distributions from unconsolidated affiliates			$ 693	784	742
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
Northeast G And P [Member] | Caiman Energy II [Member]
Schedule of Investments [Line Items]
Equity-method investment, ownership percentage			58.00%
Northeast G And P [Member] | Appalachia Midstream Services, LLC [Member]
Schedule of Investments [Line Items]
Equity-method investment, ownership percentage			66.00%
Northeast G And P [Member] | Appalachia Midstream Investments [Member]
Schedule of Investments [Line Items]
Impairment of equity-method investments (Note 17)			$ 0	0	294
Northeast G And P [Member] | Utica East Ohio Midstream, LLC [Member]
Schedule of Investments [Line Items]
Impairment of equity-method investments (Note 17)			$ 32	0	0
Equity-method investment, ownership percentage			62.00%
Northeast G And P [Member] | Laurel Mountain Midstream, LLC [Member]
Schedule of Investments [Line Items]
Impairment of equity-method investments (Note 17)			$ 0	0	50
Equity-method investment, ownership percentage			69.00%
West [Member] | Rocky Mountain Midstream Holdings LLC [Member]
Schedule of Investments [Line Items]
Equity-method investment, ownership percentage			50.00%
West [Member] | Jackalope Gas Gathering Services LLC [Member]
Schedule of Investments [Line Items]
Goodwill, Period Increase (Decrease)		$ 47
Equity-method investment, ownership percentage			50.00%
Gain on deconsolidation of businesses (Note 6)			$ 62
West [Member] | Delaware Basin Gas Gathering System [Member]
Schedule of Investments [Line Items]
Impairment of equity-method investments (Note 17)			$ 0	0	59
Gain on sale of equity-method investment				269
Equity-method investment, ownership percentage									50.00%
Proceeds from dispositions of equity-method investments				155
West [Member] | Overland Pass Pipeline Company LLC [Member]
Schedule of Investments [Line Items]
Equity-method investment, ownership percentage			50.00%
West [Member] | Brazos Permian II, LLC [Member]
Schedule of Investments [Line Items]
Equity-method investment, ownership percentage			15.00%
Gain on deconsolidation of businesses (Note 6)			$ 141
West [Member] | Ranch Westex JV LLC [Member]
Schedule of Investments [Line Items]
Impairment of equity-method investments (Note 17)			0	0	24
Proceeds from dispositions of equity-method investments				45
Corporate and Other [Member] | Other [Member]
Schedule of Investments [Line Items]
Impairment of equity-method investments (Note 17)			$ 0	$ 0	$ 3
Brazos Permian II, LLC [Member] | West [Member]
Schedule of Investments [Line Items]
Investments, Fair Value Disclosure							$ 192
Jackalope Gas Gathering Services LLC [Member] | West [Member]
Schedule of Investments [Line Items]
Investments, Fair Value Disclosure		$ 310
Appalachia Midstream Services, LLC [Member] | Northeast G And P [Member]
Schedule of Investments [Line Items]
Investments, Fair Value Disclosure									$ 1,100
Measurement Input, Discount Rate [Member] | Jackalope Gas Gathering Services LLC [Member] | West [Member]
Schedule of Investments [Line Items]
Property Plant And Equipment And Intangibles Fair Value Inputs		10.90%
Measurement Input, Discount Rate [Member] | Appalachia Midstream Services, LLC [Member] | Northeast G And P [Member]
Schedule of Investments [Line Items]
Property Plant And Equipment And Intangibles Fair Value Inputs									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		Mar. 28, 2018	Jul. 03, 2017	Feb. 23, 2017	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Segment Reporting Information [Line Items]
Gains on asset retirements	[1]				$ 39	$ 22
Regulatory Charges In Operating Expense Resulting From Tax Reform					(17)	674	$ 0
Gain on sale of Refinery Grade Propylene Splitter					692	1,095	0
Service revenues					8,604
Regulatory charges resulting from Tax Reform (Note 1)					(15)	776	0
Repayments of Long-term Debt					3,204	5,925	7,091
Debt Instrument, Unamortized Discount (Premium), Net		$ 7	$ 3	$ 30	62	24
Unamortized Loan Commitment and Origination Fees and Unamortized Discounts or Premiums		27
Debt Instrument, Unamortized Premium		$ 34
Atlantic Gulf [Member]
Segment Reporting Information [Line Items]
Litigation Settlement, Amount Awarded to Other Party							15
Other income (expense) - net [Member] | Atlantic Gulf [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	22	25
Project development costs					4	16	28
Gains on asset retirements					(12)	0	(11)
Other income (expense) - net [Member] | West [Member]
Segment Reporting Information [Line Items]
Gains on contract settlements and terminations					0	(15)	0
Regulatory Charges In Operating Expense Resulting From Tax Reform					24	0	0
Other income (expense) - net [Member] | Corporate and Other [Member]
Segment Reporting Information [Line Items]
Gain on sale of Refinery Grade Propylene Splitter					0	(12)	0
Net foreign currency exchange (gains) losses (1)	[2]				0	0	10
Gain on sale of unused pipe					0	0	(10)
Regulatory Benefit Resulting From Tax Rate Change					(37)	0	0
Selling, general and administrative expenses [Member] | Corporate and Other [Member]
Segment Reporting Information [Line Items]
Project development costs							61
Noncash Contribution Expense					35
WPZ Merger					20
Selling, general and administrative expenses [Member] | Corporate and Other [Member] | Acquisition and Merger [Member]
Segment Reporting Information [Line Items]
Restructuring Charges						9	47
Service revenues [Member]
Segment Reporting Information [Line Items]
Deferred Revenue, Revenue Recognized							173
Selling, general, and administrative expenses and Operating and maintenance expenses [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%
Selling, general, and administrative expenses and Operating and maintenance expenses [Member] | Northeast G And P [Member]
Segment Reporting Information [Line Items]
Severance and other related costs							$ 3
Selling, general, and administrative expenses and Operating and maintenance expenses [Member] | Atlantic Gulf [Member]
Segment Reporting Information [Line Items]
Severance and other related costs							8
Selling, general, and administrative expenses and Operating and maintenance expenses [Member] | West [Member]
Segment Reporting Information [Line Items]
Severance and other related costs							13
Selling, general, and administrative expenses and Operating and maintenance expenses [Member] | Corporate and Other [Member]
Segment Reporting Information [Line Items]
Severance and other related costs							18
Other income (expense) - net [Member]
Segment Reporting Information [Line Items]
Regulatory charges resulting from Tax Reform (Note 1)						102
Other income (expense) - net [Member] | Atlantic Gulf [Member]
Segment Reporting Information [Line Items]
Allowance for funds used during construction, capitalized cost of equity					89	71	66
Regulatory charges resulting from Tax Reform (Note 1)						33
Other income (expense) - net [Member] | West [Member]
Segment Reporting Information [Line Items]
Regulatory charges resulting from Tax Reform (Note 1)						6
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					35	52	23
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 3)							66
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 3)					0	5	66
Pension Plan [Member]
Segment Reporting Information [Line Items]
Defined Benefit Plan, Net Periodic Benefit Cost (Credit), Gain (Loss) Due to Settlement					(23)	(71)	(2)
Pension Plan [Member] | Other income (expense) - net [Member] | Northeast G And P [Member]
Segment Reporting Information [Line Items]
Defined Benefit Plan, Net Periodic Benefit Cost (Credit), Gain (Loss) Due to Settlement					4	7
Pension Plan [Member] | Other income (expense) - net [Member] | Atlantic Gulf [Member]
Segment Reporting Information [Line Items]
Defined Benefit Plan, Net Periodic Benefit Cost (Credit), Gain (Loss) Due to Settlement					7	15
Pension Plan [Member] | Other income (expense) - net [Member] | West [Member]
Segment Reporting Information [Line Items]
Defined Benefit Plan, Net Periodic Benefit Cost (Credit), Gain (Loss) Due to Settlement					6	13
Pension Plan [Member] | Other income (expense) - net [Member] | Corporate and Other [Member]
Segment Reporting Information [Line Items]
Defined Benefit Plan, Net Periodic Benefit Cost (Credit), Gain (Loss) Due to Settlement					5	35
Pension Plan [Member] | Other income (expense) - net [Member]
Segment Reporting Information [Line Items]
Defined Benefit Plan, Net Periodic Benefit Cost (Credit), Gain (Loss) Due to Settlement					(23)	(71)
Northwest Pipeline LLC [Member] | Other income (expense) - net [Member] | West [Member]
Segment Reporting Information [Line Items]
Regulatory charge resulting from tax rate change					$ 12	$ 0	$ 0
4.875% Senior Unsecured Notes due 2024 [Member]
Segment Reporting Information [Line Items]
Debt Instrument, Interest Rate, Stated Percentage		4.875%
Extinguishment of Debt, Amount		$ 750
6.125% Senior Unsecured Notes due 2022 [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]
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 2018 revisions reflect changes in removal cost estimates, decreases in the estimated remaining useful life of certain assets and increases in the discount rates used in the annual review process. The 2017 revisions reflect changes in removal cost estimates and decreases in the estimated remaining useful life of certain assets and discount rates used in the annual review process.
[2]	____________(1)Primarily relates to gains and losses incurred on foreign currency transactions and the remeasurement of U.S. dollar-denominated current assets and liabilities within our former Canadian operations (see Note 3 – Divestitures).

