DEFINITIONS

The following is a listing of certain abbreviations, acronyms, and other industry terminology that may be used throughout this Form 10-Q.

Measurements:

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

Bcf: One billion cubic feet of natural gas

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

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

~~Fahrenheit~~

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

Mbbls/d: One thousand barrels per day

Mdth/d: One thousand dekatherms per day

MMcf/d: One million cubic feet per day

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

MMdth/d: One million dekatherms per day

Tbtu: One trillion British thermal units

Consolidated Entities:

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

Constitution: Constitution Pipeline Company, LLC

Gulfstar One: Gulfstar One LLC

Northwest Pipeline: Northwest Pipeline LLC

Transco: Transcontinental Gas Pipe Line Company, LLC

UEOM: Utica East Ohio Midstream LLC, previously a Partially Owned Entity until acquiring remaining interest in March 2019

Northeast JV: Ohio Valley Midstream LLC, a partially owned venture that includes our Ohio Valley assets and UEOM

WPZ: Williams Partners L.P. Effective August 10, 2018, we completed our merger with WPZ, pursuant to which we acquired all outstanding common units of WPZ held by others and Williams continued as the surviving entity.

Partially Owned Entities: Entities in which we do not own a 100 percent ownership interest and which, as of September 30, ~~2018,~~2019, we account for as an equity-method investment, including principally the following:

Aux Sable: Aux Sable Liquid Products LP

Brazos Permian II: Brazos Permian II, LLC

Caiman II: Caiman Energy II, LLC

Discovery: Discovery Producer Services LLC

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

Jackalope: Jackalope Gas Gathering Services, L.L.C., which was sold in April 2019

Laurel Mountain: Laurel Mountain Midstream, LLC

OPPL: Overland Pass Pipeline Company LLC

RMM: Rocky Mountain Midstream Holdings LLC

~~UEOM:~~ ~~Utica East Ohio Midstream LLC~~

Government and Regulatory:

EPA: Environmental Protection Agency

FERC: Federal Energy Regulatory Commission

SEC: Securities and Exchange Commission

Other:

~~ETE Merger Agreement: Merger Agreement and Plan of Merger of Williams with Energy Transfer Equity, L.P and certain of its affiliates~~

Fractionation: The process by which a mixed stream of natural gas liquids is separated into constituent products, such as ethane, propane, and butane

GAAP: U.S. generally accepted accounting principles

~~IDR:~~ ~~Incentive distribution right~~

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

MVC: Minimum volume commitment

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

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

NGL margins:NGL revenues less any applicable Btu replacement cost, plant fuel, ~~and third-party~~ transportation, and fractionation

~~RGP Splitter:~~ ~~Refinery grade propylene splitter~~

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

WPZ Merger: The August 10, 2018, merger transactions pursuant to which we acquired all outstanding common units of WPZ held by others, merged WPZ into Williams, and Williams continued as the surviving entity

PART I – FINANCIAL INFORMATION

Item 1. Financial Statements

The Williams Companies, Inc.

Consolidated Statement of Income

(Unaudited)


	Three Months Ended September 30,						Nine Months Ended September 30,						Three Months Ended September 30,						Nine Months Ended September 30,
	2018			2017			2018			2017			2019			2018			2019			2018
	(Millions, except per-share amounts)												(Millions, except per-share amounts)
Revenues:
Service revenues	$	1,371		$	1,310		$	4,062		$	3,853		$	1,495		$	1,371		$	4,424		$	4,062
Service revenues – commodity consideration (Note 2)	121			—			316			—
Service revenues – commodity consideration													38			121			158			316
Product sales	811			581			2,104			1,950			466			811			1,512			2,104
Total revenues	2,303			1,891			6,482			5,803			1,999			2,303			6,094			6,482
Costs and expenses:
Product costs	790			504			2,039			1,620			434			790			1,442			2,039
Processing commodity expenses (Note 2)	30			—			91			—
Processing commodity expenses													19			30			83			91
Operating and maintenance expenses	389			403			1,134			1,166			364			389			1,091			1,134
Depreciation and amortization expenses	425			433			1,290			1,308			435			425			1,275			1,290
Selling, general, and administrative expenses	174			138			436			452			130			174			410			436
Gain on sale of Geismar Interest (Note 4)	—			(1,095		)	—			(1,095		)
Impairment of certain assets (Note 12)	—			1,210			66			1,236
Impairment of certain assets (Note 13)													—			—			76			66
Other (income) expense – net	(6		)	24			24			34			(11		)	(6		)	30			24
Total costs and expenses	1,802			1,617			5,080			4,721			1,371			1,802			4,407			5,080
Operating income (loss)	501			274			1,402			1,082			628			501			1,687			1,402
Equity earnings (losses)	105			115			279			347			93			105			260			279
Other investing income (loss) – net (Note 5)	2			4			74			278			(107		)	2			(54		)	74
Interest incurred	(286		)	(275		)	(856		)	(842		)	(303		)	(286		)	(915		)	(856		)
Interest capitalized	16			8			38			24			7			16			27			38
Other income (expense) – net	52			23			99			124			1			52			19			99
Income (loss) before income taxes	390			149			1,036			1,013			319			390			1,024			1,036
Provision (benefit) for income taxes	190			24			297			126			77			190			244			297
Net income (loss)	200			125			739			887			242			200			780			739
Less: Net income (loss) attributable to noncontrolling interests	71			92			323			400			21			71			54			323
Net income (loss) attributable to The Williams Companies, Inc.	129			33			416			487			221			129			726			416
Preferred stock dividends (Note 11)	—			—			—			—
Preferred stock dividends													1			—			2			—
Net income (loss) available to common stockholders	$	129		$	33		$	416		$	487		$	220		$	129		$	724		$	416
Amounts attributable to The Williams Companies, Inc.:
Basic earnings (loss) per common share:
Net income (loss)	$	.13		$	.04		$	.47		$	.59		$	.18		$	.13		$	.60		$	.47
Weighted-average shares (thousands)	1,023,587			826,779			893,706			825,925			1,212,270			1,023,587			1,211,938			893,706
Diluted earnings (loss) per common share:
Net income (loss)	$	.13		$	.04		$	.46		$	.59		$	.18		$	.13		$	.60		$	.46
Weighted-average shares (thousands)	1,026,504			829,368			896,322			828,150			1,214,165			1,026,504			1,213,943			896,322
Cash dividends declared per common share	$	.34		$	.30		$	1.02		$	.90

See accompanying notes.

The Williams Companies, Inc.

Consolidated Statement of Comprehensive Income

(Unaudited)


	Three Months Ended September 30,						Nine Months Ended September 30,						Three Months Ended September 30,						Nine Months Ended September 30,
	2018			2017			2018			2017			2019			2018			2019			2018
	(Millions)												(Millions)
Net income (loss)	$	200		$	125		$	739		$	887		$	242		$	200		$	780		$	739
Other comprehensive income (loss):
Cash flow hedging activities:
Net unrealized gain (loss) from derivative instruments, net of taxes of $3 and $6 in 2018, and $2 and $1 in 2017	(5		)	(9		)	(19		)	(5		)
Reclassifications into earnings of net derivative instruments (gain) loss, net of taxes of ($2) and ($3) in 2018, and $1 and $1 in 2017	7			2			10			—
Net unrealized gain (loss) from derivative instruments, net of taxes of $3 and $6 in 2018													—			(5		)	—			(19		)
Reclassifications into earnings of net derivative instruments (gain) loss, net of taxes of ($2) and ($3) in 2018													—			7			—			10
Pension and other postretirement benefits:
Amortization of prior service cost (credit) included in net periodic benefit cost (credit), net of taxes of $1 and $2 in 2017	—			—			—			(2		)
Net actuarial gain (loss) arising during the year, net of taxes of ($0) and ($1) in 2018	—			—			4			—
Amortization of actuarial (gain) loss and net actuarial loss from settlements included in net periodic benefit cost (credit), net of taxes of ($3) and ($5) in 2018, and ($2) and ($7) in 2017	4			4			14			13
Net actuarial gain (loss) arising during the year, net of taxes of $1 and $1 in 2019, and ($0) and ($1) in 2018													(5		)	—			(5		)	4
Amortization of actuarial (gain) loss and net actuarial loss from settlements included in net periodic benefit cost (credit), net of taxes of ($0) and ($3) in 2019, and ($3) and ($5) in 2018													4			4			9			14
Other comprehensive income (loss)	6			(3		)	9			6			(1		)	6			4			9
Comprehensive income (loss)	206			122			748			893			241			206			784			748
Less: Comprehensive income (loss) attributable to noncontrolling interests	72			89			321			398			21			72			54			321
Comprehensive income (loss) attributable to The Williams Companies, Inc.	$	134		$	33		$	427		$	495		$	220		$	134		$	730		$	427

See accompanying notes.

The Williams Companies, Inc.

Consolidated Balance Sheet

(Unaudited)


	September 30, 2018			December 31, 2017			September 30, 2019			December 31, 2018
	(Millions, except per-share amounts)						(Millions, except per-share amounts)
ASSETS
Current assets:
Cash and cash equivalents	$	42		$	899		$	247		$	168
Trade accounts and other receivables (net of allowance of $9 at September 30, 2018 and $9 at December 31, 2017)	883			976
Trade accounts and other receivables (net of allowance of $6 at September 30, 2019 and $9 at December 31, 2018)							875			992
Inventories	153			113			129			130
Assets held for sale (Note 4)	664			7
Other current assets and deferred charges	242			184			183			174
Total current assets	1,984			2,179			1,434			1,464
Investments	7,427			6,552			6,228			7,821
Property, plant, and equipment	39,953			39,513			41,647			38,661
Accumulated depreciation and amortization	(11,279		)	(11,302		)	(12,034		)	(11,157		)
Property, plant, and equipment – net	28,674			28,211			29,613			27,504
Intangible assets – net of accumulated amortization	8,324			8,791			8,041			7,767
Regulatory assets, deferred charges, and other	744			619			965			746
Total assets	$	47,153		$	46,352		$	46,281		$	45,302
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable	$	739		$	978		$	602		$	662
Liabilities held for sale (Note 4)	49			—
Accrued liabilities	1,117			1,167			1,184			1,102
Commercial paper	823			—
Long-term debt due within one year	33			501			1,538			47
Total current liabilities	2,761			2,646			3,324			1,811
Long-term debt	21,409			20,434			20,719			22,367
Deferred income tax liabilities	1,648			3,147			1,651			1,524
Regulatory liabilities, deferred income, and other	4,376			3,950			3,728			3,603
Contingent liabilities (Note 13)
Contingent liabilities (Note 14)
Equity:
Stockholders’ equity:
Preferred stock (Note 11)	35			—
Common stock ($1 par value; 1,470 million shares authorized at September 30, 2018 and 960 million shares authorized at December 31, 2017; 1,245 million shares issued at September 30, 2018 and 861 million shares issued at December 31, 2017)	1,245			861
Preferred stock							35			35
Common stock ($1 par value; 1,470 million shares authorized at September 30, 2019 and December 31, 2018; 1,247 million shares issued at September 30, 2019 and 1,245 million shares issued at December 31, 2018)							1,247			1,245
Capital in excess of par value	24,680			18,508			24,310			24,693
Retained deficit	(9,018		)	(8,434		)	(10,664		)	(10,002		)
Accumulated other comprehensive income (loss)	(291		)	(238		)	(266		)	(270		)
Treasury stock, at cost (35 million shares of common stock)	(1,041		)	(1,041		)	(1,041		)	(1,041		)
Total stockholders’ equity	15,610			9,656			13,621			14,660
Noncontrolling interests in consolidated subsidiaries	1,349			6,519			3,238			1,337
Total equity	16,959			16,175			16,859			15,997
Total liabilities and equity	$	47,153		$	46,352		$	46,281		$	45,302

See accompanying notes.

The Williams Companies, Inc.

Consolidated Statement of Changes in Equity

(Unaudited)

The Williams Companies, Inc., Stockholders

Preferred
Stock
Common
Stock
Capital in
Excess of
Par Value

Retained
Deficit
AOCI*
Treasury
Stock

Total
Stockholders’
Equity

Noncontrolling
Interests
Total Equity
(Millions)
Balance – December 31, 2017 $ —
$ 861
$ 18,508
$ (8,434 ) $ (238 ) $ (1,041 ) $ 9,656
$ 6,519
$ 16,175
Adoption of ASC 606 (Note 1) —
—
—
(84 ) —
—
(84 ) (37 ) (121 )
Adoption of ASU 2018-02 (Note 1) —
—
—
61
(61 ) —
—
—
—
Net income (loss) —
—
—
416
—
—
416
323
739
Other comprehensive income (loss) —
—
—
—
11
—
11
(2 ) 9
WPZ Merger (Note 1) —
382
6,112
—
(3 ) —
6,491
(4,629 ) 1,862
Issuance of preferred stock (Note 11) 35
—
—
—
—
—
35
—
35
Cash dividends – common stock —
—
—
(974 ) —
—
(974 ) —
(974 )
Dividends and distributions to noncontrolling interests —
—
—
—
—
—
—
(598 ) (598 )
Stock-based compensation and related common stock issuances —
1
48
—
—
—
49
—
49
Sales of limited partner units of Williams Partners L.P. —
—
—
—
—
—
—
46
46
Changes in ownership of consolidated subsidiaries, net —
—
14
—
—
—
14
(18 ) (4 )
Contributions from noncontrolling interests —
—
—
—
—
—
—
13
13
Deconsolidation of subsidiary (Note 3) —
—
—
—
—
—
—
(267 ) (267 )
Other —
1
(2 ) (3 ) —
—
(4 ) (1 ) (5 )
Net increase (decrease) in equity 35
384
6,172
(584 ) (53 ) —
5,954
(5,170 ) 784
Balance – September 30, 2018 $ 35
$ 1,245
$ 24,680
$ (9,018 ) $ (291 ) $ (1,041 ) $ 15,610
$ 1,349
$ 16,959



	The Williams Companies, Inc. Stockholders
	Preferred Stock		Common Stock		Capital in Excess of Par Value			Retained Deficit			AOCI*			Treasury Stock			Total Stockholders’ Equity			Noncontrolling Interests			Total Equity
	(Millions)
Balance – June 30, 2019	$	35	$	1,246	$	24,296		$	(10,423	)	$	(265	)	$	(1,041	)	$	13,848		$	3,233		$	17,081
Net income (loss)	—		—		—			221			—			—			221			21			242
Other comprehensive income (loss)	—		—		—			—			(1		)	—			(1		)	—			(1		)
Cash dividends – common stock ($0.38 per share)	—		—		—			(461		)	—			—			(461		)	—			(461		)
Dividends and distributions to noncontrolling interests	—		—		—			—			—			—			—			(18		)	(18		)
Stock-based compensation and related common stock issuances, net of tax	—		1		16			—			—			—			17			—			17
Changes in ownership of consolidated subsidiaries, net (Note 2)	—		—		(1		)	—			—			—			(1		)	2			1
Other	—		—		(1		)	(1		)	—			—			(2		)	—			(2		)
Net increase (decrease) in equity	—		1		14			(241		)	(1		)	—			(227		)	5			(222		)
Balance – September 30, 2019	$	35	$	1,247	$	24,310		$	(10,664	)	$	(266	)	$	(1,041	)	$	13,621		$	3,238		$	16,859



Balance – June 30, 2018	$	—	$	862	$	18,552		$	(8,735	)	$	(293	)	$	(1,041	)	$	9,345		$	6,102		$	15,447
Net income (loss)	—		—		—			129			—			—			129			71			200
Other comprehensive income (loss)	—		—		—			—			5			—			5			1			6
WPZ Merger (Note 1)	—		382		6,112			—			(3		)	—			6,491			(4,629		)	1,862
Issuance of preferred stock (Note 12)	35		—		—			—			—			—			35			—			35
Cash dividends – common stock ($0.34 per share)	—		—		—			(411		)	—			—			(411		)	—			(411		)
Dividends and distributions to noncontrolling interests	—		—		—			—			—			—			—			(196		)	(196		)
Stock-based compensation and related common stock issuances, net of tax	—		—		16			—			—			—			16			—			16
Changes in ownership of consolidated subsidiaries, net	—		—		1			—			—			—			1			(1		)	—
Contributions from noncontrolling interests	—		—		—			—			—			—			—			2			2
Other	—		1		(1		)	(1		)	—			—			(1		)	(1		)	(2		)
Net increase (decrease) in equity	35		383		6,128			(283		)	2			—			6,265			(4,753		)	1,512
Balance – September 30, 2018	$	35	$	1,245	$	24,680		$	(9,018	)	$	(291	)	$	(1,041	)	$	15,610		$	1,349		$	16,959

See accompanying notes.

The Williams Companies, Inc.