Provision (Benefit) for Incom_3

Provision (Benefit) for Income Taxes Tax Provison (Benefit) Table (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Current :
Federal	$ (83)	$ 15	$ 0
State	1	23	2
Foreign	0	0	(1)
Total	(82)	38	1
Deferred:
Federal	183	(2,004)	(6)
State	37	(8)	61
Foreign	0	0	(81)
Total	220	(2,012)	(26)
Provision (benefit) for income taxes	$ 138	$ (1,974)	$ (25)

Provision (Benefit) for Incom_4

Provision (Benefit) for Income Taxes Reconciliations to Recorded Tax Provision (Benefit) Table (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Effective Income Tax Rate Reconciliation [Abstract]
Provision (benefit) at statutory rate	$ 69	$ 187	$ (131)
Increases (decreases) in taxes resulting from:
Impact of nontaxable noncontrolling interests	(73)	(117)	(22)
Federal Tax Reform rate change	0	(1,932)	0
State income taxes (net of federal benefit)	(10)	(17)	3
State deferred income tax rate change	38	26	43
Foreign operations – net (including tax effect of Canadian Sale)	0	(127)	78
Valuation allowance	105	0	0
Translation adjustment of certain unrecognized tax benefits	0	0	(1)
Other – net	9	6	5
Provision (benefit) for income taxes	$ 138	$ (1,974)	$ (25)

Provision (Benefit) for Incom_5

Provision (Benefit) for Income Taxes Deferred Tax Table (Details) - USD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
Deferred income tax liabilities:
Property, plant and equipment	$ 2,317	$ 0
Investments	295	3,565
Other	30	19
Total deferred income tax liabilities	2,642	3,584
Deferred income tax assets:
Accrued liabilities	667	53
Minimum tax credit	71	155
Foreign tax credit	140	140
Federal loss carryovers	147	0
State losses and credits	319	283
Other	94	30
Total deferred income tax assets	1,438	661
Less valuation allowance	320	224
Net deferred income tax assets	1,118	437
Overall net deferred income tax liabilities	$ 1,524	$ 3,147

Provision (Benefit) for Incom_6

Provision (Benefit) for Income Taxes Reconciliation of Unrecognized Tax Benefits Table (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward]
Balance at beginning of period	$ 50	$ 50
Additions for tax positions of prior years	1	0
Balance at end of period	$ 51	$ 50

Provision (Benefit) for Incom_7

Provision (Benefit) for Income Taxes Textuals (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016	Aug. 10, 2018
Income Tax Contingency [Line Items]
Tax Credit Carryforward, Valuation Allowance	$ 105,000
Deferred Tax Liabilities, Net, Noncurrent	(1,524,000)	$ (3,147,000)
Foreign income (loss) in Income from continuing operations before income taxes	(3,000)	(7,000)	$ (885,000)
Minimum tax credit	71,000	155,000
Valuation Allowance, Deferred Tax Asset, Increase (Decrease), Amount	31,000
Income Taxes Paid, Net	11,000	28,000	5,000
Unrecognized tax benefits	51,000	50,000	50,000
Unrecognized Tax Benefits that Would Impact Effective Tax Rate	51,000	50,000
Total interest and penalties recognized as part of income tax provision	800	(400)	$ 300
Total interest and penalties accrued as uncertain tax positions	3,000	$ 2,000
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%
Internal Revenue Service (IRS) [Member] | Expiration2019to2023 [Member]
Income Tax Contingency [Line Items]
Deferred Tax Assets, Tax Credit Carryforwards	5,000
Internal Revenue Service (IRS) [Member] | ExpirationNone [Member]
Income Tax Contingency [Line Items]
Deferred Tax Assets, Tax Credit Carryforwards	$ 142,000
WPZ Merger Public Unit Exchange [Member]
Income Tax Contingency [Line Items]
Deferred Tax Liabilities, Net, Noncurrent				$ 1,829,000

Earnings (Loss) Per Common Sh_3

Earnings (Loss) Per Common Share (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Millions	12 Months Ended
	Dec. 31, 2018		Dec. 31, 2017	Dec. 31, 2016
Earnings (loss) per common share
Net income (loss) available to common stockholders	$ (156)		$ 2,174	$ (424)
Basic weighted-average shares	973,626		826,177	750,673
Effect of dilutive securities:
Diluted weighted-average shares	973,626	[1]	828,518	750,673	[1]
Earnings (loss) per common share:
Basic	$ (0.16)		$ 2.63	$ (0.57)
Diluted	$ (0.16)		$ 2.62	$ (0.57)
Nonvested restricted stock units [Member]
Effect of dilutive securities:
Incremental common shares attributable to share-based payment arrangements under effects of dilutive securities item	0		1,704	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	2,000			600
Stock options [Member]
Effect of dilutive securities:
Incremental common shares attributable to share-based payment arrangements under effects of dilutive securities item	0		637	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			500
[1]	For the years ended December 31, 2018 and December 31, 2016, 2.0 million and 0.6 million weighted-average nonvested restricted stock units, respectively, and 0.5 million and 0.5 million weighted-average stock options, respectively, have been excluded from the computation of diluted earnings (loss) per common share as their inclusion would be antidilutive due to our loss attributable to The Williams Companies, Inc.

EBPs Obligation Rollforward (De

EBPs Obligation Rollforward (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Pension Benefits [Member]
Change in benefit obligation:
Benefit obligation at beginning of year	$ 1,319	$ 1,466
Service cost	50	50	$ 54
Interest cost	46	59	62
Plan participants’ contributions	0	0
Benefits paid	(35)	(35)
Net actuarial loss (gain)	(90)	40
Settlements	(103)	(261)
Net increase (decrease) in benefit obligation	(132)	(147)
Benefit obligation at end of year	1,187	1,319	1,466
Other Postretirement Benefits [Member]
Change in benefit obligation:
Benefit obligation at beginning of year	206	197
Service cost	1	1	1
Interest cost	7	8	8
Plan participants’ contributions	2	3
Benefits paid	(13)	(14)
Net actuarial loss (gain)	(17)	11
Settlements	0	0
Net increase (decrease) in benefit obligation	(20)	9
Benefit obligation at end of year	$ 186	$ 206	$ 197

EBP Asset rollforward and B.S.

EBP Asset rollforward and B.S. classification (Details 1) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Pension Benefits [Member]
Change in plan assets:
Fair value of plan assets at beginning of year	$ 1,227	$ 1,254
Actual return on plan assets	(45)	184
Employer contributions	88	85
Plan participants’ contributions	0	0
Benefits paid	(35)	(35)
Settlements	(103)	(261)
Net increase (decrease) in fair value of plan assets	(95)	(27)
Fair value of plan assets at end of year	1,132	1,227
Funded status — overfunded (underfunded)	(55)	(92)
Accumulated benefit obligation	1,171	1,294
Overfunded/(underfunded) status of our pension plans and other postretirement benefit plans
Current liabilities	(2)	(2)
Noncurrent liabilities	(53)	(90)
Amounts included in Accumulated other comprehensive income (loss):
Net actuarial loss	(347)	(375)
Amounts included in regulatory liabilities associated with Transco and Northwest Pipeline:
Net regulatory liabilities	49	33
Accumulated benefit obligation for pension plans with accumulated benefit obligation in excess of plan assets	367
Plan assets for pension plans with accumulated benefit obligation in excess of plan assets	326
Other Postretirement Benefits [Member]
Change in plan assets:
Fair value of plan assets at beginning of year	227	208
Actual return on plan assets	(7)	25
Employer contributions	5	5
Plan participants’ contributions	2	3
Benefits paid	(13)	(14)
Settlements	0	0
Net increase (decrease) in fair value of plan assets	(13)	19
Fair value of plan assets at end of year	214	227
Funded status — overfunded (underfunded)	28	21
Overfunded/(underfunded) status of our pension plans and other postretirement benefit plans
Current liabilities	(6)	(6)
Noncurrent assets	34	27
Amounts included in Accumulated other comprehensive income (loss):
Net actuarial loss	(12)	(21)
Amounts included in regulatory liabilities associated with Transco and Northwest Pipeline:
Prior service credit	0	2
Net actuarial gain	4	14
Net regulatory liabilities	$ 116	$ 108

EBP Net Periodic Benefit Cost &

EBP Net Periodic Benefit Cost & OCI (Details 2) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Pension Benefits [Member]
Components of net periodic benefit cost (credit):
Service cost	$ 50	$ 50	$ 54
Interest cost	46	59	62
Expected return on plan assets	(63)	(82)	(85)
Amortization of prior service credit	0	0	0
Amortization of net actuarial loss	23	27	30
Net actuarial loss from settlements	23	71	2
Reclassification to regulatory liability	0	0	0
Net periodic benefit cost (credit)	79	125	63
Other changes in plan assets and benefit obligations recognized in Other comprehensive income (loss):
Net actuarial gain (loss)	(18)	62	(23)
Amortization of prior service credit	0	0	0
Amortization of net actuarial loss	23	27	30
Net actuarial loss from settlements	23	71	2
Other changes in plan assets and benefit obligations recognized in Other comprehensive income (loss)	28	160	9
Other Postretirement Benefits [Member]
Components of net periodic benefit cost (credit):
Service cost	1	1	1
Interest cost	7	8	8
Expected return on plan assets	(11)	(11)	(12)
Amortization of prior service credit	(2)	(13)	(15)
Amortization of net actuarial loss	0	0	0
Net actuarial loss from settlements	0	0	0
Reclassification to regulatory liability	2	3	4
Net periodic benefit cost (credit)	(3)	(12)	(14)
Other changes in plan assets and benefit obligations recognized in Other comprehensive income (loss):
Net actuarial gain (loss)	9	(3)	0
Amortization of prior service credit	0	(5)	(6)
Amortization of net actuarial loss	0	0	0
Net actuarial loss from settlements	0	0	0
Other changes in plan assets and benefit obligations recognized in Other comprehensive income (loss)	9	(8)	(6)
Other changes in plan assets and benefit obligations recognized in regulatory (assets) and liabilities:
Net actuarial gain (loss)	(10)	6	2
Amortization of prior service credit	(2)	(8)	$ (9)
Other Nonoperating Income (Expense) [Member] | Pension Benefits [Member]
Components of net periodic benefit cost (credit):
Net actuarial loss from settlements	$ 23	$ 71

EBP Key Assumptions (Details 3)

EBP Key Assumptions (Details 3)	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Pension Benefits [Member]
Weighted average assumptions utilized to determine benefit obligations
Discount rate	4.34%	3.66%
Rate of compensation increase	4.83%	4.93%
Cash balance interest crediting rate	4.25%	4.25%
Weighted average assumptions utilized to determine net periodic benefit cost (credit)
Discount rate	3.67%	4.17%	4.37%
Expected long-term rate of return on plan assets	5.34%	6.45%	6.85%
Rate of compensation increase	4.93%	4.87%	4.88%
Cash balance interest crediting rate	4.25%	4.25%	4.25%
Other Postretirement Benefits [Member]
Weighted average assumptions utilized to determine benefit obligations
Discount rate	4.39%	3.71%
Weighted average assumptions utilized to determine net periodic benefit cost (credit)
Discount rate	3.71%	4.27%	4.50%
Expected long-term rate of return on plan assets	4.95%	5.53%	6.11%
Health care cost trend rate assumed for next fiscal year	7.50%
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, 2018	Dec. 31, 2017	Dec. 31, 2016
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
Fair value, plan assets, Level 2 to Level 1 transfers, amount	$ 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	13 years	12 years
Pension Benefits [Member]
Fair values of plan assets
Total assets at fair value	$ 1,132	$ 1,227	$ 1,254
Pension Benefits [Member] | Equity Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Plan asset target allocation	25.00%
Pension Benefits [Member] | Fixed Income Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Plan asset target allocation	75.00%
Pension Benefits [Member] | Level 1 [Member]
Fair values of plan assets
Total assets at fair value	$ 219	236
Pension Benefits [Member] | Level 1 [Member] | Cash management fund
Fair values of plan assets
Total assets at fair value	10	17
Pension Benefits [Member] | Level 1 [Member] | Equity securities - U.S. large cap
Fair values of plan assets
Total assets at fair value	30	62
Pension Benefits [Member] | Level 1 [Member] | Equity securities - U.S. small cap
Fair values of plan assets
Total assets at fair value	22	54
Pension Benefits [Member] | Level 1 [Member] | Fixed income securities - U.S. Treasury securities
Fair values of plan assets
Total assets at fair value	157	103
Pension Benefits [Member] | Level 1 [Member] | Fixed income securities - Government and municipal bonds
Fair values of plan assets
Total assets at fair value	0	0
Pension Benefits [Member] | Level 1 [Member] | Fixed income securities - Mortgage and asset-backed securities
Fair values of plan assets
Total assets at fair value	0	0
Pension Benefits [Member] | Level 1 [Member] | Fixed income securities - Corporate bonds
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	285	225
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] | Equity securities - U.S. large cap
Fair values of plan assets
Total assets at fair value	0	0
Pension Benefits [Member] | Level 2 [Member] | Equity securities - U.S. small cap
Fair values of plan assets
Total assets at fair value	0	0
Pension Benefits [Member] | Level 2 [Member] | Fixed income securities - U.S. Treasury securities
Fair values of plan assets
Total assets at fair value	0	0
Pension Benefits [Member] | Level 2 [Member] | Fixed income securities - Government and municipal bonds
Fair values of plan assets
Total assets at fair value	21	15
Pension Benefits [Member] | Level 2 [Member] | Fixed income securities - Mortgage and asset-backed securities
Fair values of plan assets
Total assets at fair value	48	47
Pension Benefits [Member] | Level 2 [Member] | Fixed income securities - Corporate bonds
Fair values of plan assets
Total assets at fair value	210	158
Pension Benefits [Member] | Level 2 [Member] | Insurance company investment contracts and other
Fair values of plan assets
Total assets at fair value	6	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] | Equity securities - U.S. large cap
Fair values of plan assets
Total assets at fair value	0	0
Pension Benefits [Member] | Level 3 [Member] | Equity securities - U.S. small cap
Fair values of plan assets
Total assets at fair value	0	0
Pension Benefits [Member] | Level 3 [Member] | Fixed income securities - U.S. Treasury securities
Fair values of plan assets
Total assets at fair value	0	0
Pension Benefits [Member] | Level 3 [Member] | Fixed income securities - Government and municipal bonds
Fair values of plan assets
Total assets at fair value	0	0
Pension Benefits [Member] | Level 3 [Member] | Fixed income securities - Mortgage and asset-backed securities
Fair values of plan assets
Total assets at fair value	0	0
Pension Benefits [Member] | Level 3 [Member] | Fixed income securities - Corporate bonds
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
Pension Benefits [Member] | Fair Value, Inputs, Level 1, 2 and 3 [Member]
Fair values of plan assets
Total assets at fair value	504	461
Pension Benefits [Member] | Fair Value, Inputs, Level 1, 2 and 3 [Member] | Cash management fund
Fair values of plan assets
Total assets at fair value	10	17
Pension Benefits [Member] | Fair Value, Inputs, Level 1, 2 and 3 [Member] | Equity securities - U.S. large cap
Fair values of plan assets
Total assets at fair value	30	62
Pension Benefits [Member] | Fair Value, Inputs, Level 1, 2 and 3 [Member] | Equity securities - U.S. small cap
Fair values of plan assets
Total assets at fair value	22	54
Pension Benefits [Member] | Fair Value, Inputs, Level 1, 2 and 3 [Member] | Fixed income securities - U.S. Treasury securities
Fair values of plan assets
Total assets at fair value	157	103
Pension Benefits [Member] | Fair Value, Inputs, Level 1, 2 and 3 [Member] | Fixed income securities - Government and municipal bonds
Fair values of plan assets
Total assets at fair value	21	15
Pension Benefits [Member] | Fair Value, Inputs, Level 1, 2 and 3 [Member] | Fixed income securities - Mortgage and asset-backed securities
Fair values of plan assets
Total assets at fair value	48	47
Pension Benefits [Member] | Fair Value, Inputs, Level 1, 2 and 3 [Member] | Fixed income securities - Corporate bonds
Fair values of plan assets
Total assets at fair value	210	158
Pension Benefits [Member] | Fair Value, Inputs, Level 1, 2 and 3 [Member] | Insurance company investment contracts and other
Fair values of plan assets
Total assets at fair value	6	5
Pension Benefits [Member] | Fair Value Measured at Net Asset Value Per Share [Member] | Commingled investment funds - equities - U.S. large cap
Fair values of plan assets
Total assets at fair value	123	265
Pension Benefits [Member] | Fair Value Measured at Net Asset Value Per Share [Member] | Commingled investment funds - equities - International small cap
Fair values of plan assets
Total assets at fair value	8	26
Pension Benefits [Member] | Fair Value Measured at Net Asset Value Per Share [Member] | Commingled investment funds - equities - International emerging markets
Fair values of plan assets
Total assets at fair value	19	41
Pension Benefits [Member] | Fair Value Measured at Net Asset Value Per Share [Member] | Commingled investment funds - equities - International developed markets
Fair values of plan assets
Total assets at fair value	51	110
Pension Benefits [Member] | Fair Value Measured at Net Asset Value Per Share [Member] | Commingled investment funds - fixed income - U.S. long duration
Fair values of plan assets
Total assets at fair value	335	205
Pension Benefits [Member] | Fair Value Measured at Net Asset Value Per Share [Member] | Commingled investment funds - fixed income - Corporate bonds
Fair values of plan assets
Total assets at fair value	$ 92	119
Other Postretirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Proportion of assets subjected to income tax	38.00%
Fair values of plan assets
Total assets at fair value	$ 214	227	$ 208
Other Postretirement Benefits [Member] | Level 1 [Member]
Fair values of plan assets
Total assets at fair value	102	105
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] | Equity securities - U.S. large cap
Fair values of plan assets
Total assets at fair value	20	25
Other Postretirement Benefits [Member] | Level 1 [Member] | Equity securities - U.S. small cap
Fair values of plan assets
Total assets at fair value	9	14
Other Postretirement Benefits [Member] | Level 1 [Member] | Equity securities - International developed markets large cap growth
Fair values of plan assets
Total assets at fair value	0	0
Other Postretirement Benefits [Member] | Level 1 [Member] | Fixed income securities - U.S. Treasury securities
Fair values of plan assets
Total assets at fair value	19	12
Other Postretirement Benefits [Member] | Level 1 [Member] | Fixed income securities - Government and municipal bonds
Fair values of plan assets
Total assets at fair value	0	0
Other Postretirement Benefits [Member] | Level 1 [Member] | Fixed income securities - Mortgage and asset-backed securities
Fair values of plan assets
Total assets at fair value	0	0
Other Postretirement Benefits [Member] | Level 1 [Member] | Fixed income securities - Corporate bonds
Fair values of plan assets
Total assets at fair value	0	0
Other Postretirement Benefits [Member] | Level 1 [Member] | Mutual fund - Municipal bonds
Fair values of plan assets
Total assets at fair value	43	43
Other Postretirement Benefits [Member] | Level 2 [Member]
Fair values of plan assets
Total assets at fair value	38	32
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] | Equity securities - U.S. large cap
Fair values of plan assets
Total assets at fair value	0	0
Other Postretirement Benefits [Member] | Level 2 [Member] | Equity securities - U.S. small cap
Fair values of plan assets
Total assets at fair value	0	0
Other Postretirement Benefits [Member] | Level 2 [Member] | Equity securities - International developed markets large cap growth
Fair values of plan assets
Total assets at fair value	5	6
Other Postretirement Benefits [Member] | Level 2 [Member] | Fixed income securities - U.S. Treasury securities
Fair values of plan assets
Total assets at fair value	0	0
Other Postretirement Benefits [Member] | Level 2 [Member] | Fixed income securities - Government and municipal bonds
Fair values of plan assets
Total assets at fair value	2	2
Other Postretirement Benefits [Member] | Level 2 [Member] | Fixed income securities - Mortgage and asset-backed securities
Fair values of plan assets
Total assets at fair value	6	5
Other Postretirement Benefits [Member] | Level 2 [Member] | Fixed income securities - Corporate bonds
Fair values of plan assets
Total assets at fair value	25	19
Other Postretirement Benefits [Member] | Level 2 [Member] | Mutual fund - Municipal bonds
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] | Equity securities - U.S. large cap
Fair values of plan assets
Total assets at fair value	0	0
Other Postretirement Benefits [Member] | Level 3 [Member] | Equity securities - U.S. small cap
Fair values of plan assets
Total assets at fair value	0	0
Other Postretirement Benefits [Member] | Level 3 [Member] | Equity securities - International developed markets large cap growth
Fair values of plan assets
Total assets at fair value	0	0
Other Postretirement Benefits [Member] | Level 3 [Member] | Fixed income securities - U.S. Treasury securities
Fair values of plan assets
Total assets at fair value	0	0
Other Postretirement Benefits [Member] | Level 3 [Member] | Fixed income securities - Government and municipal bonds
Fair values of plan assets
Total assets at fair value	0	0
Other Postretirement Benefits [Member] | Level 3 [Member] | Fixed income securities - Mortgage and asset-backed securities
Fair values of plan assets
Total assets at fair value	0	0
Other Postretirement Benefits [Member] | Level 3 [Member] | Fixed income securities - Corporate bonds
Fair values of plan assets
Total assets at fair value	0	0
Other Postretirement Benefits [Member] | Level 3 [Member] | Mutual fund - Municipal bonds
Fair values of plan assets
Total assets at fair value	0	0
Other Postretirement Benefits [Member] | Fair Value, Inputs, Level 1, 2 and 3 [Member]
Fair values of plan assets
Total assets at fair value	140	137
Other Postretirement Benefits [Member] | Fair Value, Inputs, Level 1, 2 and 3 [Member] | Cash management fund
Fair values of plan assets
Total assets at fair value	11	11
Other Postretirement Benefits [Member] | Fair Value, Inputs, Level 1, 2 and 3 [Member] | Equity securities - U.S. large cap
Fair values of plan assets
Total assets at fair value	20	25
Other Postretirement Benefits [Member] | Fair Value, Inputs, Level 1, 2 and 3 [Member] | Equity securities - U.S. small cap
Fair values of plan assets
Total assets at fair value	9	14
Other Postretirement Benefits [Member] | Fair Value, Inputs, Level 1, 2 and 3 [Member] | Equity securities - International developed markets large cap growth
Fair values of plan assets
Total assets at fair value	5	6
Other Postretirement Benefits [Member] | Fair Value, Inputs, Level 1, 2 and 3 [Member] | Fixed income securities - U.S. Treasury securities
Fair values of plan assets
Total assets at fair value	19	12
Other Postretirement Benefits [Member] | Fair Value, Inputs, Level 1, 2 and 3 [Member] | Fixed income securities - Government and municipal bonds
Fair values of plan assets
Total assets at fair value	2	2
Other Postretirement Benefits [Member] | Fair Value, Inputs, Level 1, 2 and 3 [Member] | Fixed income securities - Mortgage and asset-backed securities
Fair values of plan assets
Total assets at fair value	6	5
Other Postretirement Benefits [Member] | Fair Value, Inputs, Level 1, 2 and 3 [Member] | Fixed income securities - Corporate bonds
Fair values of plan assets
Total assets at fair value	25	19
Other Postretirement Benefits [Member] | Fair Value, Inputs, Level 1, 2 and 3 [Member] | Mutual fund - Municipal bonds
Fair values of plan assets
Total assets at fair value	43	43
Other Postretirement Benefits [Member] | Fair Value Measured at Net Asset Value Per Share [Member] | Commingled investment funds - equities - U.S. large cap
Fair values of plan assets
Total assets at fair value	14	31
Other Postretirement Benefits [Member] | Fair Value Measured at Net Asset Value Per Share [Member] | Commingled investment funds - equities - International small cap
Fair values of plan assets
Total assets at fair value	1	3
Other Postretirement Benefits [Member] | Fair Value Measured at Net Asset Value Per Share [Member] | Commingled investment funds - equities - International emerging markets
Fair values of plan assets
Total assets at fair value	2	5
Other Postretirement Benefits [Member] | Fair Value Measured at Net Asset Value Per Share [Member] | Commingled investment funds - equities - International developed markets
Fair values of plan assets
Total assets at fair value	6	13
Other Postretirement Benefits [Member] | Fair Value Measured at Net Asset Value Per Share [Member] | Commingled investment funds - fixed income - U.S. long duration
Fair values of plan assets
Total assets at fair value	40	24
Other Postretirement Benefits [Member] | Fair Value Measured at Net Asset Value Per Share [Member] | Commingled investment funds - fixed income - Corporate bonds
Fair values of plan assets
Total assets at fair value	$ 11	$ 14