Consolidated Statement of Changes in Equity (Continued)

(Unaudited)



	The Williams Companies, Inc. Stockholders
	Preferred Stock		Common Stock		Capital in Excess of Par Value			Retained Deficit			AOCI*			Treasury Stock			Total Stockholders’ Equity			Noncontrolling Interests			Total Equity
	(Millions)
Balance – December 31, 2018	$	35	$	1,245	$	24,693		$	(10,002	)	$	(270	)	$	(1,041	)	$	14,660		$	1,337		$	15,997
Net income (loss)	—		—		—			726			—			—			726			54			780
Other comprehensive income (loss)	—		—		—			—			4			—			4			—			4
Cash dividends – common stock ($1.14 per share)	—		—		—			(1,382		)	—			—			(1,382		)	—			(1,382		)
Dividends and distributions to noncontrolling interests	—		—		—			—			—			—			—			(86		)	(86		)
Stock-based compensation and related common stock issuances, net of tax	—		2		43			—			—			—			45			—			45
Sale of partial interest in consolidated subsidiary (Note 2)	—		—		—			—			—			—			—			1,333			1,333
Changes in ownership of consolidated subsidiaries, net (Note 2)	—		—		(426		)	—			—			—			(426		)	568			142
Contributions from noncontrolling interests	—		—		—			—			—			—			—			32			32
Other	—		—		—			(6		)	—			—			(6		)	—			(6		)
Net increase (decrease) in equity	—		2		(383		)	(662		)	4			—			(1,039		)	1,901			862
Balance – September 30, 2019	$	35	$	1,247	$	24,310		$	(10,664	)	$	(266	)	$	(1,041	)	$	13,621		$	3,238		$	16,859



Balance – December 31, 2017	$	—	$	861	$	18,508		$	(8,434	)	$	(238	)	$	(1,041	)	$	9,656		$	6,519		$	16,175
Adoption of new accounting standards	—		—		—			(23		)	(61		)	—			(84		)	(37		)	(121		)
Net income (loss)	—		—		—			416			—			—			416			323			739
Other comprehensive income (loss)	—		—		—			—			11			—			11			(2		)	9
WPZ Merger (Note 1)	—		382		6,112			—			(3		)	—			6,491			(4,629		)	1,862
Issuance of preferred stock (Note 12)	35		—		—			—			—			—			35			—			35
Cash dividends – common stock ($1.02 per share)	—		—		—			(974		)	—			—			(974		)	—			(974		)
Dividends and distributions to noncontrolling interests	—		—		—			—			—			—			—			(598		)	(598		)
Stock-based compensation and related common stock issuances, net of tax	—		1		48			—			—			—			49			—			49
Sales of limited partner units of Williams Partners L.P.	—		—		—			—			—			—			—			46			46
Changes in ownership of consolidated subsidiaries, net	—		—		14			—			—			—			14			(18		)	(4		)
Contributions from noncontrolling interests	—		—		—			—			—			—			—			13			13
Deconsolidation of subsidiary (Note 5)	—		—		—			—			—			—			—			(267		)	(267		)
Other	—		1		(2		)	(3		)	—			—			(4		)	(1		)	(5		)
Net increase (decrease) in equity	35		384		6,172			(584		)	(53		)	—			5,954			(5,170		)	784
Balance – September 30, 2018	$	35	$	1,245	$	24,680		$	(9,018	)	$	(291	)	$	(1,041	)	$	15,610		$	1,349		$	16,959


*	Accumulated Other Comprehensive Income (Loss)

See accompanying notes.

The Williams Companies, Inc.

Consolidated Statement of Cash Flows

(Unaudited)


	Nine Months Ended September 30,						Nine Months Ended September 30,
	2018			2017			2019			2018
	(Millions)						(Millions)
OPERATING ACTIVITIES:
Net income (loss)	$	739		$	887		$	780		$	739
Adjustments to reconcile to net cash provided (used) by operating activities:
Depreciation and amortization	1,290			1,308			1,275			1,290
Provision (benefit) for deferred income taxes	351			99			268			351
Equity (earnings) losses	(279		)	(347		)	(260		)	(279		)
Distributions from unconsolidated affiliates	507			602			458			507
Net (gain) loss on disposition of equity-method investments	—			(269		)
Gain on sale of Geismar Interest (Note 4)	—			(1,095		)
Impairment of and net (gain) loss on sale of assets	64			1,225
Net (gain) loss on disposition of equity-method investments (Note 5)							(122		)	—
Impairment of equity-method investments (Note 13)							186			—
(Gain) loss on deconsolidation of businesses (Note 5)							2			(62		)
Impairment of and net (gain) loss on sale of certain assets							76			64
Amortization of stock-based awards	43			61			44			43
Cash provided (used) by changes in current assets and liabilities:
Accounts and notes receivable	75			118			159			75
Inventories	(39		)	(23		)	7			(39		)
Other current assets and deferred charges	(44		)	(11		)	(10		)	(44		)
Accounts payable	(76		)	47			(76		)	(76		)
Accrued liabilities	(62		)	(161		)	76			(62		)
Other, including changes in noncurrent assets and liabilities	(238		)	(210		)	(161		)	(176		)
Net cash provided (used) by operating activities	2,331			2,231			2,702			2,331
FINANCING ACTIVITIES:
Proceeds from (payments of) commercial paper – net	821			(93		)	(4		)	821
Proceeds from long-term debt	3,745			3,013			736			3,745
Payments of long-term debt	(3,201		)	(5,475		)	(904		)	(3,201		)
Proceeds from issuance of common stock	15			2,130			10			15
Proceeds from sale of partial interest in consolidated subsidiary (Note 2)							1,330			—
Common dividends paid	(974		)	(744		)	(1,382		)	(974		)
Dividends and distributions paid to noncontrolling interests	(552		)	(636		)	(86		)	(552		)
Contributions from noncontrolling interests	13			15			32			13
Payments for debt issuance costs	(26		)	(14		)	—			(26		)
Other – net	(46		)	(87		)	(11		)	(46		)
Net cash provided (used) by financing activities	(205		)	(1,891		)	(279		)	(205		)
INVESTING ACTIVITIES:
Property, plant, and equipment:
Capital expenditures (1)	(2,659		)	(1,700		)	(1,705		)	(2,659		)
Dispositions – net	(2		)	(27		)	(32		)	(2		)
Contributions in aid of construction	395			253			25			395
Proceeds from sale of businesses, net of cash divested	—			2,056
Proceeds from dispositions of equity-method investments	—			200
Purchases of businesses, net of cash acquired (Note 2)							(728		)	—
Proceeds from dispositions of equity-method investments (Note 5)							485			—
Purchases of and contributions to equity-method investments	(803		)	(103		)	(361		)	(803		)
Other – net	86			(17		)	(28		)	86
Net cash provided (used) by investing activities	(2,983		)	662			(2,344		)	(2,983		)
Increase (decrease) in cash and cash equivalents	(857		)	1,002			79			(857		)
Cash and cash equivalents at beginning of year	899			170			168			899
Cash and cash equivalents at end of period	$	42		$	1,172		$	247		$	42
_____________
(1) Increases to property, plant, and equipment	$	(2,482	)	$	(1,826	)	$	(1,707	)	$	(2,482	)
Changes in related accounts payable and accrued liabilities	(177		)	126			2			(177		)
Capital expenditures	$	(2,659	)	$	(1,700	)	$	(1,705	)	$	(2,659	)

See accompanying notes.

The Williams Companies, Inc.

Notes to Consolidated Financial Statements

(Unaudited)

Note 1 – General, Description of Business, and Basis of Presentation

General

Our accompanying interim consolidated financial statements do not include all the notes in our annual financial statements and, therefore, should be read in conjunction with the consolidated financial statements and notes thereto for the year ended December 31, ~~2017,~~2018, in ~~Exhibit 99.1 of~~ our Annual Report on Form ~~8-K dated May 3, 2018.~~10-K. The accompanying unaudited financial statements include all normal recurring adjustments and others that, in the opinion of management, are necessary to present fairly our interim financial statements.

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

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 ~~non-cash~~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~~Sheet. Pursuant to its distribution reinvestment program, WPZ had issued 1,230,657 common units to the public in 2018 associated with reinvested distributions of $46 million.

~~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. 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 ~~principally~~ in the United ~~States. Prior to~~States and are presented within the ~~WPZ Merger, we had one~~following reportable ~~segment, Williams Partners. Beginning in the third-quarter 2018,~~segments: Northeast G&P, Atlantic-Gulf, and West, consistent with the manner in which our chief operating decision maker evaluates performance and allocates ~~resources, our operations~~resources. All remaining business activities as well as corporate activities 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.~~

~~Notes (Continued)~~

included in Other.

Northeast G&P is comprised of our midstream gathering, processing, and ~~processing~~fractionation 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~~including 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,~~as well as a 69 percent equity-method investment in Laurel Mountain Midstream, LLC (Laurel Mountain), a 58 percent equity-method investment in Caiman Energy II, LLC, 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). Northeast G&P includes a 65 percent interest in Ohio Valley Midstream LLC (Northeast JV) (a consolidated entity). The Northeast JV includes our Ohio Valley assets and Utica East Ohio Midstream LLC (UEOM), a former equity-method investment in which we acquired the remaining ownership interest in March 2019 (see Note 2 – Acquisitions).

Notes (Continued)

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., a 60 percent equity-method investment in Discovery Producer Services LLC, and a 41 percent interest in Constitution Pipeline Company, LLC (Constitution) (a consolidated entity), which is developing a pipeline project (see Note 34 – Variable Interest Entities)~~, and a 60 percent equity-method investment in Discovery Producer Services LLC.~~.

West is comprised of our interstate natural gas pipeline, Northwest Pipeline LLC (Northwest Pipeline), and our gathering, processing, and treating operations in ~~New Mexico,~~ Colorado, ~~and~~ Wyoming, ~~as well as~~ the Barnett Shale region of north-central Texas, the Eagle Ford Shale region of south Texas, the Permian Shale region of west Texas, the Haynesville Shale region of northwest Louisiana, and the Mid-Continent region which includes the Anadarko ~~Arkoma, Delaware,~~ and ~~Permian~~Arkoma 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 Company LLC, a 50 percent equity-method investment in Rocky Mountain Midstream Holdings LLC, and a 15 percent equity-method investment in Brazos Permian II, LLC (Brazos Permian II). West also included our former natural gas gathering and processing assets in the Four Corners area of New Mexico and Colorado, which were sold during the fourth quarter of 2018, and our former 50 percent interest in Jackalope Gas Gathering Services, L.L.C. (Jackalope) (an equity-method investment following deconsolidation as of June 30, 2018), ~~a 43 percent equity-method investment~~which was sold in Rocky Mountain Midstream Holdings LLC (RMM), and our previously owned 50 percent equity-method investment in the Delaware basin gas gathering system (DBJV) in the Mid-Continent region (see Note 5 – Investing Activities).

All remaining business activities, 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) (see Note 4 – Divestitures and Assets Held for Sale), as well as corporate activities, are included in Other.April 2019.

Basis of Presentation

Significant risks and uncertainties

We ~~may monetize assets~~believe that ~~are not core to our strategy which could result in impairments~~the carrying value of certain ~~equity-method investments,~~of our property, plant, and equipment and other identifiable intangible ~~assets. Such impairments could potentially~~assets, notably certain acquired assets accounted for as business combinations between 2012 and 2014, may be ~~caused by indications~~in excess of current fair value. However, the carrying value ~~implied through the monetization process or,~~of these assets, in ~~the case~~our judgment, continues to be recoverable based on our evaluation of ~~asset dispositions that are part of a broader asset group, the impact of the loss of~~undiscounted future ~~estimated~~ cash flows.

~~Proposition 112~~

On November 6, 2018, citizens of Colorado will vote on Proposition 112, a ballot measure that could significantly increase setback distances from occupied structures or other vulnerable areas, as defined or designated, for any new oil and gas development in the state, critically restricting or banning such activities. If the measure is approved, it could still be subject to modification or amendment by the Colorado legislature. An unfavorable outcome could adversely impact the operations, and ultimately the value, of our businesses and investments in Colorado, notably our recent investment in RMM (see Note 5 – Investing Activities).

~~FERC Income Tax Policy Revision~~

On March 15, 2018, the Federal Energy Regulatory Commission (FERC) issued a revised policy statement (the March 15 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

~~Notes (Continued)~~

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 March 15 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. Further, 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 the 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 the reduction in the corporate income tax in Tax Reform is already addressed in its settlement.

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~~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 ~~interstate natural gas pipelines~~assumptions and ultimately result in impairments of these assets. Such transactions or developments may ~~be adversely impacted.~~also indicate that certain of our equity-method investments have experienced other-than-temporary declines in value, which could result in impairment, or that the fair value of the reporting unit for our goodwill is less than its carrying amount, which would result in impairment.

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, the tax effects of items within accumulated other comprehensive income may not reflect 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.~~

~~Notes (Continued)~~

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 Accounting Standards Codification (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.

Effective January 1, 2018, we adopted ASU 2017-07 “Compensation - Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost” (ASU 2017-07). ASU 2017-07 requires employers to report the service cost component of net benefit cost in the same line item or items as other compensation costs arising from employee services. The other components of net benefit cost must be presented in the income statement separately from the service cost component and outside ~~Operating income (loss)~~. Only the service cost component is now eligible for capitalization when applicable. The presentation aspect of ASU 2017-07 must be applied retrospectively and the capitalization requirement prospectively. In ~~accordance with this adoption, we have conformed the prior year presentation, which resulted in increases of $3 million and $9 million to~~ ~~Operating and maintenance expenses~~ ~~with corresponding decreases to~~ ~~Operating income (loss)~~ ~~and increases of $3 million and $9 million to~~ ~~Other income (expense) – net~~ ~~below~~ ~~Operating income (loss)~~ ~~in the~~ ~~Consolidated Statement of Incomefor the three- and nine-month periods ended September 30, 2017, respectively.~~

Effective January 1, 2018, we adopted ASU 2016-15 “Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments” (ASU 2016-15). Among other things, ASU 2016-15 permits an accounting policy election to classify distributions received from equity-method investees using either the cumulative earnings approach or the nature of distribution approach. We have elected to apply the nature of distribution approach and have retrospectively conformed the prior year presentation within the ~~Consolidated Statement of Cash Flowsin accordance with ASU 2016-15. For the period ended September 30, 2017, amounts previously presented as~~ ~~Distributions from unconsolidated affiliates in excess of cumulative earnings~~ ~~within~~ ~~Investing Activities~~ ~~are now presented as part of~~ ~~Distributions from unconsolidated affiliates~~ ~~within~~ ~~Operating Activities, resulting in an increase to~~ ~~Net cash provided (used) by operating activities~~ ~~of $394 million with a corresponding reduction in~~ ~~Net cash provided (used) by investing activities~~.

~~In May 2014,~~February 2016, the Financial Accounting Standards Board (FASB) issued ASU 2014-09 establishing ASC Topic 606, “Revenue from Contracts with Customers” (ASC 606). ASC 606 establishes a comprehensive new revenue recognition model designed to depict the transfer of goods or services to a customer in an amount that reflects the consideration the entity expects to be entitled to receive in exchange for those goods or services and requires significantly enhanced revenue disclosures. In August 2015, the FASB issued ASU 2015-14 “Revenue from Contracts with Customers (Topic 606): Deferral of the Effective Date” (ASU 2015-14). Per ASU 2015-14, the standard 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

~~Notes (Continued)~~

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~~Standards Update (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~~prior 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~~are 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~~Accounting Standards Codification (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

Notes (Continued)

practical expedient that permits lessors to not separate ~~non-lease~~nonlease 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 ~~will adopt~~prospectively adopted ASU 2016-02 effective January 1, ~~2019.~~2019, and did not adjust prior periods as permitted by ASU 2018-11 (see Note 10 – Leases).

We ~~are in the process of finalizing~~completed our review of contracts to identify leases based on the modified definition of a lease and ~~identifying~~implemented 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. ~~While we are still in the process of completing our implementation evaluation of ASU 2016-02, we currently believe the~~The most significant changes to our financial statements as a result of adopting ASU 2016-02 relate to the recognition of a $225 million lease liability and offsetting right-of-use asset in our Consolidated Balance Sheetfor operating leases. We ~~are~~ also ~~evaluating~~evaluated ASU 2016-02’s available practical expedients on adoption and have generally elected to adopt the practical expedients, which includes the practical expedient to not separate lease and nonlease components by both lessees and lessors by class of underlying assets and the land easements practical expedient.

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 us for interim and annual periods beginning after December 15, 2019. We plan to adopt as of January 1, 2020. We anticipate that ASU 2016-13 will primarily apply to our trade receivables. While we ~~generally~~do not expect a significant financial impact, we have analyzed our historical credit loss experience and continue to ~~elect.~~develop and implement processes, procedures, and internal controls in order to make the necessary credit loss assessments and required disclosures upon adoption.

Note 2 – Acquisitions

UEOM

As of December 31, 2018, we owned a 62 percent interest in UEOM which we accounted for as an equity-method investment. On March 18, 2019, we signed and closed the acquisition of the remaining 38 percent interest in UEOM. Total consideration paid, including post-closing adjustments, was $741 million in cash funded through credit facility borrowings and cash on hand. As a result of acquiring this additional interest, we obtained control of and now consolidate UEOM.

UEOM is involved primarily in the processing and fractionation of natural gas and natural gas liquids in the Utica Shale play in eastern Ohio. The purpose of the acquisition is to enhance our position in the region. We expect synergies through common ownership of UEOM and our Ohio Valley midstream systems to create a more efficient platform for capital spending in the region, resulting in reduced operating and maintenance expenses and creating enhanced capabilities and benefits for producers in the area.

The acquisition of UEOM was accounted for as a business combination, which requires, among other things, that identifiable assets acquired and liabilities assumed be recognized at their acquisition date fair values. In March 2019, based on the transaction price for our purchase of the remaining interest in UEOM as finalized just prior to the acquisition, we recognized a $74 million noncash impairment loss related to our existing 62 percent interest (see Note 13 – Fair Value Measurements and Guarantees). Thus, there was 0 gain or loss on remeasuring our existing equity-method investment to fair value due to the impairment recognized just prior to closing the acquisition of the additional interest.

The valuation techniques used to measure the acquisition date fair value of the UEOM acquisition consisted of the market approach for our previous equity-method investment in UEOM and the income approach (excess earnings method) for valuation of intangible assets and depreciated replacement costs for property, plant, and equipment.

The following table presents the allocation of the acquisition date fair value of the major classes of the assets acquired, which are presented in the Northeast G&P segment, and liabilities assumed at March 18, 2019. The net assets

Notes (Continued)

acquired reflect the sum of the consideration transferred and the noncash elimination of the fair value of our existing equity-method investment upon our acquisition of the additional interest. The fair value of accounts receivable acquired, presented in current assets in the table, equals contractual amounts receivable. After the March 31, 2019 financial statements were issued, we received an updated valuation report from a third-party valuation firm. Significant changes from the preliminary allocation disclosed in the first quarter to the final allocation reflect an increase of $169 million in goodwill, and decreases of $106 million in property, plant, and equipment and $61 million in other intangible assets.



	(Millions)
Current assets, including $13 million cash acquired	$	55
Property, plant, and equipment	1,387
Other intangible assets	328
Total identifiable assets acquired	1,770

Current liabilities	7
Total liabilities assumed	7

Net identifiable assets acquired	1,763

Goodwill	188
Net assets acquired	$	1,951

The goodwill recognized in the acquisition relates primarily to enhancing and diversifying our basin positions and is reported within the Northeast G&P segment. Substantially all of the goodwill is expected to be deductible for tax purposes. Goodwill is included within Intangible assets – net of accumulated amortization in the Consolidated Balance Sheet and represents the excess of the consideration, plus the fair value of any previously held equity interest, over the fair value of the net assets acquired. It is not subject to amortization but is evaluated annually as of October 1 for impairment or more frequently if impairment indicators are present that would indicate it is more likely than not that the fair value of the reporting unit is less than its carrying amount.

Other intangible assets recognized in the acquisition are related to contractual customer relationships from gas gathering, processing, and fractionation agreements with our customers. The basis for determining the value of these intangible assets is estimated future net cash flows to be derived from acquired contractual customer relationships discounted using a risk-adjusted discount rate. These intangible assets are being amortized on a straight-line basis over an initial period of 20 years which represents the term over which the contractual customer relationships are expected to contribute to our cash flows. Approximately 49 percent of the expected future revenues from these contractual customer relationships are impacted by our ability and intent to renew or renegotiate existing customer contracts. We expense costs incurred to renew or extend the terms of our gas gathering, processing, and fractionation contracts with customers. Based on the estimated future revenues during the current contract periods (as estimated at the time of the acquisition), the weighted-average period prior to the next renewal or extension of the existing contractual customer relationships is approximately 10 years.

The following unaudited pro forma Revenues and Net income (loss) attributable to The Williams Companies, Inc. for the three and nine months ended September 30, 2019 and 2018, are presented as if the UEOM acquisition had been completed on January 1, 2018. These pro forma amounts are not necessarily indicative of what the actual results would have been if the acquisition had in fact occurred on the date or for the periods indicated, nor do they purport to project Revenues or Net income (loss) attributable to The Williams Companies, Inc. for any future periods or as of any date. These amounts do not give effect to any potential cost savings, operating synergies, or revenue enhancements to result from the transaction or the potential costs to achieve these cost savings, operating synergies, and revenue enhancements.

Notes (Continued)



	Three Months Ended September 30,				Nine Months Ended September 30,
	2019		2018		2019		2018
	(Millions)
Revenues	$	1,999	$	2,342	$	6,126	$	6,589

Net income (loss) attributable to The Williams Companies, Inc.	$	221	$	138	$	804	$	434

Adjustments to pro forma Net income (loss) attributable to The Williams Companies, Inc. include the removal of the previously described $74 million impairment loss recognized in March 2019 just prior to the acquisition. There are no pro forma adjustments for the three months ended September 30, 2019 as UEOM was consolidated and reflected in our results during the entire quarter.

During the period from the acquisition date of March 18, 2019 to September 30, 2019, UEOM contributed Revenues of $104 million and Net income (loss) attributable to The Williams Companies, Inc. of $25 million.

Costs related to this acquisition are $4 million and are reported within our Northeast G&P segment and included in Selling, general, and administrative expenses in our Consolidated Statement of Income.

Northeast JV

Concurrent with the UEOM acquisition, we executed an agreement whereby we contributed our consolidated interests in UEOM and our Ohio Valley midstream business to a newly formed partnership. In June 2019, our partner invested approximately $1.33 billion (subject to post-closing adjustments) for a 35 percent ownership interest, and we retained 65 percent ownership of, as well as operate and consolidate, the Northeast JV business. The change in ownership due to this transaction increased Noncontrolling interests in consolidated subsidiaries by $568 million, and decreased Capital in excess of par value by $426 million and Deferred income tax liabilities by $142 million in the Consolidated Balance Sheet. Costs related to this transaction are $6 million and are reported within our Northeast G&P segment and included in Selling, general, and administrative expenses in our Consolidated Statement of Income.

Notes (Continued)

Note 23 – Revenue Recognition

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. "Regulated Operations" (Topic 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 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 interstate natural gas pipeline businesses, which are included within the caption “Regulated interstate natural gas transportation and storage” in the revenue by category table below and 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 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:

Guaranteed 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;

~~Notes (Continued)~~

Interruptible transportation and storage under interruptible transportation and storage contracts—an integrated package of services typically constituting a single performance obligation, which includes receiving, transporting or storing (as applicable), and redelivering commodities upon nomination by the customer.

In situations where 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 at the completion of the integrated package of services which represents a single 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 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 midstream businesses, which are included in the caption titled “Non-regulated gathering, processing, transportation, and storage” in the revenue by category table below, 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 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 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. 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 it

~~Notes (Continued)~~

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.

~~Notes (Continued)~~

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		Northeast Midstream		Atlantic- Gulf Midstream		West Midstream		Transco		Northwest Pipeline		Other		Intercompany Eliminations			Total
																		(Millions)
Three Months Ended September 30, 2019																		Three Months Ended September 30, 2019
Revenues from contracts with customers:
Service revenues:
Non-regulated gathering, processing, transportation, and storage:
Monetary consideration																		$	310	$	117	$	308	$	—	$	—	$	—	$	(19	)	$	716
Commodity consideration																		1		7		30		—		—		—		—			38
Regulated interstate natural gas transportation and storage																		—		—		—		601		111		—		(2		)	710
Other																		38		8		12		—		—		—		(5		)	53
Total service revenues																		349		132		350		601		111		—		(26		)	1,517
Product Sales:
NGL and natural gas product sales																		30		34		391		41		—		—		(28		)	468
Total revenues from contracts with customers																		379		166		741		642		111		—		(54		)	1,985
Other revenues (1)																		5		2		—		3		—		7		(3		)	14
Total revenues																		$	384	$	168	$	741	$	645	$	111	$	7	$	(57	)	$	1,999
	(Millions)
Three Months Ended September 30, 2018	Three Months Ended September 30, 2018																	Three Months Ended September 30, 2018
Revenues from contracts with customers:
Service revenues:
Non-regulated gathering, processing, transportation, and storage:
Monetary consideration	$	219	$	139	$	409	$	—	$	—	$	1	$	(19	)	$	749	$	219	$	139	$	409	$	—	$	—	$	1	$	(19	)	$	749
Commodity consideration	5		19		97		—		—		—		—			121		5		19		97		—		—		—		—			121
Regulated interstate natural gas transportation and storage	—		—		—		457		110		—		(1		)	566		—		—		—		457		110		—		(1		)	566
Other	23		4		11		—		—		—		(4		)	34		23		4		11		—		—		—		(4		)	34
Total service revenues	247		162		517		457		110		1		(24		)	1,470		247		162		517		457		110		1		(24		)	1,470
Product Sales:
NGL and natural gas	69		88		720		41		—		—		(117		)	801		69		88		720		41		—		—		(117		)	801
Other	—		—		12		—		—		—		(3		)	9		—		—		12		—		—		—		(3		)	9
Total product sales	69		88		732		41		—		—		(120		)	810		69		88		732		41		—		—		(120		)	810
Total revenues from contracts with customers	316		250		1,249		498		110		1		(144		)	2,280		316		250		1,249		498		110		1		(144		)	2,280
Other revenues (1)	6		5		3		3		—		9		(3		)	23		6		5		3		3		—		9		(3		)	23
Total revenues	$	322	$	255	$	1,252	$	501	$	110	$	10	$	(147	)	$	2,303	$	322	$	255	$	1,252	$	501	$	110	$	10	$	(147	)	$	2,303

Nine Months Ended September 30, 2018
Revenues from contracts with customers:
Service revenues:
Non-regulated gathering, processing, transportation, and storage:
Monetary consideration	$	626	$	404	$	1,231	$	—	$	—	$	2	$	(55	)	$	2,208
Commodity consideration	14		45		257		—		—		—		—			316
Regulated interstate natural gas transportation and storage	—		—		—		1,368		330		—		(2		)	1,696
Other	65		12		35		1		—		—		(10		)	103
Total service revenues	705		461		1,523		1,369		330		2		(67		)	4,323
Product Sales:
NGL and natural gas	242		232		1,799		96		—		—		(285		)	2,084
Other	—		—		20		—		—		—		(4		)	16
Total product sales	242		232		1,819		96		—		—		(289		)	2,100
Total revenues from contracts with customers	947		693		3,342		1,465		330		2		(356		)	6,423
Other revenues (1)	16		14		6		8		—		24		(9		)	59
Total revenues	$	963	$	707	$	3,348	$	1,473	$	330	$	26	$	(365	)	$	6,482

Notes (Continued)



	Northeast Midstream		Atlantic- Gulf Midstream		West Midstream		Transco		Northwest Pipeline		Other		Intercompany Eliminations			Total
	(Millions)
Nine Months Ended September 30, 2019
Revenues from contracts with customers:
Service revenues:
Non-regulated gathering, processing, transportation, and storage:
Monetary consideration	$	840	$	366	$	1,007	$	—	$	—	$	—	$	(54	)	$	2,159
Commodity consideration	9		33		116		—		—		—		—			158
Regulated interstate natural gas transportation and storage	—		—		—		1,736		335		—		(4		)	2,067
Other	104		21		32		1		—		—		(12		)	146
Total service revenues	953		420		1,155		1,737		335		—		(70		)	4,530
Product Sales:
NGL and natural gas product sales	114		140		1,300		88		—		—		(132		)	1,510
Total revenues from contracts with customers	1,067		560		2,455		1,825		335		—		(202		)	6,040
Other revenues (1)	15		6		12		8		—		22		(9		)	54
Total revenues	$	1,082	$	566	$	2,467	$	1,833	$	335	$	22	$	(211	)	$	6,094

Nine Months Ended September 30, 2018
Revenues from contracts with customers:
Service revenues:
Non-regulated gathering, processing, transportation, and storage:
Monetary consideration	$	626	$	404	$	1,231	$	—	$	—	$	2	$	(55	)	$	2,208
Commodity consideration	14		45		257		—		—		—		—			316
Regulated interstate natural gas transportation and storage	—		—		—		1,368		330		—		(2		)	1,696
Other	65		12		35		1		—		—		(10		)	103
Total service revenues	705		461		1,523		1,369		330		2		(67		)	4,323
Product Sales:
NGL and natural gas	242		232		1,799		96		—		—		(285		)	2,084
Other	—		—		20		—		—		—		(4		)	16
Total product sales	242		232		1,819		96		—		—		(289		)	2,100
Total revenues from contracts with customers	947		693		3,342		1,465		330		2		(356		)	6,423
Other revenues (1)	16		14		6		8		—		24		(9		)	59
Total revenues	$	963	$	707	$	3,348	$	1,473	$	330	$	26	$	(365	)	$	6,482

(1)

~~Service revenues~~ ~~in our Consolidated Statement~~Revenues not within the scope of ~~Income include~~ASC 606, “Revenue from Contracts with Customers,” consist of 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~~equity-method investments, which are reported in Service revenues ~~and the management fees do not constitute revenue from contracts with customers.~~ ~~Product sales~~ in our Consolidated Statement of Income, ~~include~~and amounts associated with our derivative contracts, ~~that~~which are ~~not within the scope~~reported in Product sales in our Consolidated Statement of ~~ASC 606.~~Income.

Notes (Continued)

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.~~

The following table presents a reconciliation of our contract assets:



	Three Months Ended September 30,				Nine Months Ended September 30,
	2019		2018		2019			2018
	(Millions)
Balance at beginning of period	$	17	$	39	$	4		$	4
Revenue recognized in excess of amounts invoiced	14		17		53			53
Minimum volume commitments invoiced	—		—		(26		)	(1		)
Balance at end of period	$	31	$	56	$	31		$	56

Quarter-to-Date September 30, 2018 Year-to-Date September 30, 2018
(Millions)
Balance at beginning of period $ 39
$ 4
Revenue recognized in excess of cash received 17
53
Minimum volume commitments invoiced —
(1 )
Balance at end of period $ 56
$ 56

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 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.

The following table presents a reconciliation of our contract liabilities:



	Three Months Ended September 30,						Nine Months Ended September 30,
	2019			2018			2019			2018
	(Millions)
Balance at beginning of period	$	1,331		$	1,535		$	1,397		$	1,596
Payments received and deferred	12			58			138			269
Deconsolidation of Jackalope interest (Note 5)	—			—			—			(52		)
Significant financing component	3			4			10			11
Recognized in revenue	(77		)	(112		)	(276		)	(339		)
Balance at end of period	$	1,269		$	1,485		$	1,269		$	1,485

Quarter-to-Date September 30, 2018 Year-to-Date September 30, 2018
(Millions)
Balance at beginning of period $ 1,535
$ 1,596
Payments received and deferred 62
280
Deconsolidation of Jackalope interest (Note 3) —
(52 )
Recognized in revenue (112 ) (339 )
Balance at end of period $ 1,485
$ 1,485

~~Notes (Continued)~~

The following table presents the amount of the contract liabilities balance as of September 30, 2018, expected to be recognized as revenue in each of the next five years as performance obligations are expected to be satisfied:

(Millions)
2018 (remainder) $ 191
2019 257
2020 129
2021 110
2022 103
2023 100
Thereafter 595
Total $ 1,485

Remaining Performance Obligations

~~The following table presents the transaction price allocated to the remaining~~Remaining performance obligations ~~under certain contracts as of September 30, 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 onfor our gas pipeline firm transportation contracts with customers, ~~as well as~~ storage capacity ~~contracts. Amounts included in the table below for~~contracts, long-term contracts containing minimum volume commitments associated with our midstream businesses, and fixed payments associated with offshore production handling. For our interstate natural gas pipeline businesses, remaining performance obligations reflect the rates for such services in our current ~~FERC~~Federal Energy Regulatory Commission (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 isare not currently known. ~~As a~~

Our remaining performance obligations exclude variable consideration, including contracts with variable consideration for which we have elected the practical expedient ~~permitted by ASC 606, this table excludes variable~~for consideration ~~as well as consideration in contracts that is~~ recognized in revenue as billed. It also excludes consideration received prior to September 30, 2018, that will be recognized in future periods (see above for Contract Liabilities and the expected recognition of those amounts within revenue). As noted above, certainCertain 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 September 30, ~~2018,~~2019, do not consider potential future performance obligations for which the renewal has not been ~~exercised. The table below also does not include~~exercised and excludes contracts with customers for which the underlying facilities have not received FERC authorization to be placed into service.

(Millions)
2018 (remainder) $ 624
2019 2,465
2020 2,274
2021 2,106
2022 1,830
2023 1,650
Thereafter 12,471
Total $ 23,420

~~The table above excludes~~ Consideration received prior to September 30, 2019, that will be recognized in future periods is also excluded from our remaining performance obligations ~~associated with~~and is instead reflected in contract liabilities.

The following table presents the ~~Atlantic Sunrise expansion project for which we received FERC authorization~~amount of the contract liabilities balance as of September 30, 2019, expected to ~~place into service in October 2018. We anticipate annual~~be recognized as revenue as performance obligations are satisfied and the transaction price allocated to the remaining performance obligations under certain contracts as of ~~approximately $420 million associated with Atlantic Sunrise over the term of the contracts.~~September 30, 2019.

Notes (Continued)



	Contract Liabilities		Remaining Performance Obligations
	(Millions)
2019 (remainder)	$	70	$	762
2020	167		3,028
2021	126		2,873
2022	112		2,705
2023	103		2,244
Thereafter	691		19,840
Total	$	1,269	$	31,452

Accounts Receivable

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.