EBP Benefit Pymts & Defined Con

EBP Benefit Pymts & Defined Contribution Plans (Details 5) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Expected benefit payments
Employer's contributions charged to expense under defined contribution plans	$ 35	$ 34	$ 36
Other Postretirement Benefits [Member]
Benefit Plan Disclosure [Line Items]
Expected total plans contribution, approximate	6
Expected benefit payments
2,019	14
2,020	14
2,021	13
2,022	14
2,023	14
2024-2028	59
Pension Benefits [Member]
Benefit Plan Disclosure [Line Items]
Expected total plans contribution, approximate	63
Expected benefit payments
2,019	85
2,020	87
2,021	90
2,022	90
2,023	89
2024-2028	467
Nonqualified Plan [Member]
Benefit Plan Disclosure [Line Items]
Expected total plans contribution, approximate	3
Qualified Plan [Member]
Benefit Plan Disclosure [Line Items]
Expected total plans contribution, approximate	$ 60

Property, Plant, and Equipmen_2

Property, Plant, and Equipment (Details PPE) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Property, Plant, and Equipment
Property, plant, and equipment, at cost		$ 38,661	$ 39,513
Accumulated depreciation and amortization		(11,157)	(11,302)
Property, plant, and equipment - net		27,504	28,211
Depreciation and amortization expenses		1,392	1,389	$ 1,407
Nonregulated [Member] | Natural gas gathering and processing facilities [Member]
Property, Plant, and Equipment
Property, plant, and equipment, at cost		$ 15,324	18,440
Nonregulated [Member] | Natural gas gathering and processing facilities [Member] | Minimum [Member]
Property, Plant, and Equipment
Property, Plant and Equipment, Useful Life	[1]	5 years
Nonregulated [Member] | Natural gas gathering and processing facilities [Member] | Maximum [Member]
Property, Plant, and Equipment
Property, Plant and Equipment, Useful Life	[1]	40 years
Nonregulated [Member] | Construction in Progress [Member]
Property, Plant, and Equipment
Property, plant, and equipment, at cost		$ 778	566
Nonregulated [Member] | Other Capitalized Property Plant and Equipment [Member]
Property, Plant, and Equipment
Property, plant, and equipment, at cost		$ 2,356	2,776
Nonregulated [Member] | Other Capitalized Property Plant and Equipment [Member] | Minimum [Member]
Property, Plant, and Equipment
Property, Plant and Equipment, Useful Life	[1]	2 years
Nonregulated [Member] | Other Capitalized Property Plant and Equipment [Member] | Maximum [Member]
Property, Plant, and Equipment
Property, Plant and Equipment, Useful Life	[1]	45 years
Regulated [Member] | Natural gas transmission facilities [Member]
Property, Plant, and Equipment
Property, plant, and equipment, at cost		$ 17,312	14,460
Regulated [Member] | Natural gas transmission facilities [Member] | Minimum [Member]
Property, Plant, and Equipment
Property, Plant, and Equipment, Depreciation Rate	[1]	1.20%
Regulated [Member] | Natural gas transmission facilities [Member] | Maximum [Member]
Property, Plant, and Equipment
Property, Plant, and Equipment, Depreciation Rate	[1]	6.97%
Regulated [Member] | Construction in Progress [Member]
Property, Plant, and Equipment
Property, plant, and equipment, at cost		$ 965	1,637
Regulated [Member] | Acquisition Adjustment Of Regulated Facilities [Member]
Property, Plant, and Equipment
Property, Plant and Equipment, Plant Acquisition Adjustments for Intangible Utility Plants		$ 586	626
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		$ 1,926	$ 1,634
Regulated [Member] | Other Capitalized Property Plant and Equipment [Member] | Minimum [Member]
Property, Plant, and Equipment
Property, Plant and Equipment, Useful Life	[1]	5 years
Property, Plant, and Equipment, Depreciation Rate	[1]	1.35%
Regulated [Member] | Other Capitalized Property Plant and Equipment [Member] | Maximum [Member]
Property, Plant, and Equipment
Property, Plant and Equipment, Useful Life	[1]	45 years
Property, Plant, and Equipment, Depreciation Rate	[1]	33.33%
[1]	(1)Estimated useful life and depreciation rates are presented as of December 31, 2018. Depreciation rates and estimated useful lives for regulated assets are prescribed by the FERC.

Property, Plant, and Equipmen_3

Property, Plant, and Equipment (Details ARO) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2018		Dec. 31, 2017
Asset Retirement Obligations
Asset Retirement Obligations, Noncurrent		$ 968		$ 946
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Beginning balance		998		862
Liabilities incurred		21		33
Liabilities settled		(19)		(16)
Accretion expense		71	[1]	141
Revisions (1)	[2]	(39)		(22)
Ending balance		1,032		$ 998
Asset Retirement Obligation Costs [Member]
Unusual or Infrequent Item [Line Items]
Transco's annual funding commitment for ARO		$ 36
[1]	(1)The decrease in accretion expense in 2018 primarily reflects the absence of a 2017 adjustment associated with obligations identified from certain Transco land agreements.
[2]	(2)Several factors are considered in the annual review process, including inflation rates, current estimates for removal cost, market risk premiums, discount rates, and the estimated remaining useful life of the assets. The 2018 revisions reflect changes in removal cost estimates, decreases in the estimated remaining useful life of certain assets and increases in the discount rates used in the annual review process. The 2017 revisions reflect changes in removal cost estimates and decreases in the estimated remaining useful life of certain assets and discount rates used in the annual review process.

Other Intangible Assets (Detail

Other Intangible Assets (Details) - USD ($) $ in Millions	1 Months Ended	12 Months Ended
	May 31, 2015	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Finite-Lived Intangible Assets [Line Items]
Acquired Finite-lived Intangible Assets, Weighted Average Useful Life	30 years
Amortization of Intangible Assets		$ 333	$ 347	$ 356
Finite-Lived Intangible Assets, Amortization Expense, Next Twelve Months		312
Finite-Lived Intangible Assets, Amortization Expense, Year Two		312
Finite-Lived Intangible Assets, Amortization Expense, Year Three		312
Finite-Lived Intangible Assets, Amortization Expense, Year Four		312
Finite-Lived Intangible Assets, Amortization Expense, Year Five		312
Contractual customer relationships [Member]
Finite-Lived Intangible Assets [Line Items]
Finite-Lived Intangible Assets, Gross		9,232	10,027
Finite-Lived Intangible Assets, Accumulated Amortization		$ (1,465)	$ (1,283)

Accrued Liabilities Table (Deta

Accrued Liabilities Table (Details) - USD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
Accrued Liabilities, Current [Abstract]
Interest on debt	$ 282	$ 267
Revenue contract liabilities (Note 2)	244	361
Employee costs	205	202
Other, including other loss contingencies	371	337
Other accrued liabilities	$ 1,102	$ 1,167

Long-Term Debt (Details)