~~Notes (Continued)~~

The following is a summary of our Trade accounts and other receivables~~as it relates to contracts with customers:~~:



	September 30, 2019		December 31, 2018
	(Millions)
Accounts receivable related to revenues from contracts with customers	$	791	$	858
Other accounts receivable	84		134
Total reflected in Trade accounts and other receivables	$	875	$	992

September 30, 2018 January 1, 2018
(Millions)
Accounts receivable related to revenues from contracts with customers $ 795
$ 958
Other accounts receivable 88
18
Total reflected in Trade accounts and other receivables
$ 883
$ 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)
Consolidated Statement of Income
Three Months Ended September 30, 2018
Service revenues $ 1,371
$ 5
$ 1,376
Service revenues – commodity consideration 121
(121 ) —
Product sales 811
44
855
Total revenues 2,303
(72 ) 2,231
Product costs 790
(48 ) 742
Processing commodity expenses 30
(30 ) —
Depreciation and amortization expenses 425
1
426
Total costs and expenses 1,802
(77 ) 1,725
Operating income (loss) 501
5
506
Interest incurred (286 ) 4
(282 )
Interest capitalized 16
(2 ) 14
Income (loss) before income taxes 390
7
397
Provision (benefit) for income taxes 190
1
191
Net income (loss) 200
6
206
Less: Net income (loss) attributable to noncontrolling interests 71
(1 ) 70
Net income (loss) attributable to The Williams Companies, Inc. 129
7
136
Basic earnings (loss) per common share $ 0.13
$ 0.01
$ 0.14
Diluted earnings (loss) per common share $ 0.13
$ 0.01
$ 0.14

Nine Months Ended September 30, 2018
Service revenues $ 4,062
$ 16
$ 4,078
Service revenues – commodity consideration 316
(316 ) —
Product sales 2,104
86
2,190
Total revenues 6,482
(214 ) 6,268
Product costs 2,039
(143 ) 1,896
Processing commodity expenses 91
(91 ) —
Operating and maintenance expenses 1,134
3
1,137
Depreciation and amortization expenses 1,290
2
1,292
Total costs and expenses 5,080
(229 ) 4,851

~~Notes (Continued)~~

As Reported Adjustments resulting from adoption of ASC 606 Balance without adoption of ASC 606
(Millions)
Operating income (loss) $ 1,402
$ 15
$ 1,417
Equity earnings (losses) 279
1
280
Other investing income (loss) - net 74
(9 ) 65
Interest incurred (856 ) 11
(845 )
Interest capitalized 38
(6 ) 32
Income (loss) before income taxes 1,036
12
1,048
Provision (benefit) for income taxes 297
1
298
Net income (loss) 739
11
750
Net income (loss) attributable to The Williams Companies, Inc. 416
11
427
Basic earnings (loss) per common share $ 0.47
$ 0.01
$ 0.48
Diluted earnings (loss) per common share $ 0.46
$ 0.01
$ 0.47

Consolidated Statement of Comprehensive Income
Three Months Ended September 30, 2018
Net income (loss) $ 200
$ 6
$ 206
Comprehensive income (loss) 206
6
212
Less: Comprehensive income (loss) attributable to noncontrolling interests 72
(1 ) 71
Comprehensive income (loss) attributable to The Williams Companies, Inc. 134
7
141

Nine Months Ended September 30, 2018
Net income (loss) $ 739
$ 11
$ 750
Comprehensive income (loss) 748
11
759
Comprehensive income (loss) attributable to The Williams Companies, Inc. 427
11
438

Consolidated Balance Sheet
September 30, 2018
Inventories $ 153
$ (8 ) $ 145
Other current assets and deferred charges 242
(53 ) 189
Total current assets 1,984
(61 ) 1,923
Investments 7,427
(1 ) 7,426
Property, plant, and equipment 39,953
(6 ) 39,947
Property, plant, and equipment – net 28,674
(6 ) 28,668
Intangible assets – net of accumulated amortization 8,324
63
8,387
Regulatory assets, deferred charges, and other 744
(4 ) 740
Total assets 47,153
(9 ) 47,144
Deferred income tax liabilities 1,648
27
1,675
Regulatory liabilities, deferred income, and other 4,376
(159 ) 4,217
Retained deficit (9,018 ) 95
(8,923 )
Total stockholders’ equity 15,610
95
15,705
Noncontrolling interests in consolidated subsidiaries $ 1,349
$ 28
$ 1,377
Total equity 16,959
123
17,082
Total liabilities and equity 47,153
(9 ) 47,144

~~Notes (Continued)~~

As Reported Adjustments resulting from adoption of ASC 606 Balance without adoption of ASC 606
(Millions)
Consolidated Statement of Changes in Equity
September 30, 2018
Adoption of ASC 606 $ (121 ) $ 121
$ —
Net income (loss) 739
11
750
Deconsolidation of subsidiary (267 ) (9 ) (276 )
Net increase (decrease) in equity 784
123
907
Balance at September 30, 2018 16,959
123
17,082

Note 34 – Variable Interest Entities

Consolidated VIEs

As of September 30, ~~2018,~~2019, we consolidate the following variable interest entities (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~~which will extend from Susquehanna County, Pennsylvania, to the Iroquois Gas Transmission and the Tennessee Gas Pipeline ~~systems. The~~systems in New York. While we previously estimated the total remaining cost of the project ~~is estimated~~ to be approximately $740 million, ~~which~~this amount is expected to increase and the revised estimate is being developed. The project costs 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~~but 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~~upholding 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.denial. Constitution filed a petition for rehearing with the Second Circuit Court of Appeals, but in October 2017 the court denied our petition.

Notes (Continued)

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. InBy orders issued in January 2018 and July 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.~~

~~Notes (Continued)~~

~~The project’s sponsors remain committed to the project, and in September 2018~~Thereafter, we ~~filed a petition with~~petitioned the D.C. Circuit for review of the FERC’s decision. ~~An unfavorable resolution could result~~In November 2018, the D.C. Circuit granted a motion filed by the FERC to hold our appeal in abeyance pending a decision by the court in the ~~impairment~~Hoopa Valley Tribe v. FERC case. In January 2019, the D.C. Circuit issued its decision in Hoopa Valley Tribe, finding that the applicant’s withdrawal and resubmission of a ~~significant portion~~Clean Water Act Section 401 water quality certification request did not trigger new statutory periods of review for the state agencies, which resulted in the state agencies waiving their Section 401 authority regarding the hydropower project in question. As a result of the Hoopa Valley Tribe decision, the FERC filed a motion for voluntary remand of our appeal, and in February 2019, the D.C. Circuit granted the motion, sending our waiver case back to the FERC to determine whether or not NYSDEC waived its authority under Section 401.

On August 28, 2019, the FERC issued an order finding that NYSDEC waived its water quality certification authority under Section 401 with respect to Constitution. The FERC interpreted the Hoopa Valley Tribe decision to stand for the general principle that where an applicant withdraws and resubmits an application for water quality certification for the purpose of avoiding Section 401’s one-year time limit, and the state agency does not act within one year of the receipt of the original application, the state agency has “failed or refused to act under Section 401” and, therefore, has waived its Section 401 authority.

The equity partners are evaluating the next steps in connection with advancing the project.

At September 30, 2019, capitalized project costs total $376 million, of which ~~total $377 million on a consolidated basis at September 30, 2018,~~we have funded our proportionate share, and are included within Property, plant, and equipment 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 a66 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.

Northeast JV

As a result of the June 2019 sale of a 35 percent interest in the Northeast JV (see Note 2 – Acquisitions), we now own a 65 percent interest in the Northeast JV, a subsidiary that is a VIE due to certain of our voting rights being disproportionate to our obligation to absorb losses and substantially all of the Northeast JV’s activities being performed on our behalf. We are the primary beneficiary because we have the power to direct the activities that most significantly impact the Northeast JV’s economic performance. The Northeast JV provides midstream services for producers in the Marcellus Shale and Utica Shale regions. Future expansion activity is expected to be funded with capital contributions from us and the other equity partner on a proportional basis.

Notes (Continued)

The following table presents amounts included in our Consolidated Balance Sheet that are only for the use or obligation of our consolidated VIEs:



	September 30, 2019			December 31, 2018
	(Millions)
Assets (liabilities):
Cash and cash equivalents	$	90		$	33
Trade accounts and other receivables – net	152			62
Other current assets and deferred charges	5			2
Property, plant, and equipment – net	6,167			2,363
Intangible assets – net of accumulated amortization	2,697			1,177
Regulatory assets, deferred charges, and other	13			—
Accounts payable	(54		)	(15		)
Accrued liabilities	(100		)	(115		)
Regulatory liabilities, deferred income, and other	(268		)	(264		)

September 30,
2018
December 31, 2017 (1)

Classification

(Millions)

Assets (liabilities):

Cash and cash equivalents $ 32
$ 881

Cash and cash equivalents
Trade accounts and other receivables – net
57
972
Trade accounts and other receivables
Inventories —
113
Inventories
Other current assets 1
176
Other current assets and deferred charges
Investments —
6,552
Investments
Property, plant, and equipment – net
2,398
27,912

Property, plant, and equipment – net
Intangible assets – net
1,189
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 (16 ) (957 )
Accounts payable
Accrued liabilities including current asset retirement obligations (98 ) (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 (104 ) (944 ) Regulatory liabilities, deferred income, and other
Regulatory liabilities, deferred income, and other noncurrent liabilities (189 ) (2,809 )
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, and Basis of Presentation~~).

Nonconsolidated VIEs

Jackalope

~~We own~~At December 31, 2018, we owned a50 percent interest in Jackalope, which provides gathering and processing services for the Powder River basin and iswas a VIE due to certain risks shared with customers. ~~Prior to the second quarter of 2018~~In April 2019, we ~~were the primary beneficiary of Jackalope. During the second quarter of 2018, the scope of Jackalope’s planned future activities changed,~~

~~Notes (Continued)~~

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 forsold our interest ~~using the equity method of accounting as we exert significant influence over the financial and operational policies of~~in Jackalope for $485 million in cash (see Note 5 – Investing Activities).

Brazos Permian II

We own a 15 percent interest in Brazos Permian II, 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 September 30, ~~2018,~~2019, the carrying value of our equity-method investment in ~~Jackalope~~Brazos Permian II was ~~$316~~$197 million. Our maximum exposure to loss is limited to the carrying value of our investment. ~~Jackalope is undertaking an expansion project that is estimated to cost up to approximately $400 million, which will be funded on a proportional basis.~~

~~Note 4 – Divestitures and Assets Held for Sale~~

~~Divestment of Four Corners Assets~~

On October 1, 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, of which a $113 million deposit was received in the third quarter. At September 30, 2018, these assets were designated as held for sale within the West segment. As a result of this sale, we expect to record a gain of approximately $0.6 billion in the fourth quarter of 2018.

~~The following table presents the carrying amounts of the major classes of the Four Corners area assets and liabilities, which are presented within~~ ~~Assets held for sale~~ ~~and~~ ~~Liabilities held for sale~~ ~~in the Consolidated Balance Sheet:~~

Carrying Amount
September 30, 2018
(Millions)
Assets:
Current assets $ 23
Property, plant, and equipment – net 539
Other noncurrent assets 12
$ 574

Liabilities:
Current liabilities $ 22
Other noncurrent liabilities 23
$ 45

~~The following table presents the results of operations for the Four Corners area:~~

Three Months Ended September 30, Nine Months Ended September 30,
2018 2017 2018 2017
(Millions)
Income (loss) before income taxes of Four Corners area $ 25
$ 14
$ 52
$ 31
Income (loss) before income taxes of Four Corners area attributable to The Williams Companies, Inc. 23
10
43
23

~~Other Assets Held for Sale~~

Certain assets and operations from our former petchem services are designated as held for sale within the Atlantic-Gulf and Other segments as of September 30, 2018. Included as part of the disposal group and presented within ~~Assets held for sale~~ ~~and~~ ~~Liabilities held for sale~~ ~~in the Consolidated Balance Sheet, are Current assets and Property, plant, and equipment - net, of approximately $2 million and $84 million, respectively, and Current liabilities and Noncurrent~~

~~Notes (Continued)~~

~~liabilities of approximately $1 million and $3 million, respectively.~~ ~~Assets held for sale~~ ~~also includes certain other insignificant assets unrelated to these disposal groups.~~

~~Divestment 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 our 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. Proceeds were also used to fund a portion of the capital and investment expenditures that were a part of our growth portfolio.

~~The following table presents the results of operations for the Geismar Interest, excluding the gain noted above:~~

Three Months Ended September 30, Nine Months Ended September 30,
2018 2017 2018 2017
(Millions)
Income (loss) before income taxes of the Geismar Interest $ —
$ 1
$ —
$ 26
Income (loss) before income taxes of the Geismar Interest attributable to The Williams Companies, Inc. —
1
—
19

Note 5 – Investing Activities

~~RMM Equity-Method Investment~~The following table presents certain items reflected in Other investing income (loss) – netin the Consolidated Statement of Income:

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 is expected to increase to 50 percent as we provide additional capital contributions. At September 30, 2018, our carrying value was $569 million reflecting our 43 percent economic ownership. We are committed to fund up to an additional $177 million to reach 50 percent economic ownership, to the extent RMM needs funding for capital expenditures. We account for this investment under the equity method of accounting.



	Three Months Ended September 30,					Nine Months Ended September 30,
	2019			2018		2019			2018
	(Millions)
Impairment of equity-method investments (Note 13)	$	(114	)	$	—	$	(186	)	$	—
Gain (loss) on deconsolidation of businesses	—			—		(2		)	62
Gain on disposition of equity-method investments	—			—		122			—
Other	7			2		12			12
Other investing income (loss) – net	$	(107	)	$	2	$	(54	)	$	74

Jackalope Deconsolidation

During the second quarter of 2018, we deconsolidated our 50 percent interest in ~~Jackalope (see Note 3 – Variable Interest Entities).~~Jackalope. 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 Income~~.

Notes (Continued)

$62 million. 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~~Sale of ~~Additional Interests in Appalachia Midstream Investments~~Jackalope

~~During the first quarter of 2017,~~In April 2019, we ~~exchanged all of~~sold our 50 percent equity-method interest in ~~DBJV~~Jackalope for ~~an increased interest in two natural gas gathering systems that are part of the Appalachia Midstream Investments and $155~~$485 million in ~~cash. This transaction was recorded based~~cash, resulting in a gain on ~~our estimate~~the disposition 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$122 million.

Notes (Continued)

~~sold all of our interest in Ranch Westex JV LLC 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 Income~~.

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.

Note 6 – Other Income and Expenses

The following table presents, by segment, certain ~~gains or losses reflected in~~ ~~Other (income) expense – net~~ ~~within~~ ~~Costs and expenses~~ other items included in our Consolidated Statement of Income:



	Three Months Ended September 30,						Nine Months Ended September 30,
	2019			2018			2019			2018
	(Millions)
Selling, general, and administrative expenses
Other
Charitable contribution of preferred stock to The Williams Companies Foundation, Inc. (see Note 12)	$	—		$	35		$	—		$	35
WPZ Merger costs	—			15			—			19

Other (income) expense – net within Costs and expenses
Atlantic-Gulf
Amortization of regulatory assets associated with asset retirement obligations	1			8			17			24
Net accrual (amortization) of regulatory liability related to overcollection of certain employee expenses	(9		)	5			(11		)	16
Adjustments to regulatory liabilities related to tax reform	—			—			—			(10		)
Amortization of regulatory liability associated with tax reform	(12		)	—			(19		)	—
Reversal of expenditures previously capitalized	—			—			10			—
Gain on asset retirement	—			(10		)	—			(10		)

West
Adjustments to regulatory liabilities related to tax reform	—			—			—			(7		)
Regulatory charge per approved rates related to tax reform	6			6			18			18
Charge for regulatory liability associated with the decrease in Northwest Pipeline’s estimated deferred state income tax rates following WPZ Merger	—			12			—			12

Other
Change to (benefit of) regulatory asset associated with Transco’s estimated deferred state income tax rate following WPZ Merger	—			(37		)	12			(37		)

Other income (expense) – net below Operating income (loss)
Atlantic-Gulf
Allowance for equity funds used during construction	9			32			21			78

Other
Income associated with a regulatory asset related to deferred taxes on equity funds used during construction	3			19			7			28
Net loss associated with early retirement of debt	—			—			—			(7		)

Three Months Ended
September 30, Nine Months Ended
September 30,
2018 2017 2018 2017
(Millions)
Atlantic-Gulf
Amortization of regulatory assets associated with asset retirement obligations $ 8
$ 8
$ 24
$ 25
Accrual of regulatory liability related to overcollection of certain employee expenses 5
5
16
16
Project development costs related to Constitution (see Note 3) 1
4
4
12
Adjustments to regulatory liability related to Tax Reform —
—
(10 ) —
Gain on asset retirement (10 ) (5 ) (10 ) (5 )
West
Gains on contract settlements and terminations —
—
—
(15 )
Adjustments to regulatory liability related to Tax Reform —
—
(7 ) —
Regulatory charge per approved rates related to Tax Reform 6
—
18
—
Charge for regulatory liability associated with the decrease in Northwest Pipeline’s estimated deferred state income tax rates following WPZ Merger 12
—
12
—
Other
Benefit of regulatory asset associated with increase in Transco’s estimated deferred state income tax rate following WPZ Merger (37 ) —
(37 ) —
Gain on sale of Refinery Grade Propylene Splitter —
—
—
(12 )

~~Additional Items~~

~~Certain additional items included~~In conjunction with a previously announced organizational realignment and considering asset sales in ~~the~~ ~~Consolidated Statement of Income~~recent years, we are ~~as follows:~~

~~Selling, general,~~evaluating our cost structure and ~~administrative~~have implemented a voluntary separation program (VSP) for certain eligible employees. Operating and maintenance expenses for the three and nine months ended September 30, ~~2018 includes a $35~~2019, reflect charges of $7 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 11 – Stockholders’ Equity.) and $30 million, respectively, and Selling, general, and administrative expenses for the three and

Notes (Continued)

nine months ended September 30, 2019, reflect charges of $3 million and $23 million, respectively, for estimated severance and related costs, primarily associated with the VSP. The severance and related costs by segment are as follows:



	Three Months Ended September 30,			Nine Months Ended September 30,
	2019
	(Millions)
Northeast G&P	$	(3	)	$	7
Atlantic-Gulf	11			30
West	2			16
Total	$	10		$	53

Note 7 – Provision (Benefit) for Income Taxes

The Provision (benefit) for income taxes includes:



	Three Months Ended September 30,						Nine Months Ended September 30,
	2019			2018			2019			2018
	(Millions)
Current:
Federal	$	(10	)	$	(19	)	$	(25	)	$	(55	)
State	—			—			—			1
Foreign	1			—			1			—
	(9		)	(19		)	(24		)	(54		)
Deferred:
Federal	73			188			225			312
State	13			21			43			39
	86			209			268			351
Provision (benefit) for income taxes	$	77		$	190		$	244		$	297

The effective income tax rates for the total provision for the three and nine months ended September 30, ~~2018 also includes $15 million and $19 million, respectively, for WPZ Merger related costs within~~2019, are greater than the ~~Other segment.~~ ~~Selling, general, and administrative expenses~~ ~~for~~federal statutory rate, primarily due to the ~~three and nine months ended September 30, 2017 includes $5 million and $18 million, respectively,~~effect of ~~severance and other related costs within the Other segment.~~

~~Other~~state income ~~(expense) – net~~ ~~below~~ ~~Operating income (loss)~~ ~~includes income of $33 million and $80 million for the three and nine months ended September 30, 2018, respectively, and $17 million and $55 million for~~

~~Notes (Continued)~~

~~the three and nine months ended September 30, 2017, respectively, for allowance for equity funds used during construction primarily within the Atlantic-Gulf segment.~~ ~~Other income (expense) – net~~ ~~below~~ ~~Operating income (loss)~~ also includes income of $22 million and $31 million for the three and nine months ended September 30, 2018, respectively, and $8 million and $44 million for the three and nine months ended September 30, 2017, respectively of income associated with a regulatory asset related to deferred taxes on equity funds used during construction. These items are reported primarily within the Other segment.