Long-Term Debt (Details) - USD ($) $ in Millions	3 Months Ended
	Dec. 31, 2018	Sep. 30, 2017	Aug. 24, 2018	Jun. 15, 2018	Mar. 28, 2018	Mar. 15, 2018	Mar. 05, 2018	Dec. 31, 2017	Jul. 03, 2017	Jun. 05, 2017	Apr. 03, 2017	Feb. 23, 2017
Long-term Debt
Debt issuance costs	$ (131)							$ (122)
Net unamortized debt premium (discount)	(62)				$ (7)			(24)	$ (3)			$ (30)
Total long-term debt, including current portion	22,414							20,935
Long-term debt due within one year	(47)							(501)
Long-term debt	22,367							20,434
4.875% Senior Unsecured Notes due 2024 [Member]
Long-term Debt
Long-term debt interest rate					4.875%
Transcontinental Gas Pipe Line Company, LLC [Member]
Long-term Debt
Other financing obligations	1,067							231
Transcontinental Gas Pipe Line Company, LLC [Member] | 6.05% Senior Unsecured Notes due 2018 [Member]
Long-term Debt
Long-term debt	0							$ 250
Long-term debt interest rate				6.05%				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%
Transcontinental Gas Pipe Line Company, LLC [Member] | 4% Senior Unsecured Notes Due 2028 [Member]
Long-term Debt
Long-term debt	$ 400							0
Long-term debt interest rate	4.00%					4.00%
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%
Transcontinental Gas Pipe Line Company, LLC [Member] | 4.6%SeniorUnsecuredNotesDue2048 [Member]
Long-term Debt
Long-term debt	$ 600							0
Long-term debt interest rate	4.60%					4.60%
Transcontinental Gas Pipe Line Company, LLC [Member] | Dalton [Member]
Long-term Debt
Other financing obligations	$ 260							231
Capitalized Construction Costs	100.00%
Debt Instrument, Term		35 years
Transcontinental Gas Pipe Line Company, LLC [Member] | AtlanticSunrise [Member]
Long-term Debt
Other financing obligations	$ 807
Capitalized Construction Costs	100.00%
Debt Instrument, Term	20 years
Northwest Pipeline LLC [Member] | 6.05% Senior Unsecured Notes due 2018 [Member]
Long-term Debt
Long-term debt	$ 0							$ 250
Long-term debt interest rate				6.05%				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	$ 500							250
Long-term debt interest rate	4.00%		4.00%								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] | 4.85%SeniorUnsecuredNotesDue2048 [Member]
Long-term Debt
Long-term debt interest rate							4.85%
The Williams Companies, Inc. [Member]
Long-term Debt
Credit facility loans	$ 160							270
The Williams Companies, Inc. [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%
The Williams Companies, Inc. [Member] | 4.125% Senior Unsecured Notes due 2020 [Member]
Long-term Debt
Long-term debt	$ 600							600
Long-term debt interest rate	4.125%
The Williams Companies, Inc. [Member] | 4% Senior Unsecured Notes due 2021 [Member]
Long-term Debt
Long-term debt	$ 500							500
Long-term debt interest rate	4.00%
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] | 3.35% Senior Unsecured Notes due 2022 [Member]
Long-term Debt
Long-term debt	$ 750							750
Long-term debt interest rate	3.35%
The Williams Companies, Inc. [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%
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] | 4.5% Senior Unsecured Notes due 2023 [Member]
Long-term Debt
Long-term debt	$ 600							600
Long-term debt interest rate	4.50%
The Williams Companies, Inc. [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%
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] | 4.875% Senior Unsecured Notes due 2024 [Member]
Long-term Debt
Long-term debt	$ 0							$ 750
Long-term debt interest rate								4.875%
The Williams Companies, Inc. [Member] | 3.9% Senior Unsecured Notes due 2025 [Member]
Long-term Debt
Long-term debt	$ 750							$ 750
Long-term debt interest rate	3.90%
The Williams Companies, Inc. [Member] | 4% Senior Unsecured Notes due 2025 [Member]
Long-term Debt
Long-term debt	$ 750							750
Long-term debt interest rate	4.00%
The Williams Companies, Inc. [Member] | 3.75% Senior Unsecured Notes Due 2027 [Member]
Long-term Debt
Long-term debt	$ 1,450							1,450
Long-term debt interest rate	3.75%
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] | 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%
The Williams Companies, Inc. [Member] | 5.8% Senior Unsecured Notes due 2043 [Member]
Long-term Debt
Long-term debt	$ 400							400
Long-term debt interest rate	5.80%
The Williams Companies, Inc. [Member] | 5.4% Senior Unsecured Notes Due 2044 [Member]
Long-term Debt
Long-term debt	$ 500							500
Long-term debt interest rate	5.40%
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 - 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%
The Williams Companies, Inc. [Member] | 4.9% Senior Unsecured Notes due 2045 [Member]
Long-term Debt
Long-term debt	$ 500							500
Long-term debt interest rate	4.90%
The Williams Companies, Inc. [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%
The Williams Companies, Inc. [Member] | 4.85%SeniorUnsecuredNotesDue2048 [Member]
Long-term Debt
Long-term debt	$ 800							0
Long-term debt interest rate	4.85%
The Williams Companies, Inc. [Member] | Various - 7.625% to 10.25% Senior Unsecured Notes and Debentures due 2019 to 2027 [Member]
Long-term Debt
Long-term debt	$ 55							$ 55

Long-Term Debt Maturities (Deta

Long-Term Debt Maturities (Details) $ in Millions	Dec. 31, 2018USD ($)
Aggregate minimum maturities of long-term debt
2,019	$ 47
2,020	2,138
2,021	890
2,022	2,021
2,023	$ 1,633

Long-Term Debt Issuances and Re

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

Jun. 15, 2018

Mar. 28, 2018

Jul. 06, 2017

Jul. 03, 2017

Apr. 15, 2017

Feb. 23, 2017

Feb. 01, 2017

Dec. 31, 2018

Sep. 30, 2017

Aug. 24, 2018

Mar. 15, 2018

Mar. 05, 2018

Dec. 31, 2017

Jun. 05, 2017

Apr. 03, 2017

6.125% Senior Unsecured Notes due 2022 [Member]

Debt Instrument [Line Items]

Extinguishment of Debt, Amount

$ 750

Long-term debt interest rate

6.125%

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%

4.875% Senior Unsecured Notes due 2024 [Member]

Debt Instrument [Line Items]

Extinguishment of Debt, Amount

$ 750

Long-term debt interest rate

4.875%

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] | 7.25% Senior Unsecured Notes due 2017 [Member]

Debt Instrument [Line Items]

Extinguishment of Debt, Amount

$ 600

Long-term debt interest rate

7.25%

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%

Williams Partners L.P. [Member] | 4.85%SeniorUnsecuredNotesDue2048 [Member]

Debt Instrument [Line Items]

Long-term debt face amount

$ 800

Long-term debt interest rate

4.85%

The Williams Companies, Inc. [Member] | 3.9% Senior Unsecured Notes due 2025 [Member]

Debt Instrument [Line Items]

Long-term debt interest rate

3.90%

The Williams Companies, Inc. [Member] | 4.9% Senior Unsecured Notes due 2045 [Member]

Debt Instrument [Line Items]

Long-term debt interest rate

4.90%

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%

The Williams Companies, Inc. [Member] | 4.3% Senior Unsecured Notes Due 2024 [Member]

Debt Instrument [Line Items]

Long-term debt interest rate

4.30%

The Williams Companies, Inc. [Member] | 5.4% Senior Unsecured Notes Due 2044 [Member]

Debt Instrument [Line Items]

Long-term debt interest rate

5.40%

The Williams Companies, Inc. [Member] | 4.5% Senior Unsecured Notes due 2023 [Member]

Debt Instrument [Line Items]

Long-term debt interest rate

4.50%

The Williams Companies, Inc. [Member] | 5.8% Senior Unsecured Notes due 2043 [Member]

Debt Instrument [Line Items]

Long-term debt interest rate

5.80%

The Williams Companies, Inc. [Member] | 3.6% Senior Unsecured Notes due 2022 [Member]

Debt Instrument [Line Items]

Long-term debt interest rate

3.60%

The Williams Companies, Inc. [Member] | 4% Senior Unsecured Notes due 2025 [Member]

Debt Instrument [Line Items]

Long-term debt interest rate

4.00%

The Williams Companies, Inc. [Member] | 5.1% Senior Unsecured Notes due 2045 [Member]

Debt Instrument [Line Items]

Long-term debt interest rate

5.10%

The Williams Companies, Inc. [Member] | 3.75% Senior Unsecured Notes Due 2027 [Member]

Debt Instrument [Line Items]

Long-term debt interest rate

3.75%

The Williams Companies, Inc. [Member] | 4.85%SeniorUnsecuredNotesDue2048 [Member]

Debt Instrument [Line Items]

Long-term debt interest rate

4.85%

The Williams Companies, Inc. [Member] | 4.875% Senior Unsecured Notes due 2024 [Member]

Debt Instrument [Line Items]

Long-term debt interest rate

4.875%

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

Debt Instrument [Line Items]

Long-term debt face amount

$ 250

$ 250

Long-term debt interest rate

4.00%

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%

Northwest Pipeline LLC [Member] | 6.05% Senior Unsecured Notes due 2018 [Member]

Debt Instrument [Line Items]

Extinguishment of Debt, Amount

$ 250

Long-term debt interest rate

6.05%

6.05%

Transcontinental Gas Pipe Line Company, LLC [Member]

Debt Instrument [Line Items]

Other Long-term Debt, Noncurrent

$ 1,067

$ 231

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

Debt Instrument [Line Items]

Long-term debt interest rate

7.85%

Transcontinental Gas Pipe Line Company, LLC [Member] | 6.05% Senior Unsecured Notes due 2018 [Member]

Debt Instrument [Line Items]

Extinguishment of Debt, Amount

$ 250

Long-term debt interest rate

6.05%

6.05%

Transcontinental Gas Pipe Line Company, LLC [Member] | 4% Senior Unsecured Notes Due 2028 [Member]

Debt Instrument [Line Items]

Long-term debt face amount

$ 400

Long-term debt interest rate

4.00%

4.00%

Transcontinental Gas Pipe Line Company, LLC [Member] | 4.6%SeniorUnsecuredNotesDue2048 [Member]

Debt Instrument [Line Items]

Long-term debt face amount

$ 600

Long-term debt interest rate

4.60%

4.60%

Transcontinental Gas Pipe Line Company, LLC [Member] | Dalton [Member]

Debt Instrument [Line Items]

Other Long-term Debt, Noncurrent

$ 260

$ 231

Percent Of Construction Costs Capitalized

100.00%

Debt Instrument, Term

35 years

Transcontinental Gas Pipe Line Company, LLC [Member] | AtlanticSunrise [Member]

Debt Instrument [Line Items]

Other Long-term Debt, Noncurrent

$ 807

Percent Of Construction Costs Capitalized

100.00%

Debt Instrument, Term

20 years

Credit Facilities and Commercia

Credit Facilities and Commercial Paper (Details) $ in Millions	Aug. 10, 2018USD ($)	Feb. 19, 2019USD ($)	Dec. 31, 2018USD ($)	Dec. 31, 2017USD ($)
Williams Companies Inc [Member]
Credit Facility and Commercial Paper [Line Items]
Credit facility, capacity	$ 4,500		$ 4,500
Credit facility, loans outstanding			160	$ 270
Additional amount by which credit facility can be increased	$ 500
Maximum ratio of debt to EBITDA after acquisition	5.5
Acquisition Trigger Amount	$ 25
Williams Companies Inc [Member] | SwingLineLoan [Member]
Credit Facility and Commercial Paper [Line Items]
Credit facility, capacity	200
Williams Companies Inc [Member] | Commercial paper [Member]
Credit Facility and Commercial Paper [Line Items]
Credit facility, capacity	$ 4,000
Commercial paper, outstanding			0	$ 0
Commercial paper, maximum maturity	397 days
Williams Companies Inc [Member] | Commercial paper [Member] | Subsequent Event [Member]
Credit Facility and Commercial Paper [Line Items]
Commercial paper, outstanding		$ 0
Williams Companies Inc [Member] | Letters of credit [Member]
Credit Facility and Commercial Paper [Line Items]
Credit facility, capacity	$ 1,000
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			$ 14
Williams Partners L.P. [Member] | Commercial paper [Member]
Credit Facility and Commercial Paper [Line Items]
Credit facility, capacity	3,000
Transcontinental Gas Pipe Line Company, LLC [Member]
Credit Facility and Commercial Paper [Line Items]
Credit facility, capacity	$ 500
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%
Sep18Dec18Mar19Jun19 [Member] | Williams Companies Inc [Member]
Credit Facility and Commercial Paper [Line Items]
Maximum ratio of debt to EBITDA	5.75
Sep19Dec19 [Member] | Williams Companies Inc [Member]
Credit Facility and Commercial Paper [Line Items]
Maximum ratio of debt to EBITDA	5.5
Mar20 And Subsequent Quarters [Member] | Williams Companies Inc [Member]
Credit Facility and Commercial Paper [Line Items]
Maximum ratio of debt to EBITDA	5

Cash Payments For Interest (Net

Cash Payments For Interest (Net of Amounts Capitalized) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Debt Disclosure [Abstract]
Cash payments for interest (net of amounts capitalized)	$ 1,064	$ 1,110	$ 1,152

Leases-Lessee (Details)

Leases-Lessee (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Future minimum annual rentals under noncancelable operating leases
2,019	$ 32
2,020	31
2,021	28
2,022	24
2,023	15
Thereafter	86
Total	216
Operating leases [Abstract]
Total rent expense	$ 73	$ 62	$ 64

Stockholders' Equity Stockholde

Stockholders' Equity Stockholders' Equity (Details) - USD ($) $ / shares in Units, $ in Millions	Feb. 20, 2019	Feb. 01, 2017	Jul. 31, 2018	Jan. 31, 2017	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016	Jan. 13, 2017
Class of Stock [Line Items]
Common Stock, Dividends, Per Share, Declared					$ 1.36	$ 1.20	$ 1.68
Stock Issued During Period, Shares, New Issues		9,750,000		65,000,000
Preferred Stock, Value, Issued					$ 35	$ 0
Shares Issued, Price Per Share								$ 29
Proceeds from Issuance of Common Stock		$ 2,100			$ 15	$ 2,131	$ 9
Series B Preferred Stock [Member]
Class of Stock [Line Items]
Stock Issued During Period, Shares, New Issues			35,000
Preferred Stock, Value, Issued			$ 35
Preferred Stock, Dividend Rate, Percentage			7.25%
Dividends, Preferred Stock, Cash			$ 1.1
Preferred Stock, Shares Authorized			30,000,000
Preferred Stock, Par or Stated Value Per Share			$ 1
Subsequent Event [Member]
Class of Stock [Line Items]
Common Stock, Dividends, Per Share, Declared	$ 0.38

Stockholders' Equity Table of C

Stockholders' Equity Table of Changes in AOCI (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016	Jan. 01, 2018
Accumulated Other Comprehensive Income (Loss) [Line Items]
Total, Beginning Balance	$ (238)
Noncontrolling Interest, Decrease from Redemptions or Purchase of Interests	1,862
Other comprehensive income (loss)	30	$ 100	$ 172
Total, Ending Balance	(270)	(238)
Cash Flow Hedges [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Total, Beginning Balance	(2)
Cumulative Effect of New Accounting Principle in Period of Adoption				$ 0
Noncontrolling Interest, Decrease from Redemptions or Purchase of Interests	(3)
Other Comprehensive Income (Loss), before Reclassifications, Net of Tax	(2)
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax	5
Other comprehensive income (loss)	3
Total, Ending Balance	(2)	(2)
Foreign Currency Translation [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Total, Beginning Balance	(1)
Cumulative Effect of New Accounting Principle in Period of Adoption				0
Noncontrolling Interest, Decrease from Redemptions or Purchase of Interests	0
Other Comprehensive Income (Loss), before Reclassifications, Net of Tax	0
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax	0
Other comprehensive income (loss)	0
Total, Ending Balance	(1)	(1)
Pension and Other Post Retirement Benefits [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Total, Beginning Balance	(235)
Cumulative Effect of New Accounting Principle in Period of Adoption				(61)
Noncontrolling Interest, Decrease from Redemptions or Purchase of Interests	0
Other Comprehensive Income (Loss), before Reclassifications, Net of Tax	(6)
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax	35
Other comprehensive income (loss)	29
Total, Ending Balance	(267)	(235)
Total AOCI Attributable to Parent [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Total, Beginning Balance	(238)
Cumulative Effect of New Accounting Principle in Period of Adoption				$ (61)
Noncontrolling Interest, Decrease from Redemptions or Purchase of Interests	(3)
Other Comprehensive Income (Loss), before Reclassifications, Net of Tax	(8)
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax	40
Other comprehensive income (loss)	32	101	$ 103
Total, Ending Balance	$ (270)	$ (238)

Stockholders' Equity Stockhol_2

Stockholders' Equity Stockholders' Equity Reclassifications from AOCI (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Total cash flow hedges, energy commodity contract reclassifications	$ 331	$ 535	$ (375)
Provision (benefit) for income taxes	(138)	1,974	25
Net income (loss)	193	2,509	(350)
Net Income (Loss) Attributable to Noncontrolling Interest	(348)	$ (335)	$ (74)
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	5
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	35
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	55
Provision (benefit) for income taxes	(12)
Net income (loss)	43
Net Income (Loss) Attributable to Noncontrolling Interest	(3)
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax	40
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 actuarial (gain) loss included in net periodic benefit cost	46
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	$ 9

Equity-Based Compensation (Deta

Equity-Based Compensation (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Millions		12 Months Ended
		Dec. 31, 2018		Dec. 31, 2017	Dec. 31, 2016	May 22, 2014	May 20, 2010	May 17, 2007
Williams Companies Incentive Plan [Member]
Equity-Based Compensation (Textuals) [Abstract]
Shares reserved for issuance		24,000				10,000	11,000	19,000
Shares available for future grants		12,000
Equity-based compensation expense		$ 54		$ 70	$ 53
Tax benefit from equity-based compensation expense		14		$ 17	20
Employee Service Share-based Compensation, Nonvested Awards, Compensation Cost Not yet Recognized [Abstract]
Unrecognized equity-based compensation expense		$ 56
Unrecognized equity-based compensation expense, Weighted-average period of recognition in years		1 year 9 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		6,600
Options, Granted		1,300
Options, Exercised		(400)
Options, Cancelled		(200)
Options Outstanding, Ending Balance		7,300		6,600
Options Exercisable at Period End		5,300
Options, Aggregate Intrinsic Value, Ending Balance		$ 6
Options, Aggregate Intrinsic Value, Exercisable at Period End		6
Total intrinsic value of options exercised		3		$ 4	2
Tax benefits realized on options exercised		0		1	1
Cash received from the exercise of options		$ 9		$ 7	$ 4
Stock Options Outstanding, Weighted Average Remaining Contractual Life		5 years 1 month
Stock Options Exercisable, Weighted Average Remaining Contractual Life		3 years 8 months
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding, Weighted Average Exercise Price [Abstract]
Options, Weighted Average Exercise Price, Beginning Balance		$ 31.53
Options, Weighted Average Exercise Price, Granted		29.09
Options, Weighted Average Exercise Price, Exercised		23.06
Options, Weighted Average Exercise Price, Cancelled		31.45
Options, Weighted Average Exercise Price, Ending Balance		31.55		$ 31.53
Options, Weighted Average Exercise Price, Exercisable at Period End		32.63
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		$ 5.49		$ 6.61	$ 7.90
Weighted-average assumptions:
Dividend yield		4.70%		4.20%	3.20%
Volatility		30.10%		35.10%	44.70%
Risk-free interest rate		2.70%		2.10%	1.20%
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		$ 52
Rollforward of nonvested restricted stock unit activity and related information
Restricted Stock Units, Nonvested shares, Beginning Balance		4,200
Restricted Stock Units, Granted		1,700
Restricted Stock Units, Forfeited		(500)
Restricted Stock Units, Vested		(900)
Restricted Stock Units, Nonvested shares, Ending Balance		4,500		4,200
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]	$ 31.02
Weighted-average grant date fair value of restricted stock units granted during the year, per share		30.48	[1]	$ 29.47	$ 26.51
Restricted Stock Units, Forfeited, Weighted-Average Fair Value	[1]	32.97
Restricted Stock Units, Vested, Weighted-Average Fair Value	[1]	39.30
Restricted Stock Units, Nonvested, Weighted-Average Fair Value, Ending Balance	[1]	$ 28.96		$ 31.02
Restricted Stock Units, Vested in Period, Fair Value		$ 35		$ 33	$ 32
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		34.00%
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		746
No. of shares purchases by employees		338
Average price of shares purchased		$ 20.70
Williams Partners Long Term Incentive Plan [Member] | Nonvested Restricted Stock Units [Member]
Equity-Based Compensation (Textuals) [Abstract]
Equity-based compensation expense		$ 1		8	20
Rollforward of nonvested restricted stock unit activity and related information
Restricted Stock Units, Granted		0
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		$ 5		$ 24	$ 34
[1]	Performance-based restricted stock units are valued considering measures of total shareholder return, utilizing a Monte Carlo valuation method, and return on capital employed. All other restricted stock units are valued at the grant-date market price. Restricted stock units generally vest after three years.