~~Other income (expense) – net~~ ~~below~~ ~~Operating income (loss)~~ for the nine months ended September 30, 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. (See Note 10 – Debt and Banking Arrangements.) ~~Other income (expense) – net~~ ~~below~~ ~~Operating income (loss)~~ for the three months ended September 30, 2017 includes 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 loss for the July 3, 2017 early retirement reflects $54 million in premiums paid, offset by $51 million of unamortized premium. For the nine months ended September 30, 2017, ~~Other income (expense) – net~~ ~~below~~ ~~Operating income (loss)~~ also includes a net gain of $30 million associated with the February 23, 2017, early retirement of $750 million of 6.125 percent senior unsecured notes that were due in 2022. The net gain within the Other segment reflects $53 million of unamortized premium, partially offset by $23 million in premiums paid.

~~Note 7 – Provision (Benefit) for Income Taxes~~

~~The~~ ~~Provision (benefit) for income taxes~~ ~~includes:~~

Three Months Ended
September 30, Nine Months Ended
September 30,
2018 2017 2018 2017
(Millions)
Current:
Federal $ (19 ) $ 7
$ (55 ) $ 10
State —
9
1
17
(19 ) 16
(54 ) 27
Deferred:
Federal 188
(11 ) 312
63
State 21
19
39
36
209
8
351
99
Provision (benefit) for income taxes $ 190
$ 24
$ 297
$ 126
taxes.

The effective income tax rates for the total provision for the three and nine months ended September 30, 2018, are higher than the federal statutory rate primarily due to the effect of state income taxes and a $105 million valuation allowance associated with foreign tax credits, that expire between 2024 and 2027. This is partially offset by the impact of the allocation of income to nontaxable noncontrolling interests. The state income tax provisions include a $38 million provision related to an increase in the deferred state income tax rate (net of federal benefit) partially offset by a net decrease in valuation allowances of $31 million on state net operating losses, both primarily driven by the impact that the completion of the WPZ Merger (see Note 1 – General, Description of Business, and Basis of Presentation) had on income allocation for state tax purposes.

A valuation allowance for deferred tax assets, including foreign tax credits, is recognized when it is more likely than not that some, or all, of the benefit from the deferred tax asset will not be realized. To assess that likelihood, we use estimates and judgment regarding our sources of future taxable income, including available tax planning strategies, to determine whether a valuation allowance is required. The completion of the WPZ Merger decreased our deferred income tax liability by $1.829 ~~billion.~~billion at September 30, 2018. Increased tax depreciation from the additional tax basis will reduce taxable income in future years and may limit our ability to realize the full benefit of certain short-lived deferred tax assets.

~~Notes (Continued)~~

The effective income tax rate for the three months ended September 30, 2017, is less than the federal statutory rate primarily due to the impact of the allocation of income to nontaxable noncontrolling interests, partially offset by the effect of state income taxes, including an $18 million provision related to an increase in the deferred state income tax rate (net of federal benefit).

The effective income tax rate for the nine months ended September 30, 2017, is less than the federal statutory rate. This is primarily due to the impact of the allocation of income to nontaxable noncontrolling interests and releasing a $127 million valuation allowance on a deferred tax asset associated with a capital loss carryover, partially offset by the effect of state income taxes, including an $18 million provision related to an increase in the deferred state income tax rate (net of federal benefit). In 2016, we recorded a valuation allowance on a deferred tax asset associated with a capital loss that was incurred with the sale of our Canadian operations. The sale of the Geismar olefins facility in 2017 (see Note 4 – Divestitures and Assets Held for Sale) generated capital gains sufficient to offset the capital loss carryover, thereby allowing us to reverse the valuation allowance in full.

On December 22, 2017, Tax Reform was enacted. Under the guidance provided by Securities and Exchange Commission Staff Accounting Bulletin No. 118, Income Tax Accounting Implications of the Tax Cuts and Jobs Act, we recorded provisional adjustments related to the impact of Tax Reform in the fourth quarter of 2017. We consider all amounts recorded related to Tax Reform to be reasonable estimates. The amounts recorded continue to be provisional as our interpretation, assessment, and presentation of the impact of the tax law change may be further clarified with additional guidance from regulatory, tax, and accounting authorities. We anticipate that additional guidance from the Internal Revenue Service will be released to guide us in determining what assets are eligible for direct expensing. We are also recording provisional adjustments for valuation allowances associated with losses and credits since, at this time, we cannot assess the impact that the interest expense disallowance will have on our estimated future taxable income. We are not reducing our minimum tax credit for sequestration until we receive further guidance provided by these authorities or other sources.

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.

Notes (Continued)

Note 8 – Earnings (Loss) Per Common Share



	Three Months Ended September 30,				Nine Months Ended September 30,
	2019		2018		2019		2018
	(Dollars in millions, except per-share amounts; shares in thousands)
Net income (loss) available to common stockholders	$	220	$	129	$	724	$	416
Basic weighted-average shares	1,212,270		1,023,587		1,211,938		893,706
Effect of dilutive securities:
Nonvested restricted stock units	1,790		2,387		1,809		2,102
Stock options	105		530		196		514
Diluted weighted-average shares	1,214,165		1,026,504		1,213,943		896,322
Earnings (loss) per common share:
Basic	$	.18	$	.13	$	.60	$	.47
Diluted	$	.18	$	.13	$	.60	$	.46

Three Months Ended
September 30, Nine Months Ended
September 30,
2018 2017 2018 2017

(Dollars in millions, except per-share
amounts; shares in thousands)
Net income available to common stockholders $ 129
$ 33
$ 416
$ 487

Basic weighted-average shares 1,023,587
826,779
893,706
825,925
Effect of dilutive securities:
Nonvested restricted stock units 2,387
1,889
2,102
1,567
Stock options 530
700
514
658
Diluted weighted-average shares 1,026,504
829,368
896,322
828,150

Earnings per common share:
Basic $ .13
$ .04
$ .47
$ .59
Diluted $ .13
$ .04
$ .46
$ .59

~~Notes (Continued)~~

Note 9 – Employee Benefit Plans

Net periodic benefit cost (credit) is as follows:



	Pension Benefits
	Three Months Ended September 30,						Nine Months Ended September 30,
	2019			2018			2019			2018
	(Millions)
Components of net periodic benefit cost (credit):
Service cost	$	11		$	12		$	33		$	37
Interest cost	13			12			38			35
Expected return on plan assets	(15		)	(16		)	(46		)	(47		)
Amortization of net actuarial loss	3			6			11			17
Net actuarial loss from settlements	1			1			1			2
Net periodic benefit cost (credit)	$	13		$	15		$	37		$	44

Pension Benefits

Three Months Ended
September 30,
Nine Months Ended
September 30,

2018
2017
2018
2017

(Millions)
Components of net periodic benefit cost (credit):

Service cost $ 12

$ 13

$ 37

$ 38
Interest cost 12

15

35

44
Expected return on plan assets (16 )
(21 )
(47 )
(62 )
Amortization of net actuarial loss 6

6

17

20
Net actuarial loss from settlements 1

—

2

—
Net periodic benefit cost (credit) $ 15

$ 13

$ 44

$ 40



	Other Postretirement Benefits
	Three Months Ended September 30,						Nine Months Ended September 30,
	2019			2018			2019			2018
	(Millions)
Components of net periodic benefit cost (credit):
Service cost	$	1		$	1		$	1		$	1
Interest cost	2			1			6			5
Expected return on plan assets	(3		)	(2		)	(8		)	(8		)
Amortization of prior service credit	—			—			—			(1		)
Reclassification to regulatory liability	—			—			1			1
Net periodic benefit cost (credit)	$	—		$	—		$	—		$	(2	)

Other Postretirement Benefits
Three Months Ended
September 30, Nine Months Ended
September 30,
2018 2017 2018 2017
(Millions)
Components of net periodic benefit cost (credit):
Service cost $ 1
$ —
$ 1
$ 1
Interest cost 1
2
5
6
Expected return on plan assets (2 ) (3 ) (8 ) (9 )
Amortization of prior service credit —
(3 ) (1 ) (10 )
Reclassification to regulatory liability —
1
1
3
Net periodic benefit cost (credit) $ —
$ (3 ) $ (2 ) $ (9 )

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 Income.

Notes (Continued)

Amortization of prior service credit included in Net periodic benefit cost (credit) for our other postretirement benefit plans associated with Transco and Northwest Pipeline is recorded to regulatory assets/liabilities instead of Other comprehensive income (loss). The ~~amounts~~amount of Amortization of prior service credit recognized in regulatory liabilities ~~were $2 million for the three months ended September 30, 2017, and~~was $1 ~~million and $6~~ million for the nine months ended September 30, ~~2018 and 2017, respectively.~~2018.

During the nine months ended September 30, ~~2018~~2019, we contributed ~~$87~~$63 million to our pension plans and $4 million to our other postretirement benefit plans. We presently anticipate making additional contributions of approximately $1 million to our pension plans and approximately $2$1 million to our other postretirement benefit plans in the remainder of ~~2018.~~2019.

Note 10 – Leases

We are a lessee through noncancellable lease agreements for property and equipment consisting primarily of buildings, land, vehicles, and equipment used in both our operations and administrative functions. We recognize a lease liability with an offsetting right-of-use asset in our Consolidated Balance Sheet for operating leases based on the present value of the future lease payments. As an accounting policy, we have elected to combine lease and nonlease components for all classes of leased assets in our calculation of the lease liability and the offsetting right-of-use asset.

Our lease agreements require both fixed and variable periodic payments, with initial terms typically ranging from one year to 15 years, but a certain land lease has a term of 108 years. Payment provisions in certain of our lease agreements contain escalation factors which may be based on stated rates or a change in a published index at a future time. The amount by which a lease escalates based on the change in a published index, which is not known at lease commencement, is considered a variable payment and is not included in the present value of the future lease payments, which only includes those that are stated or can be calculated based on the lease agreement at lease commencement. In addition to the noncancellable periods, many of our lease agreements provide for one or more extensions of the lease agreement for periods ranging from one year in length to an indefinite number of times following the specified contract term. Other lease agreements provide for extension terms that allow us to utilize the identified leased asset for an indefinite period of time so long as the asset continues to be utilized in our operations. In consideration of these renewal features, we assess the term of the lease agreements, which includes using judgment in the determination of which renewal periods and termination provisions, when at our sole election, will be reasonably certain of being exercised. Periods after the initial term or extension terms that allow for either party to the lease to cancel the lease are not considered in the assessment of the lease term. Additionally, we have elected to exclude leases with an original term of one year or less, including renewal periods, from the calculation of the lease liability and the offsetting right-of-use asset.

We used judgment in determining the discount rate upon which the present value of the future lease payments is determined. This rate is based on a collateralized interest rate corresponding to the term of the lease agreement using company, industry, and market information available.

When permitted under our lease agreements, we may sublease certain unused office space for fixed periods that could extend up to the length of the original lease agreement.

Notes (Continued)



	Three Months Ended September 30,		Nine Months Ended September 30,
	2019
	(Millions)
Lease Cost:
Operating lease cost	$	10	$	31
Short-term lease cost	—		—
Variable lease cost	7		21
Sublease income	—		(1		)
Total lease cost	$	17	$	51
Cash paid for amounts included in the measurement of operating lease liabilities	$	10	$	30
			September 30, 2019
			(Millions)
Other Information:
Right-of-use asset (included in Regulatory assets, deferred charges, and other in our Consolidated Balance Sheet)			$	213
Operating lease liabilities:
Current (included in Accrued liabilities in our Consolidated Balance Sheet)			$	23
Noncurrent (included in Regulatory liabilities, deferred income, and other in our Consolidated Balance Sheet)			$	190
Weighted-average remaining lease term – operating leases (years)			13
Weighted-average discount rate – operating leases			4.60%

As of September 30, 2019, the following table represents our operating lease maturities, including renewal provisions that we have assessed as being reasonably certain of exercise, for each of the years ended December 31:



	(Millions)
2019 (remainder)	$	8
2020	32
2021	33
2022	27
2023	21
Thereafter	171
Total future lease payments	292
Less amount representing interest	79
Total obligations under operating leases	$	213

We are the lessor to certain lease agreements for office space in our headquarters building, which are insignificant to our financial statements.

Note 1011 – Debt and Banking Arrangements

Long-Term Debt

~~Issuances and retirements~~Retirements

~~On August 24, 2018, Northwest Pipeline issued $250~~We retired approximately $32 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 (Continued)~~

notes due 2027. As part of the issuance, Northwest Pipeline entered into a registration rights agreement with the initial purchasers of the unsecured notes. Northwest Pipeline is obligated to file and consummate a registration statement for an offer to exchange the notes for a new issue of substantially identical notes registered under the Securities Act of 1933, as amended, within 365 days from closing and to use commercially reasonable efforts to complete the exchange offer. Northwest Pipeline is required to provide a shelf registration statement to cover resales of the notes under certain circumstances. If Northwest Pipeline fails to fulfill these obligations, additional interest will accrue on the affected securities. The rate of additional interest will be 0.25 percent per annum on the principal amount of the affected securities for the first 90-day period immediately following the occurrence of a registration default, increasing by an additional 0.25 percent per annum with respect to each subsequent 90-day period thereafter, up to a maximum amount for all such registration defaults of 0.5 percent annually. Following the cure of any registration defaults, the accrual of additional interest will cease.

~~Northwest Pipeline retired $250 million of 6.05~~7.625 percent senior unsecured notes that matured on ~~June~~July 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 September 2018, Transco completed an exchange of these notes for substantially identical new notes that are registered under the Securities Act of 1933, as amended.

~~Other financing obligations~~

During the first three quarters of 2018, Transco received an additional $29 million of funding from a co-owner related to the construction of the Dalton expansion project. This additional funding is reflected as ~~Long-term debt~~ ~~in the Consolidated Balance Sheet.~~

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 October 2018, Transco began utilizing this partner’s undivided interest in the lateral, including the associated pipeline capacity, and expects to reclassify approximately ~~$790 million~~ ~~of funding previously received from its partner from noncurrent liabilities to debt to reflect the financing obligation payable to its partner over an expected term of~~ ~~20 years~~. As this transaction did not meet the criteria for sale leaseback accounting due to our continued involvement, it will be accounted for as a financing arrangement over the course of the capacity agreement.2019.

Commercial Paper Program

~~On August 10, 2018, following the consummation of the WPZ Merger, WPZ’s $3 billion~~At September 30, 2019, 0 commercial paper ~~program~~ was ~~discontinued and we entered into a new~~outstanding under our $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 September 30, 2018, approximately $824 million of ~~Commercial paper~~ ~~at a weighted-average interest rate of 2.73 percent was outstanding. At October 30, 2018, no commercial paper was outstanding.~~

Notes (Continued)

Credit Facilities


	September 30, 2018				September 30, 2019
	Stated Capacity		Outstanding		Stated Capacity		Outstanding
	(Millions)				(Millions)

Long-term credit facility (1)	$	4,500	$	—	$	4,500	$	—
Letters of credit under certain bilateral bank agreements			14				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 adjusted 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.

~~Notes (Continued)~~

~~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 September 30, 2018, we are in compliance with these covenants.~~

Note 1112 – Stockholders’ Equity

Issuance of Preferred Shares

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 $0.4 million on the shares of Preferred Stock in September 2018.~~ Our certificate of incorporation authorizes 30 million shares of Preferred Stock, $1 par value per ~~share.~~shares.

AOCI

The following table presents the changes in ~~Accumulated other comprehensive income (loss)(AOCI)~~ AOCI by component, net of income taxes:



	Cash Flow Hedges			Foreign Currency Translation			Pension and Other Postretirement Benefits			Total
	(Millions)
Balance at December 31, 2018	$	(2	)	$	(1	)	$	(267	)	$	(270	)
Other comprehensive income (loss) before reclassifications	—			—			(5		)	(5		)
Amounts reclassified from accumulated other comprehensive income (loss)	—			—			9			9
Other comprehensive income (loss)	—			—			4			4
Balance at September 30, 2019	$	(2	)	$	(1	)	$	(263	)	$	(266	)

Cash
Flow
Hedges

Foreign
Currency
Translation

Pension and
Other Postretirement
Benefits
Total
(Millions)
Balance at December 31, 2017 $ (2 ) $ (1 ) $ (235 ) $ (238 )
Adoption of ASU 2018-02 (Note 1) —
—
(61 ) (61 )
WPZ Merger (Note 1) (3 ) —
—
(3 )
Other comprehensive income (loss):
Other comprehensive income (loss) before reclassifications
(14 ) —
4
(10 )
Amounts reclassified from accumulated other comprehensive income (loss)
7
—
14
21
Other comprehensive income (loss) (7 ) —
18
11
Balance at September 30, 2018 $ (12 ) $ (1 ) $ (278 ) $ (291 )

~~Notes (Continued)~~

Reclassifications out of AOCI are presented in the following table by component for the nine months ended September 30, ~~2018:~~2019:



Component	Reclassifications			Classification
	(Millions)
Pension and other postretirement benefits:
Amortization of actuarial (gain) loss and net actuarial loss from settlements included in net periodic benefit cost (credit)	$	12		Note 9 – Employee Benefit Plans
Income tax benefit	(3		)	Provision (benefit) for income taxes
Reclassifications during the period	$	9

Component Reclassifications Classification
(Millions)
Cash flow hedges:
Energy commodity contracts $ 13
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) 19
Note 9 – Employee Benefit Plans
Total before tax 32

Income tax benefit (8 ) Provision (benefit) for income taxes
Net of income tax 24

Noncontrolling interest (3 ) Net income (loss) attributable to noncontrolling interests
Reclassifications during the period $ 21

~~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.~~

Notes (Continued)

The following table reflects the reconciliation of Segment revenues to Total revenues as reported in the Consolidated Statement of Income and Total assets by reportable segment.



	Northeast G&P		Atlantic-Gulf		West		Other		Eliminations			Total
	(Millions)
Three Months Ended September 30, 2019
Segment revenues:
Service revenues
External	$	340	$	718	$	433	$	4	$	—		$	1,495
Internal	13		13		—		3		(29		)	—
Total service revenues	353		731		433		7		(29		)	1,495
Total service revenues – commodity consideration	1		7		30		—		—			38
Product sales
External	22		66		378		—		—			466
Internal	8		10		11		—		(29		)	—
Total product sales	30		76		389		—		(29		)	466
Total revenues	$	384	$	814	$	852	$	7	$	(58	)	$	1,999

Three Months Ended September 30, 2018
Segment revenues:
Service revenues
External	$	236	$	595	$	533	$	7	$	—		$	1,371
Internal	11		12		—		3		(26		)	—
Total service revenues	247		607		533		10		(26		)	1,371
Total service revenues – commodity consideration	6		18		97		—		—			121
Product sales
External	59		46		706		—		—			811
Internal	10		85		26		—		(121		)	—
Total product sales	69		131		732		—		(121		)	811
Total revenues	$	322	$	756	$	1,362	$	10	$	(147	)	$	2,303

Nine Months Ended September 30, 2019
Segment revenues:
Service revenues
External	$	925	$	2,102	$	1,384	$	13	$	—		$	4,424
Internal	34		36		—		9		(79		)	—
Total service revenues	959		2,138		1,384		22		(79		)	4,424
Total service revenues – commodity consideration	9		33		116		—		—			158
Product sales
External	87		169		1,256		—		—			1,512
Internal	27		57		46		—		(130		)	—
Total product sales	114		226		1,302		—		(130		)	1,512
Total revenues	$	1,082	$	2,397	$	2,802	$	22	$	(209	)	$	6,094

Northeast G&P Atlantic-Gulf West Other (1) Eliminations (2) Total
(Millions)
Three Months Ended September 30, 2018
Segment revenues:
Service revenues
External $ 236
$ 595
$ 533
$ 7
$ —
$ 1,371
Internal 11
12
—
3
(26 ) —
Total service revenues 247
607
533
10
(26 ) 1,371
Total service revenues – commodity consideration (external only) 6
18
97
—
—
121
Product sales
External 59
46
706
—
—
811
Internal 10
85
26
—
(121 ) —
Total product sales 69
131
732
—
(121 ) 811
Total revenues $ 322
$ 756
$ 1,362
$ 10
$ (147 ) $ 2,303

Three Months Ended September 30, 2017
Segment revenues:
Service revenues
External $ 207
$ 553
$ 544
$ 6
$ —
$ 1,310
Internal 7
11
—
3
(21 ) —
Total service revenues 214
564
544
9
(21 ) 1,310
Product sales
External 56
57
459
9
—
581
Internal 5
49
26
—
(80 ) —
Total product sales 61
106
485
9
(80 ) 581
Total revenues $ 275
$ 670
$ 1,029
$ 18
$ (101 ) $ 1,891

Nine Months Ended September 30, 2018
Segment revenues:
Service revenues
External $ 677
$ 1,769
$ 1,599
$ 17
$ —
$ 4,062
Internal 30
37
—
9
(76 ) —
Total service revenues 707
1,806
1,599
26
(76 ) 4,062
Total service revenues – commodity consideration (external only) 14
45
257
—
—
316
Product sales
External 214
131
1,759
—
—
2,104
Internal 28
198
63
—
(289 ) —
Total product sales 242
329
1,822
—
(289 ) 2,104
Total revenues $ 963
$ 2,180
$ 3,678
$ 26
$ (365 ) $ 6,482

Notes (Continued)



	Northeast G&P		Atlantic-Gulf		West		Other		Eliminations			Total
	(Millions)
Nine Months Ended September 30, 2018
Segment revenues:
Service revenues
External	$	677	$	1,769	$	1,599	$	17	$	—		$	4,062
Internal	30		37		—		9		(76		)	—
Total service revenues	707		1,806		1,599		26		(76		)	4,062
Total service revenues – commodity consideration	14		45		257		—		—			316
Product sales
External	214		131		1,759		—		—			2,104
Internal	28		198		63		—		(289		)	—
Total product sales	242		329		1,822		—		(289		)	2,104
Total revenues	$	963	$	2,180	$	3,678	$	26	$	(365	)	$	6,482

September 30, 2019
Total assets	$	15,445	$	16,888	$	13,550	$	928	$	(530	)	$	46,281
December 31, 2018
Total assets	$	14,526	$	16,346	$	13,948	$	849	$	(367	)	$	45,302

Northeast G&P Atlantic-Gulf West Other (1) Eliminations (2) Total
(Millions)
Nine Months Ended September 30, 2017
Segment revenues:
Service revenues
External $ 621
$ 1,620
$ 1,589
$ 23
$ —
$ 3,853
Internal 27
27
—
9
(63 ) —
Total service revenues 648
1,647
1,589
32
(63 ) 3,853
Product sales
External 159
201
1,233
357
—
1,950
Internal 22
164
143
8
(337 ) —
Total product sales 181
365
1,376
365
(337 ) 1,950
Total revenues $ 829
$ 2,012
$ 2,965
$ 397
$ (400 ) $ 5,803

September 30, 2018
Total assets $ 14,482
$ 16,361
$ 16,169
$ 748
$ (607 ) $ 47,153
December 31, 2017
Total assets $ 14,397
$ 14,989
$ 16,143
$ 1,449
$ (626 ) $ 46,352

~~___________~~

~~(1) Decrease in Other~~ ~~Total assets~~ ~~due primarily to decreased cash balance.~~

~~(2)~~ ~~Total assets~~ ~~Eliminations primarily relate to the intercompany notes and accounts receivable generated by our cash management program.~~

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



	Three Months Ended September 30,						Nine Months Ended September 30,
	2019			2018			2019			2018
	(Millions)
Modified EBITDA by segment:
Northeast G&P	$	345		$	281		$	947		$	786
Atlantic-Gulf	599			492			1,683			1,418
West	311			412			921			1,214
Other	(2		)	6			1			(49		)
	1,253			1,191			3,552			3,369
Accretion expense associated with asset retirement obligations for nonregulated operations	(8		)	(8		)	(25		)	(26		)
Depreciation and amortization expenses	(435		)	(425		)	(1,275		)	(1,290		)
Equity earnings (losses)	93			105			260			279
Other investing income (loss) – net	(107		)	2			(54		)	74
Proportional Modified EBITDA of equity-method investments	(181		)	(205		)	(546		)	(552		)
Interest expense	(296		)	(270		)	(888		)	(818		)
(Provision) benefit for income taxes	(77		)	(190		)	(244		)	(297		)
Net income (loss)	$	242		$	200		$	780		$	739

Three Months Ended
September 30, Nine Months Ended
September 30,
2018 2017 2018 2017
(Millions)
Modified EBITDA by segment:
Northeast $ 281
$ 115
$ 786
$ 588
Atlantic-Gulf 492
430
1,418
1,334
West 412
(615 ) 1,214
126
Other 6
1,009
(49 ) 1,100
1,191
939
3,369
3,148
Accretion expense associated with asset retirement obligations for nonregulated operations (8 ) (7 ) (26 ) (23 )
Depreciation and amortization expenses (425 ) (433 ) (1,290 ) (1,308 )
Equity earnings (losses) 105
115
279
347
Other investing income (loss) – net 2
4
74
278
Proportional Modified EBITDA of equity-method investments (205 ) (202 ) (552 ) (611 )
Interest expense (270 ) (267 ) (818 ) (818 )
(Provision) benefit for income taxes (190 ) (24 ) (297 ) (126 )
Net income (loss) $ 200
$ 125
$ 739
$ 887

Item 2

2. Management’s Discussion and Analysis of

Financial Condition and Results of Operations

General

We are an energy infrastructure company focused on connecting North America’s significant hydrocarbon resource plays to growing markets for natural gas and NGLs through our gas pipeline and midstream ~~businesses.~~business. Our operations are located in the United States.

Our interstate natural gas pipeline strategy is to create value by maximizing the utilization of our pipeline capacity by providing high quality, low cost transportation of natural gas to large and growing markets. Our gas pipeline businesses’ interstate transmission and storage activities are subject to regulation by the FERC and as such, our rates and charges for the transportation of natural gas in interstate commerce, and the extension, expansion, or abandonment of jurisdictional facilities and accounting, among other things, are subject to regulation. The rates are established through the FERC’s ratemaking process. Changes in commodity prices and volumes transported have limited near-term impact on these revenues because the majority of cost of service is recovered through firm capacity reservation charges in transportation rates.

The ongoing strategy of our midstream operations is to safely and reliably operate large-scale midstream infrastructure where our assets can be fully utilized and drive low per-unit costs. We focus on consistently attracting new business by providing highly reliable service to our customers. These services include natural gas gathering, processing, treating, and compression, NGL fractionation and transportation, crude oil production handling and transportation, marketing services for NGL, crude oil, and natural gas, as well as storage facilities.

~~Prior to~~Our operations are presented within the ~~WPZ Merger, we had one~~following reportable ~~segment, Williams Partners. Beginning in the third-quarter 2018,~~segments: Northeast G&P, Atlantic-Gulf, and West, consistent with the manner in which our chief operating decision maker evaluates performance and allocates ~~resources, our operations~~resources. All remaining business activities as well as corporate activities 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.~~included in Other. Our reportable segments are comprised of the following businesses:

Northeast G&P is comprised of our midstream gathering, processing, and ~~processing~~fractionation 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~~including a 66 percent interest in Cardinal (a consolidated entity), ~~a 62 percent equity-method investment in UEOM,~~as well as a 69 percent equity-method investment in Laurel Mountain, a 58 percent equity-method investment in Caiman II, and Appalachia Midstream Services, LLC, which owns equity-method investments with an approximate average 66 percent interest in multiple gas gathering systems in the Marcellus Shale (Appalachia Midstream Investments). Northeast G&P includes a 65 percent interest in the Northeast JV (a consolidated entity), which includes our existing Ohio Valley assets and UEOM (see Note 2 – Acquisitions of Notes to Consolidated Financial Statements).

Atlantic-Gulf is comprised of our interstate natural gas pipeline, Transco, and significant natural gas gathering and processing and crude oil production handling and transportation assets in the Gulf Coast region, including a 51 percent interest in Gulfstar One (a consolidated entity), which is a proprietary floating production system, ~~and various petrochemical and feedstock pipelines in the Gulf Coast region,~~ as well as a 50 percent equity-method investment in Gulfstream, a 60 percent equity-method investment in Discovery, and a 41 percent interest in Constitution (a consolidated entity), which is developing a pipeline project (see Note 34 – Variable Interest Entities of Notes to Consolidated Financial Statements).

~~Management’s Discussion and Analysis (Continued)~~

West is comprised of our interstate natural gas pipeline, Northwest Pipeline, and our gathering, processing, and treating operations in ~~New Mexico,~~ Colorado, ~~and~~ Wyoming, ~~as well as~~ the Barnett Shale region of north-central Texas, the Eagle Ford Shale region of south Texas, the Permian Shale region of west Texas, the Haynesville Shale region of northwest Louisiana, and the Mid-Continent region which includes the Anadarko ~~Arkoma, Delaware,~~ and ~~Permian~~Arkoma basins. This segment also includes our NGL and natural gas marketing business, storage facilities, an undivided 50 percent interest in an NGL fractionator near Conway, Kansas, ~~and~~ a 50 percent equity-method investment in OPPL, a 50 percent equity-method investment in RMM, and a 15 percent equity-method investment in Brazos Permian II. West also included our former natural gas gathering and processing assets in the Four Corners area of New Mexico and Colorado, which were sold during the fourth quarter of 2018, and our former 50 percent interest in Jackalope (an equity-method investment following deconsolidation as of June 30, 2018), ~~a 43 percent equity-method investment~~which was sold in ~~RMM,~~and our previously owned 50 percent equity-method investment in the Delaware basin gas gathering system (DBJV) in the Mid-Continent region (see Note 5 – Investing Activities of Notes to Consolidated Financial Statements).

All remaining business activities, including our former Geismar Interest (see Note 4 – Divestitures and Assets Held for Sale of Notes to Consolidated Financial Statements), as well as corporate activities, are included in Other.

~~Financial Repositioning~~

In January 2017, we entered into agreements with WPZ, wherein we permanently waived the general partner’s IDRs and converted our 2 percent general partner interest in WPZ to a noneconomic interest in exchange for 289 million newly issued WPZ common units. Pursuant to this agreement, we also purchased approximately 277 thousand WPZ common units for $10 million. Additionally, we purchased approximately 59 million common units of WPZ at a price of $36.08586 per unit in a private placement transaction, funded with proceeds from our equity offering. 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.April 2019.

Management’s Discussion and Analysis (Continued)

Dividends

In September ~~2018,~~2019, we paid a regular quarterly dividend of ~~$0.34~~$0.38 per share.

Overview of Nine Months Ended September 30, ~~2018~~2019

Net income (loss) attributable to The Williams Companies, Inc., for the nine months ended September 30, ~~2018, decreased $71~~2019, increased $310 millioncompared to the nine months ended September 30, ~~2017,~~2018, reflecting $362 million of increased service revenues primarily associated with expansion projects, a ~~$204~~$269 million decrease in ~~Other investing~~to Net income (loss) attributable to noncontrolling interests primarily due to the WPZ Merger, a $122 million gain on the second-quarter 2019 sale of our 50 percent interest in Jackalope, and the absence of a ~~$269~~2018 charge for a valuation allowance on foreign tax credits. These increases are partially offset by $186 million ~~gain associated with the disposition~~ of ~~certain~~impairments of equity-method investments in ~~2017, a $171 million increase to~~2019, lower commodity margins, the ~~provision for income taxes~~absence of the Four Corners area business which ~~reflects a $105 million valuation allowance on certain deferred tax assets that may not be realized following the WPZ Merger and~~was sold in October 2018, higher interest expense, the absence of a prior year ~~$127~~$62 million ~~benefit associated with~~gain on deconsolidation of Jackalope, lower Transco allowance for equity funds used during construction (AFUDC), and current year severance charges. Long-lived asset impairments in the ~~release of a valuation allowance on a capital loss carryover, and a $68 million decrease in~~ ~~Equity earnings (losses). These decreases~~current year were ~~partially~~substantially offset by ~~an increase~~similar levels of ~~$320 million~~impairments in ~~operating income and a $77 million decrease to~~ ~~Net income (loss) attributable to noncontrolling interests~~ ~~primarily due to~~ the ~~WPZ Merger.~~prior year.

The ~~improvement in operating income reflects a decrease of $1.170 billion in~~ ~~Impairment of certain assets,~~ a $209 million increase in service revenues primarily resulting from expansion projects placed into service in 2017 and 2018, and a $64 million increase in NGL margins. These favorable changes were partially offset by the absence of a $1.095 billion gain from the sale of our Geismar Interest in 2017.

~~Unless indicated otherwise, the~~ following discussion and analysis ofresults of operations and financial condition and liquidity should be read in conjunction with the consolidated financial statements and notes thereto of this Form 10‑Q and our ~~annual consolidated financial statements and notes thereto in Exhibit 99.1~~Annual Report on Form 10-K dated February 21, 2019.

Acquisition of ~~our Form 8-K dated May 3, 2018.~~UEOM

~~WPZ Merger~~

~~On August 10,~~As of December 31, 2018, we ~~completed our merger with Williams Partners L.P. (WPZ), pursuant to~~owned a 62 percent interest in UEOM which we ~~acquired all~~accounted for as an equity-method investment. On March 18, 2019, we signed and closed the acquisition of the ~~approximately 256~~remaining 38 percent interest in UEOM. Total consideration paid, including post-closing adjustments, was $741 million ~~publicly held outstanding common units~~in cash funded through credit facility borrowings and cash on hand. As a result of ~~WPZ in exchange for 382 million shares~~acquiring this additional interest, we obtained control of ~~our common stock in a non-cash equity transaction. Williams continued as the surviving entity.~~and now consolidate UEOM. (See Note 12 – ~~General, Description of Business, and Basis of Presentation~~Acquisitions of Notes to Consolidated Financial Statements.)