Fair Value Measurements Recurri

Fair Value Measurements Recurring Measurements and Additional (Details) - USD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
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	29
Carrying Amount [Member]
Additional disclosures:
Long-term debt, including current portion	(22,414)	(20,935)
Guarantees	(43)	(43)
Carrying Amount [Member] | Indemnification Agreement [Member]
Additional disclosures:
Guarantees	0
Fair Value [Member]
Additional disclosures:
Long-term debt, including current portion	(23,330)	(23,005)
Guarantees	(30)	(30)
Level 1 [Member]
Additional disclosures:
Long-term debt, including current portion	0	0
Guarantees	0	0
Level 2 [Member]
Additional disclosures:
Long-term debt, including current portion	(23,330)	(23,005)
Guarantees	(14)	(14)
Level 3 [Member]
Additional disclosures:
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	150	135
Fair Value, Measurements, Recurring [Member] | Carrying Amount [Member] | Designated as Hedging Instrument [Member]
Measured on a recurring basis
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	3
Energy derivatives liabilities	(7)	(3)
Fair Value, Measurements, Recurring [Member] | Fair Value [Member]
Measured on a recurring basis
ARO Trust investments	150	135
Fair Value, Measurements, Recurring [Member] | Fair Value [Member] | Designated as Hedging Instrument [Member]
Measured on a recurring basis
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	3
Energy derivatives liabilities	(7)	(3)
Fair Value, Measurements, Recurring [Member] | Level 1 [Member]
Measured on a recurring basis
ARO Trust investments	150	135
Fair Value, Measurements, Recurring [Member] | Level 1 [Member] | Designated as Hedging Instrument [Member]
Measured on a recurring basis
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	3
Energy derivatives liabilities	(4)	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 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 liabilities		0
Fair Value, Measurements, Recurring [Member] | Level 3 [Member] | Not Designated as Hedging Instrument [Member]
Measured on a recurring basis
Energy derivatives assets	0
Energy derivatives liabilities	$ (3)	$ (3)

Fair Value Measurements Nonrecu

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

3 Months Ended

12 Months Ended

Dec. 31, 2018

Jun. 30, 2018

Sep. 30, 2017

Jun. 30, 2017

[7]

Dec. 31, 2016

Jun. 30, 2016

Mar. 31, 2016

Dec. 31, 2018

Dec. 31, 2017

Dec. 31, 2016

Fair Value Assets Measured On Nonrecurring Basis [Abstract]

Impairment of equity-method investments

$ 32

$ 0

$ 430

Other Asset Impairment Charges

1,915

1,248

873

Northeast G And P [Member] | Appalachia Midstream Investments [Member]

Fair Value Assets Measured On Nonrecurring Basis [Abstract]

Impairment of equity-method investments

0

0

294

Fair Value, Measurements, Nonrecurring [Member] | Level 2 [Member] | Property, plant, and equipment, net [Member] | Other [Member]

Fair Value Assets Measured On Nonrecurring Basis [Abstract]

Fair value of property, plant, and equipment

[1]

$ 25

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

Fair Value Assets Measured On Nonrecurring Basis [Abstract]

Property Plant And Equipment And Intangibles, Fair Value Disclosure

$ 470

[2]

$ 439

[3]

470

[2]

Fair Value, Measurements, Nonrecurring [Member] | Level 3 [Member] | Property Plant And Equipment, Net And Intangible Assets, Net Of Accumulated Amortization [Member] | Northeast G And P [Member]

Fair Value Assets Measured On Nonrecurring Basis [Abstract]

Property Plant And Equipment And Intangibles, Fair Value Disclosure

[4]

21

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

Fair Value Assets Measured On Nonrecurring Basis [Abstract]

Fair value of property, plant, and equipment

[5]

$ 18

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

[6]

$ 18

$ 73

73

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

Fair Value Assets Measured On Nonrecurring Basis [Abstract]

Fair value of investment

$ 0

Fair Value, Measurements, Nonrecurring [Member] | Level 3 [Member] | Investments [Member] | Northeast G And P [Member]

Fair Value Assets Measured On Nonrecurring Basis [Abstract]

Fair value of investment

[8]

1,293

1,293

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

Fair Value Assets Measured On Nonrecurring Basis [Abstract]

Fair value of investment

1,295

[9]

1,294

[10]

1,295

[9]

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]

1,130

Impairment Of Certain Assets [Member]

Fair Value Assets Measured On Nonrecurring Basis [Abstract]

Impairment of certain assets

873

Other Asset Impairment Charges

1,915

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]

0

23

70

Impairment Of Certain Assets [Member] | Fair Value, Measurements, Nonrecurring [Member] | Level 2 [Member] | Other [Member]

Fair Value Assets Measured On Nonrecurring Basis [Abstract]

Impairment of certain assets

[1]

$ 66

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

Other Asset Impairment Charges

$ 1,225

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

Fair Value Assets Measured On Nonrecurring Basis [Abstract]

Impairment of certain assets

[5]

48

Other Asset Impairment Charges

1,849

[2]

1,019

[3]

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

[6]

$ 23

8

Impairment Of Certain Assets [Member] | Fair Value, Measurements, Nonrecurring [Member] | Level 3 [Member] | Northeast G And P [Member]

Fair Value Assets Measured On Nonrecurring Basis [Abstract]

Other Asset Impairment Charges

[4]

$ 115

Impairment Of Certain Assets [Member] | Fair Value, Measurements, Nonrecurring [Member] | Fair Value, Inputs, Level 1, 2 and 3 [Member]

Fair Value Assets Measured On Nonrecurring Basis [Abstract]

Other Asset Impairment Charges

1,915

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]

$ 747

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

Fair Value Assets Measured On Nonrecurring Basis [Abstract]

Impairment of equity-method investments

$ 32

$ 430

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

Fair Value Assets Measured On Nonrecurring Basis [Abstract]

Impairment of equity-method investments

3

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

Fair Value Assets Measured On Nonrecurring Basis [Abstract]

Impairment of equity-method investments

[8]

$ 32

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

Fair Value Assets Measured On Nonrecurring Basis [Abstract]

Impairment of equity-method investments

$ 318

[9]

$ 109

[10]

Measurement Input, Discount Rate [Member] | Fair Value, Measurements, Nonrecurring [Member] | Level 3 [Member] | Property Plant And Equipment, Net And Intangible Assets, Net Of Accumulated Amortization [Member] | West [Member]

Fair Value Assets Measured On Nonrecurring Basis [Abstract]

Property Plant And Equipment And Intangibles Fair Value Inputs

8.50%

10.20%

8.50%

Measurement Input, Discount Rate [Member] | Fair Value, Measurements, Nonrecurring [Member] | Level 3 [Member] | Property Plant And Equipment, Net And Intangible Assets, Net Of Accumulated Amortization [Member] | Northeast G And P [Member]

Fair Value Assets Measured On Nonrecurring Basis [Abstract]

Property Plant And Equipment And Intangibles Fair Value Inputs

11.10%

Measurement Input, Discount Rate [Member] | Fair Value, Measurements, Nonrecurring [Member] | Level 3 [Member] | Investments [Member] | Northeast G And P [Member] | Appalachia Midstream Investments [Member]

Fair Value Assets Measured On Nonrecurring Basis [Abstract]

Investments Fair Value Inputs

10.20%

10.20%

Measurement Input, Discount Rate [Member] | Fair Value, Measurements, Nonrecurring [Member] | Level 3 [Member] | Investments [Member] | WestAndNortheastGP [Member] | Minimum [Member]

Fair Value Assets Measured On Nonrecurring Basis [Abstract]

Investments Fair Value Inputs

13.00%

Measurement Input, Discount Rate [Member] | Fair Value, Measurements, Nonrecurring [Member] | Level 3 [Member] | Investments [Member] | WestAndNortheastGP [Member] | Maximum [Member]

Fair Value Assets Measured On Nonrecurring Basis [Abstract]

Investments Fair Value Inputs

13.30%

[1]

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

[2]

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

[3]

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

[4]

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

[5]

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

[6]

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

[7]

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

[8]

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

[9]

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

[10]

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

[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 3 – 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.

Fair Value Measurements Concent

Fair Value Measurements Concentration of Credit Risk (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Concentration Risk [Line Items]
Trade accounts and other receivables	$ 992	$ 976
NGLs, natural gas, and related products and services [Member]
Concentration Risk [Line Items]
Trade accounts and other receivables	626	760
Transportation of natural gas and related products [Member]
Concentration Risk [Line Items]
Trade accounts and other receivables	232	212
Other Receivable [Member]
Concentration Risk [Line Items]
Trade accounts and other receivables	134	4
Chesapeake Energy Corporation [Member] | Customer Concentration Risk [Member] | Accounts receivable [Member] | WestAndNortheastGP [Member]
Concentration Risk [Line Items]
Trade accounts and other receivables	$ 65	$ 176
Chesapeake Energy Corporation [Member] | Customer Concentration Risk [Member] | Sales Revenue, Net [Member]
Concentration Risk [Line Items]
Consolidated revenue, major customer, percentage	8.00%	10.00%	14.00%

Contingent Liabilities and Co_2

Contingent Liabilities and Commitments (Details) - USD ($) $ in Millions	May 20, 2016	Dec. 31, 2018
Loss Contingencies [Line Items]
Accrued environmental loss liabilities		$ 35
Capital Addition Purchase Commitments [Member]
Loss Contingencies [Line Items]
Commitments for construction and acquisition of property, plant, and equipment		480
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		6
Natural Gas Underground Storage Facilities [Member]
Loss Contingencies [Line Items]
Accrued environmental loss liabilities		7
Former Operations [Member]
Loss Contingencies [Line Items]
Accrued environmental loss liabilities		22
Maximum [Member] | Former Alaska Refinery [Member]
Loss Contingencies [Line Items]
Loss contingency, range of possible loss		$ 32

Segment Disclosures Geographic

Segment Disclosures Geographic Information (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Revenues from external customers:
Revenues from external customers	$ 8,686	$ 8,031	$ 7,499
United States [Member]
Revenues from external customers:
Revenues from external customers	8,686	8,030	7,425
Canada [Member]
Revenues from external customers:
Revenues from external customers	$ 0	$ 1	$ 74