Northeast JV

Sale of Jackalope

In April 2019, we sold our interest in Jackalope for $485 million in cash, resulting in a gain on the disposition of $122 million.

Expansion Project Update

Rivervale South to Market

In August 2018, we received approval from the FERC to expand Transco’s existing natural gas transmission system to provide incremental firm transportation capacity from the existing Rivervale interconnection with Tennessee Gas Pipeline on Transco’s North New Jersey Extension to other existing Transco locations within New Jersey. The project was placed into partial service on July 1, 2019. The remaining portion of the project was placed into service on September 1, 2019. The full project increased capacity by 190 Mdth/d.

Ohio River Supply Hub Expansion

Management’s Discussion and Analysis (Continued)

~~FERC Income Tax Policy Revision~~

~~On March 15, 2018, the FERC issued~~ a ~~revised policy statement (the March 15 Statement) regarding the recovery of income tax costs in rates of natural gas pipelines. The FERC found that an impermissible double recovery results~~new NGL pipeline from ~~granting a Master Limited Partnership (MLP) pipeline both an income tax allowance and a return on equity pursuant~~Moundsville to the ~~discounted cash flow methodology. As a result, the FERC will no longer permit~~Harrison Hub fractionation facility to provide an ~~MLP pipeline~~additional outlet for NGLs. These expansions are supported by long-term, fee-based agreements and volumetric commitments.

Norphlet Project

In March 2016, we announced that we reached an agreement 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 pursuantprovide deepwater gas gathering services 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 March 15 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 reductionAppomattox development 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 haveGulf of Mexico. We completed modifications 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 consideredinstall an alternate delivery route 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. Further, 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 the 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 the reduction in the corporate income tax in Tax Reform is already addressed in its settlement.

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,our Main Pass 261 Platform, as well as ~~whether other features of Tax Reform require FERC action. We are evaluating the impact of these developments on~~modifications to our ~~interstate natural~~onshore Mobile Bay processing facility. The project went in service early in July 2019, at which time we also purchased a 54-mile-long, 16-inch-diameter pipeline (the Norphlet Pipeline) for $200 million. This pipeline transports 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.

~~Proposition 112~~

~~Management’s Discussion and Analysis (Continued)~~

~~impact the operations, and ultimately the value, of our businesses and investments in Colorado, notably our recent investment in RMM.~~

~~Revenue Recognition~~

As a result of the adoption of Accounting Standards Update 2014-09, Revenues from Contracts with Customers (ASC 606), we now record revenues for transactions where we receive noncash consideration, primarily in certain of our gas processing contracts that provide commodities as full or partial consideration for services provided. These revenues are reflected as ~~Service revenues – commodity consideration~~ ~~in the~~ ~~Consolidated Statement of Income. The costs associated with these revenues, primarily related to natural gas shrink replacement, are reported as~~ ~~Processing commodity expenses. The revenues and costs associated with the subsequent sale of the commodity consideration received is reflected within~~ ~~Product sales~~ ~~and~~ ~~Product costs~~ ~~in the~~ ~~Consolidated Statement of Income~~. ~~Service revenues – commodity consideration~~ ~~plus~~ ~~Product sales, less~~ ~~Product costs~~ ~~and~~ ~~Processing commodity expenses~~ ~~represents the margin that we have historically characterized as commodity margin. This presentation is being reflected prospectively in the~~ ~~Consolidated Statement of Income. (See Note 2 – Revenue Recognition of Notes to Consolidated Financial Statements.)~~

Additionally, future revenues are impacted by application of the new accounting standard to certain contracts for which we received prepayments for services and have recorded deferred revenue (contract liabilities). For these contracts, which underwent modifications in periods prior to January 1, 2018, the modification is treated as a termination of the existing contract and the creation of a new contract. The new accounting guidance requires that the transaction price, including any remaining deferred revenue from the ~~old contract, be allocated~~Appomattox development to the performance obligations over the term of the new contract. As a result, we will recognize the deferred revenue over longer periods than application of revenue recognition under accounting guidance prior to January 1, 2018. The application of ASC 606 to prior periods related to these contracts would have resulted in lower revenues in 2017. Annual revenues will also be lower in 2018 and 2019 than what would have been recorded under the previous guidance, offset by increased revenues in later reporting periods given the longer period of recognition.our Main Pass 261 Platform.

Filing of Rate Case

On August 31, 2018, Transco filed a general rate case with the FERC for an overall increase in rates. In September 2018, with the exception of certain rates that reflected a rate decrease, the FERC accepted and suspended our general rate filing to be effective March 1, 2019, subject to refund and the outcome of a hearing. The specific rates that reflected a rate decrease were accepted, without suspension, to be effective October 1, 2018, as requested by Transco, and will not be subject to refund. ~~The impact~~In March 2019, the FERC accepted our motion to place the rates that were suspended by the September 2018 order into effect on March 1, 2019, subject to refund. In October 2019, we reached an agreement on the terms of ~~these specific new rates~~a settlement with the participants that would resolve all issues in the rate case without the need for a hearing. Final resolution of the rate case is ~~expected to reduce revenues by approximately $2.5 million per month beginning October 1, 2018.~~

~~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 is expected to increase to 50 percent as we provide additional capital contributions. At September 30, 2018, our carrying value was $569 million reflecting our 43 percent economic ownership. We are committed to fund up to an additional $177 million to reach 50 percent economic ownership,subject to the ~~extent RMM needs funding~~filing of a formal stipulation and agreement with, and subsequent approval by, the FERC. We have provided a reserve of $131 million for ~~capital expenditures. We account~~rate refunds which we believe is adequate for ~~this investment under the equity method of accounting.~~

~~Divestment of Four Corners Assets~~

~~Management’s Discussion and Analysis (Continued)~~

~~Expansion Project Updates~~

~~Significant expansion project updates for the period, including projects placed into service are described below. Ongoing major expansion projects are discussed later in Company Outlook.~~

~~Northeast G&P~~

~~Susquehanna Supply Hub~~

~~During the first quarter of 2018, the remaining facilities~~any refunds that comprise the Susquehanna Supply Hub Expansion were fully commissioned. The project added two new compression facilities with an additional 49,000 horsepower and 59 miles of 12- to 24-inch pipeline, and increased gathering capacity, allowing a certain producer to fulfill its commitment to deliver 850 Mdth/d to our Atlantic Sunrise development.

~~Atlantic-Gulf~~

~~Atlantic Sunrise~~

In October 2018, the Atlantic Sunrise project was placed into service. This project expanded Transco’s existing natural gas transmission system along with greenfield facilities to provide incremental firm transportation capacity from the northeastern Marcellus producing area to markets along Transco’s mainline as far south as Station 85 in west central Alabama. We placed a portion of the mainline project facilities into service in September 2017, which increased capacity by 400 Mdth/d. We placed additional mainline facilities into service in June 2018, which increased capacity by an additional 150 Mdth/d. The full project increased Transco’s capacity by 1,700 Mdth/d.

~~Garden State~~

In March 2018, Phase 2 of the Garden State Expansion project was placed into service. This project expanded Transco’s existing natural gas transmission system to provide incremental firm transportation capacity from Station 210 in New Jersey to a new interconnection on our Trenton Woodbury Lateral in New Jersey. Phase 1 of the project was placed into service in September 2017, and together Phases 1 and 2 increased capacity by 180 Mdth/d.may be required.

Commodity Prices

NGL per-unit margins were approximately 4451 percent ~~higher~~lower in the first nine months of ~~2018~~2019 compared to the same period of ~~2017~~2018 primarily due to a 2832 percent ~~increase~~decrease in per-unit non-ethane prices and an approximate 223 percent ~~decrease~~increase in per-unit natural gas feedstock prices.

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

The potential impact of commodity prices on our business for the remainder of ~~2018~~2019 is further discussed in the following Company Outlook.

Company Outlook

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

~~Management’s Discussion and Analysis (Continued)~~

Our business plan for ~~2018~~2019 includes a continued focus on growing our fee-based businesses, executing growth projects, including through joint ventures, and accomplishing cost discipline initiatives to ensure operations support our strategy. We anticipate operating results will increase through organic business growth driven ~~primarily~~ by Transco expansion projects and continued ~~growth~~expansion in the Northeast region. ~~We intend to fund planned growth capital with retained cash flow, debt,~~

Management’s Discussion and ~~proceeds from asset sales.~~Analysis (Continued)

Our ~~updated~~ growth capital and investment expenditures in ~~2018~~2019 are expected to be ~~at least $3.9~~in a range from $2.3 billion to $2.5 billion. ~~Approximately $1.8 billion of our growth~~Growth capital ~~funding needs include~~spending in 2019 includes Transco expansions, ~~and other interstate pipeline growth projects, most~~all of which are fully contracted with firm transportation ~~agreements. The remaining growth capital spending in 2018 primarily reflects investment in~~agreements, and continuing to develop our gathering and processing ~~systems~~infrastructure in the Northeast G&P ~~segment limited primarily to known new producer volumes, including volumes that support Transco expansion projects including our Atlantic Sunrise project,~~ and ~~funding for growth investment opportunities as they arise such as our investment in RMM in the~~ West ~~segment.~~segments. In addition to growth capital and investment expenditures, we also remain committed to projects that maintain our assets for safe and reliable operations, as well as projects that meet legal, regulatory, and/or contractual commitments.

As a result of our significant continued capital and investment expenditures on Transco ~~expansions~~expansion projects and fee-based gathering and processing projects, fee-based businesses are a significant component of our portfolio and serve to reduce the influence of commodity price fluctuations on our operating results and cash flows. We expect to benefit as continued growth in demand for low-cost natural gas is driven by increases in LNG exports, industrial demand, and power generation. For ~~2018,~~2019, current forward market prices indicate crude oil, natural gas, and NGL prices are expected to be ~~higher~~lower compared to ~~2017, while natural gas prices are expected to be lower as compared to 2017.~~2018. We continue to address certain pricing risks through the utilization of commodity hedging strategies. However, some of our customers may continue to curtail or delay drilling plans until there is a more sustained recovery in prices, which may negatively impact our gathering and processing volumes. Reductions in drilling activity or lower energy commodity prices could also adversely affect the credit profiles of certain of our producer customers. Unfavorable changes in energy commodity prices or the credit profile of our producer customers may also result in noncash impairments of our assets.

In ~~2018,~~2019, our operating results are expected to include increases from our regulated Transco fee-based business, primarily related to projects ~~recently~~ placed in-service ~~or expected to be placed in-service~~beginning early 2018 and 2019, as well as the favorable impact from Transco’s agreement on the terms of a settlement in ~~2018 including the Atlantic Sunrise project.~~its general rate case as previously discussed. For our non-regulated businesses, we anticipate ~~a reduction in fee-based revenue in the West segment, partially offset by~~ increases in fee-based revenue in the Northeast G&P ~~segment. As previously discussed, under~~segment driven by expansion projects, partially offset with a decrease in the ~~new accounting guidance for revenue~~West segment primarily due to the absence of results of our former sold or deconsolidated assets, lower commodity margins and commodity-based gathering and processing rates, and reduced recognition of deferred revenue ~~under certain contracts will be recognized over longer periods than under~~associated with the ~~prior guidance, contributing to the decrease in annual revenue for the West region.~~end of a contractual MVC period. We expect overall gathering and processing volumes to grow in ~~2018~~2019 for our continuing businesses. Additionally, we believe our expenses will be impacted by the changes in our asset portfolio, including the UEOM acquisition and ~~increase thereafter to meet the growing demand for natural gas~~asset divestitures, as well as severance charges and ~~natural gas products. We also anticipate slightly lower general and administrative expenses due to the full year impact of prior year cost reduction initiatives and lower equity earnings from~~other costs associated with our ~~investment in Discovery due to production ending on certain wells.~~previously announced organizational realignment.

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

Opposition to, and legal regulations affecting, our infrastructure projects, including the risk of delay or denial in permits and approvals needed for our projects;

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

Counterparty credit and performance ~~risk, including that of Chesapeake Energy Corporation~~risk;

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

Lower than anticipated demand for natural gas and natural gas products which could result in lower than expected volumes, energy commodity prices, and margins;

General economic, financial markets, or further industry downturn, including increased interest rates;

Physical damages to facilities, including damage to offshore facilities by named windstorms;

~~Management’s Discussion and Analysis (Continued)~~

~~Production issues impacting offshore gathering volumes;~~

Other risks set forth under Part I, Item 1A. Risk Factors in our Annual Report on Form 10-K for the year ended December 31, ~~2017,~~2018, as filed with the SEC on February ~~22, 2018 as supplemented by the disclosure in Part II, Item 1A. Risk Factors in this Quarterly Report on Form 10-Q.~~21, 2019.

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

Management’s Discussion and Analysis (Continued)

Expansion Projects

Our ongoing major expansion projects include the following:

Northeast G&P

~~Ohio River Supply Hub Expansion~~

We agreed to expand our services for certain customers to provide additional rich gas processing capacity in the Marcellus and Upper Devonian Shale in West Virginia and Pennsylvania. Associated with these agreements, we plan to further expand the processing capacity of our Oak Grove facility by 400 MMcf/d. With one of these customers, we secured a gathering dedication agreement to gather dry gas in this same region. Additionally, we will be constructing a new NGL pipeline from Moundsville to the Harrison Hub fractionation facility to provide a new outlet for NGLs. These expansions will be supported by long-term, fee-based agreements and volumetric commitments.

Susquehanna Supply Hub Expansion

We continue to expand the gathering systems in the Susquehanna Supply Hub that are needed to meet our customers’ production plans by 2020. This next expansion of the gathering infrastructure includes an additional 40,000 horsepower of new compression and gathering pipelines to bring the capacity to approximately 4.5 Bcf/d.

Atlantic-Gulf

Constitution Pipeline

We currently own 41 percent of Constitution with three other parties holding 25 percent, 24 percent, and 10 percent, respectively. We are the operator of Constitution. The 126-mile Constitution pipeline is proposed to connect our gathering system in Susquehanna County, Pennsylvania, to the Iroquois Gas Transmission and Tennessee Gas Pipeline systems in New York, as well as to a local distribution company serving New York and Pennsylvania.

~~In December 2014, Constitution received approval from~~ For further discussion on the ~~FERC to construct and operate its proposed pipeline, which will have an expected capacity~~status of 650 Mdth/d. 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.

~~Management’s Discussion and Analysis (Continued)~~

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, and in September 2018 we filed a petition with the D.C. Circuit for review of the FERC’s decision.(See~~see Note 34 – Variable Interest Entities of Notes to Consolidated Financial Statements.)

Gateway

In ~~November 2017,~~December 2018, we ~~filed an application with~~received approval from the FERC to expand Transco’s existing natural gas transmission system to provide incremental firm transportation capacity from PennEast Pipeline ~~Company's~~Company’s proposed interconnection with Transco’s mainline south of Station 205 in New Jersey to other existing Transco meter stations within New Jersey. We plan to place the project into service in the first ~~quarter~~half of ~~2021,~~2020, assuming timely receipt of all necessary regulatory approvals. The project is expected to increase capacity by 65 ~~Mdth/d.~~

~~Gulf Connector~~

In November 2017, we received approval from the FERC allowing Transco to expand its existing natural gas transmission system to provide incremental firm transportation capacity from Station 65 in Louisiana to delivery points in Wharton and San Patricio Counties, Texas. We plan to place the project into service during the first quarter of 2019, assuming timely receipt of all necessary regulatory approvals. The project is expected to increase capacity by 475 Mdth/d.

Hillabee

In February 2016, the FERC issued a certificate order for the initial phases of Transco’s Hillabee Expansion Project. The project involves an expansion of Transco’s existing natural gas transmission system from Station 85 in west central Alabama to a new interconnection with the Sabal Trail pipeline in Alabama. The project is being constructed in phases, and all of the project expansion capacity is dedicated to Sabal Trail pursuant to a capacity lease agreement. ~~We placed a portion of~~ Phase I ~~into service~~was completed in ~~June of~~ 2017 and ~~the remainder of Phase I into service in July of 2017. Phase I~~it increased capacity by 818 Mdth/d. The in-service date of Phase II is planned for the second quarter of 2020, and together Phases I and II are expected to increase capacity by 1,025 Mdth/d.

In August 2017, the Court of Appeals for the District of Columbia Circuit granted an appeal of the FERC certificate order for the Southeast Market Pipelines projects (a group of related projects, including the Hillabee Expansion Project) filed by certain non-governmental organizations. In doing so, the court (i) remanded the matter to the FERC for preparation of an Environmental Impact Statement (EIS) that conforms with the court’s opinion regarding quantifying certain greenhouse gas emissions, and (ii) vacated the FERC’s certificate order for the projects, which would be effective following the court’s mandate (by court order, the mandate will not issue until after disposition of all petitions for rehearing). In compliance with the court's directive, on February 5, 2018, the FERC issued a Final Supplemental EIS for the projects, reaffirming that while the projects would result in temporary and permanent impacts on the environment, those impacts would not be significant. On March 14, 2018, the FERC issued an order on remand reinstating the certificate and abandonment authorizations for the Hillabee Expansion Project and the other Southeast Market Pipelines projects. As this order was issued prior to the court’s mandate (which was issued on March 30, 2018), we experienced no lapse in FERC authorization for the project.