Segment Disclosures Recon from

Segment Disclosures Recon from Segment to Consolidated - Revenues (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Segment revenues [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	$ 8,604
Sales revenue services commodity consideration	400	$ 0	$ 0
Total revenues	8,686	8,031	7,499
Other financial information:
Additions to long-lived assets	3,171	2,814	2,145
Proportional Modified Ebitda Equity Method Investments	770	795	754
Northeast G And P [Member]
Segment revenues [Line Items]
Sales revenue services commodity consideration	20
Atlantic Gulf [Member]
Segment revenues [Line Items]
Sales revenue services commodity consideration	59
West [Member]
Segment revenues [Line Items]
Sales revenue services commodity consideration	321
Other [Member]
Segment revenues [Line Items]
Sales revenue services commodity consideration	0
Intersegment Eliminations [Member]
Segment revenues [Line Items]
Total revenues	(488)	(518)	(536)
Other financial information:
Additions to long-lived assets	0	0	(1)
Proportional Modified Ebitda Equity Method Investments	0	0	0
Operating Segments [Member] | Northeast G And P [Member]
Segment revenues [Line Items]
Total revenues	1,283	1,163	1,032
Other financial information:
Additions to long-lived assets	477	460	223
Proportional Modified Ebitda Equity Method Investments	493	452	357
Operating Segments [Member] | Atlantic Gulf [Member]
Segment revenues [Line Items]
Total revenues	3,003	2,723	2,448
Other financial information:
Additions to long-lived assets	2,297	2,001	1,608
Proportional Modified Ebitda Equity Method Investments	183	264	287
Operating Segments [Member] | West [Member]
Segment revenues [Line Items]
Total revenues	4,854	4,259	3,708
Other financial information:
Additions to long-lived assets	361	321	223
Proportional Modified Ebitda Equity Method Investments	94	79	110
Operating Segments [Member] | Other [Member]
Segment revenues [Line Items]
Total revenues	34	404	847
Other financial information:
Additions to long-lived assets	36	32	92
Proportional Modified Ebitda Equity Method Investments	0	0	0
Service [Member]
Segment revenues [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	5,502	5,312	5,171
Service [Member] | Northeast G And P [Member]
Segment revenues [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	935	837	836
Service [Member] | Atlantic Gulf [Member]
Segment revenues [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	2,460	2,202	1,959
Service [Member] | West [Member]
Segment revenues [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	2,085	2,246	2,328
Service [Member] | Other [Member]
Segment revenues [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	22	27	48
Service [Member] | Intersegment Eliminations [Member]
Segment revenues [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	(102)	(83)	(84)
Sales revenue services commodity consideration	0
Service [Member] | Intersegment Eliminations [Member] | Northeast G And P [Member]
Segment revenues [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	41	35	34
Service [Member] | Intersegment Eliminations [Member] | Atlantic Gulf [Member]
Segment revenues [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	49	37	39
Service [Member] | Intersegment Eliminations [Member] | West [Member]
Segment revenues [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	0	0	0
Service [Member] | Intersegment Eliminations [Member] | Other [Member]
Segment revenues [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	12	11	11
Service [Member] | Operating Segments [Member] | Northeast G And P [Member]
Segment revenues [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	976	872	870
Service [Member] | Operating Segments [Member] | Atlantic Gulf [Member]
Segment revenues [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	2,509	2,239	1,998
Service [Member] | Operating Segments [Member] | West [Member]
Segment revenues [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	2,085	2,246	2,328
Service [Member] | Operating Segments [Member] | Other [Member]
Segment revenues [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	34	38	59
Product [Member]
Segment revenues [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	2,784	2,719	2,328
Product [Member] | Northeast G And P [Member]
Segment revenues [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	245	264	134
Product [Member] | Atlantic Gulf [Member]
Segment revenues [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	174	257	245
Product [Member] | West [Member]
Segment revenues [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	2,365	1,840	1,183
Product [Member] | Other [Member]
Segment revenues [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	0	358	766
Product [Member] | Intersegment Eliminations [Member]
Segment revenues [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	(386)	(435)	(452)
Product [Member] | Intersegment Eliminations [Member] | Northeast G And P [Member]
Segment revenues [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	42	27	28
Product [Member] | Intersegment Eliminations [Member] | Atlantic Gulf [Member]
Segment revenues [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	261	227	205
Product [Member] | Intersegment Eliminations [Member] | West [Member]
Segment revenues [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	83	173	197
Product [Member] | Intersegment Eliminations [Member] | Other [Member]
Segment revenues [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	0	8	22
Product [Member] | Operating Segments [Member] | Northeast G And P [Member]
Segment revenues [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	287	291	162
Product [Member] | Operating Segments [Member] | Atlantic Gulf [Member]
Segment revenues [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	435	484	450
Product [Member] | Operating Segments [Member] | West [Member]
Segment revenues [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	2,448	2,013	1,380
Product [Member] | Operating Segments [Member] | Other [Member]
Segment revenues [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	$ 0	$ 366	$ 788

Segment Disclosures Recon fro_2

Segment Disclosures Recon from Modified EBITDA to Net Income (Loss) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Segment Reporting Information [Line Items]
Service revenues	$ 8,604
Payments to Acquire Productive Assets	3,171	$ 2,814	$ 2,145
Reconciliation of Modified EBITDA to Net Income (Loss)
Modified EBITDA	3,388	3,466	3,322
Accretion expense associated with asset retirement obligations for nonregulated operations	(33)	(33)	(31)
Depreciation and amortization expenses	(1,725)	(1,736)	(1,763)
Equity earnings (losses)	396	434	397
Impairment of equity-method investments	(32)	0	(430)
Other investing income (loss) – net	219	282	63
Proportional Modified Ebitda Equity Method Investments	(770)	(795)	(754)
Interest Expense	(1,112)	(1,083)	(1,179)
(Provision) benefit for income taxes	(138)	1,974	25
Net income (loss)	193	2,509	(350)
Intersegment Eliminations [Member]
Segment Reporting Information [Line Items]
Payments to Acquire Productive Assets	0	0	(1)
Reconciliation of Modified EBITDA to Net Income (Loss)
Proportional Modified Ebitda Equity Method Investments	0	0	0
Operating Segments [Member] | Northeast G And P [Member]
Segment Reporting Information [Line Items]
Payments to Acquire Productive Assets	477	460	223
Reconciliation of Modified EBITDA to Net Income (Loss)
Modified EBITDA	1,086	819	853
Proportional Modified Ebitda Equity Method Investments	(493)	(452)	(357)
Operating Segments [Member] | Atlantic Gulf [Member]
Segment Reporting Information [Line Items]
Payments to Acquire Productive Assets	2,297	2,001	1,608
Reconciliation of Modified EBITDA to Net Income (Loss)
Modified EBITDA	2,023	1,238	1,621
Proportional Modified Ebitda Equity Method Investments	(183)	(264)	(287)
Operating Segments [Member] | West [Member]
Segment Reporting Information [Line Items]
Payments to Acquire Productive Assets	361	321	223
Reconciliation of Modified EBITDA to Net Income (Loss)
Modified EBITDA	308	412	1,544
Proportional Modified Ebitda Equity Method Investments	(94)	(79)	(110)
Operating Segments [Member] | Other [Member]
Segment Reporting Information [Line Items]
Payments to Acquire Productive Assets	36	32	92
Reconciliation of Modified EBITDA to Net Income (Loss)
Modified EBITDA	(29)	997	(696)
Proportional Modified Ebitda Equity Method Investments	0	0	0
Service [Member]
Segment Reporting Information [Line Items]
Service revenues	5,502	5,312	5,171
Service [Member] | Northeast G And P [Member]
Segment Reporting Information [Line Items]
Service revenues	935	837	836
Service [Member] | Atlantic Gulf [Member]
Segment Reporting Information [Line Items]
Service revenues	2,460	2,202	1,959
Service [Member] | West [Member]
Segment Reporting Information [Line Items]
Service revenues	2,085	2,246	2,328
Service [Member] | Other [Member]
Segment Reporting Information [Line Items]
Service revenues	22	27	48
Service [Member] | Intersegment Eliminations [Member]
Segment Reporting Information [Line Items]
Service revenues	(102)	(83)	(84)
Service [Member] | Intersegment Eliminations [Member] | Northeast G And P [Member]
Segment Reporting Information [Line Items]
Service revenues	41	35	34
Service [Member] | Intersegment Eliminations [Member] | Atlantic Gulf [Member]
Segment Reporting Information [Line Items]
Service revenues	49	37	39
Service [Member] | Intersegment Eliminations [Member] | West [Member]
Segment Reporting Information [Line Items]
Service revenues	0	0	0
Service [Member] | Intersegment Eliminations [Member] | Other [Member]
Segment Reporting Information [Line Items]
Service revenues	12	11	11
Service [Member] | Operating Segments [Member] | Northeast G And P [Member]
Segment Reporting Information [Line Items]
Service revenues	976	872	870
Service [Member] | Operating Segments [Member] | Atlantic Gulf [Member]
Segment Reporting Information [Line Items]
Service revenues	2,509	2,239	1,998
Service [Member] | Operating Segments [Member] | West [Member]
Segment Reporting Information [Line Items]
Service revenues	2,085	2,246	2,328
Service [Member] | Operating Segments [Member] | Other [Member]
Segment Reporting Information [Line Items]
Service revenues	$ 34	$ 38	$ 59

Segment Disclosures Recon fro_3

Segment Disclosures Recon from Segment to Consolidated - Assets and Investments (Details) - USD ($) $ in Millions		Dec. 31, 2018	Dec. 31, 2017
Segment Reporting, Asset Reconciling Item [Line Items]
Total assets		$ 45,302	$ 46,352
Equity-method investments		7,821	6,552
Northeast G And P [Member]
Segment Reporting, Asset Reconciling Item [Line Items]
Total assets		14,526	14,397
Atlantic Gulf [Member]
Segment Reporting, Asset Reconciling Item [Line Items]
Total assets		16,346	14,989
West [Member]
Segment Reporting, Asset Reconciling Item [Line Items]
Total assets		13,948	16,143
Other [Member]
Segment Reporting, Asset Reconciling Item [Line Items]
Total assets	[1]	849	1,449
Operating Segments [Member] | Northeast G And P [Member]
Segment Reporting, Asset Reconciling Item [Line Items]
Equity-method investments		5,319	5,307
Operating Segments [Member] | Atlantic Gulf [Member]
Segment Reporting, Asset Reconciling Item [Line Items]
Equity-method investments		776	823
Operating Segments [Member] | West [Member]
Segment Reporting, Asset Reconciling Item [Line Items]
Equity-method investments		1,726	422
Operating Segments [Member] | Other [Member]
Segment Reporting, Asset Reconciling Item [Line Items]
Equity-method investments		0	0
Intersegment Eliminations [Member]
Segment Reporting, Asset Reconciling Item [Line Items]
Total assets	[2]	(367)	(626)
Equity-method investments		$ 0	$ 0
[1]	(1)Decrease in Other is due primarily to a decreased cash balance.
[2]	(2)Eliminations primarily relate to the intercompany notes and accounts receivable generated by our cash management program.

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, 2018	Dec. 31, 2017	Dec. 31, 2016
Valuation And Qualifying Accounts
Beginning Balance	[1]	$ 224	$ 334	$ 190
Additions Charged (Credited) To Cost and Expenses		96	(110)	144
Additions Other		0	0	0
Deductions		0	0	0
Ending Balance	[1]	$ 320	$ 224	$ 334
[1]	Deducted from related assets.