~~Norphlet Project~~

In March 2016, we announced that we have reached an agreement to provide deepwater gas gathering services to the Appomattox development in the Gulf of Mexico. The project will provide offshore gas gathering services to our existing Transco lateral, which will provide transmission services onshore to our Mobile Bay processing facility. We also plan to make modifications to our Main Pass 261 Platform to install an alternate delivery route from the platform, as well as modifications to our Mobile Bay processing facility. The project is scheduled to go into service during the second quarter of 2019.

~~Management’s Discussion and Analysis (Continued)~~

Northeast Supply Enhancement

In ~~March 2017,~~May 2019, we ~~filed an application with~~received approval from the FERC to expand Transco’s existing natural gas transmission system to provide incremental firm transportation capacity from Station 195 in Pennsylvania to the Rockaway Delivery Lateral transfer point in New York. ~~On April 20, 2018,~~Approvals required for the ~~NYSDEC~~project from the New York State Department of Environmental Conservation and the New Jersey Department of Environmental Protection remain pending, with each such agency having denied, without prejudice, Transco’s ~~application~~applications for ~~certain permits required~~such approvals. We have refiled our applications for ~~the project. We~~those approvals and have addressed the technical issues identified by ~~NYSDEC and in May 2018, we refiled our application for~~ the ~~permits.~~agencies. We plan to place the project into service in the fourth quarter of 2020, assuming timely receipt of ~~all necessary regulatory~~these remaining approvals. The project is expected to increase capacity by 400 Mdth/d.

~~Rivervale South to Market~~Southeastern Trail

In ~~August 2018,~~October 2019, we received approval from the FERC to expand Transco’s existing natural gas transmission system to provide incremental firm transportation capacity from the existing Rivervale interconnection with Tennessee Gas Pipeline on Transco’s North New Jersey Extension to other existing Transco locations within New Jersey. We plan to place the project into service as early as the fourth quarter of 2019, assuming timely receipt of all necessary regulatory approvals. The project is expected to increase capacity by 190 Mdth/d.

~~Southeastern Trail~~

~~In April 2018, we filed an application with~~ the FERC to expand Transco’s existing natural gas transmission system to provide incremental firm transportation capacity from the Pleasant Valley interconnect with Dominion’s Cove Point Pipeline in Virginia to the Station 65 pooling point in Louisiana. We plan to place the project into

Management’s Discussion and Analysis (Continued)

service in late 2020, assuming timely receipt of all remaining necessary regulatory approvals. The project is expected to increase capacity by 296 Mdth/d.

Leidy South

In July 2019, we filed an application with the FERC for approval of the project to expand Transco’s existing natural gas transmission system and also extend its system through a capacity lease with National Fuel Gas Supply Corporation that will enable us to provide incremental firm transportation from Clermont, Pennsylvania and from the Zick interconnection on Transco’s Leidy Line to the River Road regulating station in Lancaster County, Pennsylvania. We plan to place the project into service in the second half of 2022, assuming timely receipt of all necessary regulatory approvals. The project is expected to increase capacity by ~~296~~582 Mdth/d.

West

North Seattle Lateral Upgrade

In July 2018, we received approval from the FERC to expand delivery capabilities on Northwest Pipeline’s North Seattle Lateral. The project consists of the removal and replacement of approximately 5.9 miles of 8-inch diameter pipeline with new 20-inch diameter pipeline. We plan to place the project into service ~~as early as~~during the fourth quarter of ~~2019, assuming timely receipt of all necessary regulatory approvals.~~2019. The project is expected to increase delivery capacity by approximately 159 Mdth/d.

Wamsutter Expansion

We ~~are expanding~~have expanded our gathering and processing infrastructure in the Wamsutter region of Wyoming in order to meet our customers’ production plans. We have completed construction of new compressor stations and modifications to our processing facilities, which are now in service. The expansion ~~includes the addition of~~added approximately 5420 miles of gathering pipelines and ~~compression,~~approximately 15,000 horsepower of compression. Additional expansion is expected in 2020, subject to the level of production activity in the area.

Project Bluestem

We are expanding our presence in the Mid-Continent region through building a 188-mile pipeline from our fractionator near Conway, Kansas to an interconnect with a third-party NGL pipeline system in Oklahoma, providing us with firm access to Mt. Belvieu pricing. As part of the project, the third-party intends to construct a 110-mile pipeline extension of their existing NGL pipeline system that will have an initial capacity of 120 Mbbls/d. Further, during the first quarter of 2019, we exercised an option to purchase a 20 percent equity interest in a Mt. Belvieu fractionation train developed by the third party. The pipeline and ~~modifications~~extension projects are expected to ~~existing treating and processing facilities. We plan to place the project~~be placed into service during the first quarter of ~~2019.~~2021.

Critical Accounting Estimates

Constitution Pipeline Capitalized Project Costs

As of September 30, ~~2018,~~ 2019, Property, plant, and equipmentinour Consolidated Balance Sheet includes approximately ~~$377~~$376 million of capitalized project costs for Constitution, for which we are the construction manager and own a 41 percent consolidated interest. As a result of the events discussed in ~~Company Outlook,~~Note 4 – Variable Interest Entities of Notes to Consolidated Financial Statements, we have evaluated the capitalized project costs for impairment ~~as recently as December 31, 2017,~~ and determined that no impairment was necessary. Our evaluation considered probability-weighted scenarios of undiscounted future net cash flows, including scenarios assuming construction of the pipeline, as well as a scenario where the project does not proceed. These scenarios included our most recent estimate of total construction costs. The probability-weighted scenarios also considered our assessment of the likelihood of success of the path to obtain necessary certification, as described in Company Outlook. It is reasonably possible that future unfavorable developments, such as ~~a reduced likelihood of success,~~failure to successfully renegotiate associated customer contracts, increased estimates of construction costs, or further significant delays, could result in a future impairment.

~~Management’s Discussion and Analysis (Continued)~~

~~Equity-Method Investments~~

As of September 30, 2018, the carrying value of our equity-method investment in Discovery is $514 million. During the fourth quarter of 2017, certain customers of Discovery terminated a significant offshore gas gathering agreement following the shut-in of production after the associated wells ceased flowing. As a result, we evaluated this investment for impairment in the fourth quarter of 2017 and determined that no impairment was necessary.

This evaluation included probability-weighted assumptions of additional commercial development, assigning higher probabilities to those commercial development opportunities that were more advanced in the discussion and contracting process, that utilized existing infrastructure due to producer capital constraints, and/or that we believe Discovery has a competitive advantage due to geographical proximity to the prospect. We continue to monitor this investment as it is reasonably possible that an impairment could be required in the future if commercial development activities are not as successful or as timely as assumed.

Regulatory Liabilities Resulting from Tax Reform

In December 2017, the Tax ~~Reform~~Cuts and Jobs Act (Tax Reform) was enacted, which, among other things, reduced the corporate income tax rate from 35 percent to 21 percent. Rates charged to customers of our regulated natural gas

Management’s Discussion and Analysis (Continued)

pipelines are subject to the rate-making policies of the FERC, which have historically permitted the recovery of an income tax allowance that includes a deferred income tax component. ~~As a result of~~Due to the reduced income tax rate from Tax Reform and the collection of historical rates that reflected historical federal income tax rates, we expect that our regulated natural gas pipelines will be required to return amounts to certain customers through future ~~rates and have accordingly~~rates. As a result, we established regulatory liabilities ~~totaling $657 million as of~~during 2017 and at September 30, ~~2018.~~2019, these liabilities total $609 million. The timing and actual amount of such return related to Transco will be subject to the final outcome of the rate case discussed in Overview while the amount of such return related to Northwest Pipeline will be subject to future negotiations regarding this matter and many other elements of ~~cost–of–service~~cost-of-service rate proceedings, including other costs of providing service.

Equity-Method Investments

We continue to monitor our equity-method investments for any indications that the carrying value may have experienced an other-than-temporary decline in value. When evidence of a loss in value has occurred, we compare our estimate of the fair value of the investment to the carrying value of the investment to determine whether an impairment has occurred. We generally estimate the fair value of our investments using an income approach where significant judgments and assumptions include expected future cash flows and the appropriate discount rate. In some cases, we may utilize a form of market approach to estimate the fair value of our investments. During 2019, we have recognized impairments totaling $186 million related to our equity-method investments. (See Note 13 – Fair Value Measurements and Guarantees of Notes to Consolidated Financial Statements.)

Management’s Discussion and Analysis (Continued)

Results of Operations

Consolidated Overview

The following table and discussion is a summary of our consolidated results of operations for the three and nine months ended September 30, ~~2018,~~2019, compared to the three and nine months ended September 30, ~~2017.~~2018. The results of operations by segment are discussed in further detail following this consolidated overview discussion.


	Three Months Ended September 30,									Nine Months Ended September 30,									Three Months Ended September 30,									Nine Months Ended September 30,
	2018			2017			$ Change*	% Change*		2018			2017			$ Change*	% Change*		2019			2018			$ Change*	% Change*		2019			2018			$ Change*	% Change*
	(Millions)									(Millions)									(Millions)									(Millions)
Revenues:
Service revenues	$	1,371		$	1,310		+61	+5	%	$	4,062		$	3,853		+209	+5	%	$	1,495		$	1,371		+124	+9	%	$	4,424		$	4,062		+362	+9	%
Service revenues – commodity consideration	121			—			+121	NM		316			—			+316	NM		38			121			-83	-69	%	158			316			-158	-50	%
Product sales	811			581			+230	+40	%	2,104			1,950			+154	+8	%	466			811			-345	-43	%	1,512			2,104			-592	-28	%
Total revenues	2,303			1,891						6,482			5,803						1,999			2,303						6,094			6,482
Costs and expenses:
Product costs	790			504			-286	-57	%	2,039			1,620			-419	-26	%	434			790			+356	+45	%	1,442			2,039			+597	+29	%
Processing commodity expenses	30			—			-30	NM		91			—			-91	NM		19			30			+11	+37	%	83			91			+8	+9	%
Operating and maintenance expenses	389			403			+14	+3	%	1,134			1,166			+32	+3	%	364			389			+25	+6	%	1,091			1,134			+43	+4	%
Depreciation and amortization expenses	425			433			+8	+2	%	1,290			1,308			+18	+1	%	435			425			-10	-2	%	1,275			1,290			+15	+1	%
Selling, general, and administrative expenses	174			138			-36	-26	%	436			452			+16	+4	%	130			174			+44	+25	%	410			436			+26	+6	%
Gain on sale of Geismar Interest	—			(1,095		)	-1,095	-100	%	—			(1,095		)	-1,095	-100	%
Impairment of certain assets	—			1,210			+1,210	+100	%	66			1,236			+1,170	+95	%	—			—			—	—		76			66			-10	-15	%
Other (income) expense – net	(6		)	24			+30	NM		24			34			+10	+29	%	(11		)	(6		)	+5	+83	%	30			24			-6	-25	%
Total costs and expenses	1,802			1,617						5,080			4,721						1,371			1,802						4,407			5,080
Operating income (loss)	501			274						1,402			1,082						628			501						1,687			1,402
Equity earnings (losses)	105			115			-10	-9	%	279			347			-68	-20	%	93			105			-12	-11	%	260			279			-19	-7	%
Other investing income (loss) – net	2			4			-2	-50	%	74			278			-204	-73	%	(107		)	2			-109	NM		(54		)	74			-128	NM
Interest expense	(270		)	(267		)	-3	-1	%	(818		)	(818		)	—	—	%	(296		)	(270		)	-26	-10	%	(888		)	(818		)	-70	-9	%
Other income (expense) – net	52			23			+29	+126	%	99			124			-25	-20	%	1			52			-51	-98	%	19			99			-80	-81	%
Income (loss) before income taxes	390			149						1,036			1,013						319			390						1,024			1,036
Provision (benefit) for income taxes	190			24			-166	NM		297			126			-171	-136	%	77			190			+113	+59	%	244			297			+53	+18	%
Net income (loss)	200			125						739			887						242			200						780			739
Less: Net income (loss) attributable to noncontrolling interests	71			92			+21	+23	%	323			400			+77	+19	%	21			71			+50	+70	%	54			323			+269	+83	%
Net income (loss) attributable to The Williams Companies, Inc.	$	129		$	33					$	416		$	487					$	221		$	129					$	726		$	416


*	+ = Favorable change; - = Unfavorable change; NM = A percentage calculation is not meaningful due to a change in signs, a zero-value denominator, or a percentage change greater than 200.

Management’s Discussion and Analysis (Continued)

Three months ended September 30, ~~2018~~2019 vs. three months ended September 30, ~~2017~~2018

Service revenuesincreased primarily due to higher transportation fee revenues at Transco associated with expansion projects placed ~~in-service~~ in ~~2017~~service in 2019 and 2018, ~~as well as~~from UEOM, which is now a consolidated entity after the remaining ownership interest was purchased in March 2019, and from higher ~~gathering~~ volumes at the Susquehanna Supply Hub. These increases are partially offset by the absence of revenues associated with asset divestitures and deconsolidations during 2018, including our former Four Corners area operations, and lower deferred revenue recognition in the Barnett Shale associated with the end of a contractual MVC period.

Service revenues – commodity consideration~~increased as~~ decreased primarily due to lower NGL prices, and lower volumes due to the ~~result~~absence of ~~implementing ASC 606 using a modified retrospective approach, effective January 1, 2018. Therefore, prior periods have not been recast under the new guidance.~~our former Four Corners area operations and ethane rejection. These revenues represent consideration we receive in the form of commodities as full or partial payment for ~~gathering and~~ processing services provided. ~~(See Note 2 – Revenue Recognition of Notes to Consolidated Financial Statements.)~~ Most of these NGL volumes are sold within the month processed and therefore are offset in Product costs below.

Product sales~~increased~~decreased primarily due to ~~higher~~lower NGL and natural gas prices associated with our marketing ~~revenues~~ and ~~higher~~equity NGL sales activities. This decrease also includes lower volumes from our equity NGL sales primarily reflecting the ~~production~~absence of our ~~equity NGLs, both reflecting higher NGL prices. Higher~~former Four Corners area operations and lower system management gas sales, ~~which~~partially offset by higher marketing volumes. Marketing revenues and system management gas sales are substantially offset in Product costs~~, also contributed to the increase.~~.

~~The increase in~~ Product costsis decreased primarily due to ~~the impact of ASC 606 in which costs reflected in this line item for 2018 include~~lower NGL and natural gas prices associated with our marketing and equity NGL production activities. This decrease also includes lower volumes acquired as commodity consideration for NGL processing services ~~as well as higher marketing costs~~reflecting the absence of our former Four Corners area operations and lower system management gas ~~costs. This increase is~~costs, partially offset by higher volumes for marketing activities.

Operating and maintenance expenses decreased primarily due to the absence of our former Four Corners area operations and a decrease in Transco’s contracted services mainly due to the timing of required engine overhauls and integrity testing, partially offset by the ~~absence~~consolidation of ~~natural gas purchases associated with the production of equity NGLs, which are now reported in~~ ~~Processing commodity expenses~~ ~~in conjunction with the implementation of ASC 606.~~

~~Processing commodity expenses~~ ~~presents the natural gas purchases associated with the production of equity NGLs as previously described in conjunction with the implementation of ASC 606~~.

~~Operating~~UEOM, and ~~maintenance expenses~~ ~~decreased primarily due to lower~~by an accrual for estimated severance and related costs ~~including reduced hydrotesting related to certain compliance projects that occurred in 2017.~~

~~Selling, general, and administrative expenses~~ increased primarily due to a charitable contribution of preferred stock to The Williams Companies Foundation, Inc. (see Note 11 – Stockholders’ Equity of Notes to Consolidated Financial Statements) and fees associated with the WPZ Merger, partially offset by the absence of severance-related and organizational realignment costs incurred in 2017.

~~The unfavorable change in~~ ~~Gain on sale of Geismar Interest~~ ~~reflects the absence of the gain recognized on the sale of our Geismar Interest in July 2017 (see Note 4 – Divestitures and Assets Held for Sale of Notes to Consolidated Financial Statements.)~~

~~The favorable change in~~ ~~Impairment of certain assets~~ includes the absence of 2017 impairments associated with certain assets in the Marcellus South, Mid-Continent, and Houston Ship Channel areas (see Note 12 – Fair Value Measurements and Guarantees of Notes to Consolidated Financial Statements.)

~~The favorable change in~~ ~~Operating income (loss)~~ ~~includes the absence of~~ ~~Impairment of certain assets~~ incurred in 2017, and the benefit of establishing a regulatory asset associated with an increase in Transco’s estimated deferred state income tax rate following the WPZ Merger. Also included are an increase in ~~Service revenues~~ primarily associated with Transco projects placed in-service in 2017 and 2018, higher gathering volumes, and favorable NGL and marketing commodity margins reflecting higher NGL prices and volumes. The favorable change was partially offset by the absence of the 2017 ~~Gain on sale of Geismar Interest~~ ~~and higher costs associated with~~ our ~~charitable contribution of preferred stock, and WPZ Merger-related fees.~~

~~The unfavorable change in~~ ~~Equity earnings (losses)~~ ~~is primarily due to a decrease in volumes at Discovery, partially offset by improved results at our Appalachia Midstream Investments.~~

~~Management’s Discussion and Analysis (Continued)~~

~~The favorable change in~~ ~~Other income (expense) – net~~ ~~below~~ ~~Operating income (loss)is primarily due to an increase in equity funds used during construction (AFUDC). (See~~voluntary separation program (VSP) (see Note 6 – Other Income and Expenses of Notes to Consolidated Financial ~~Statements.)~~Statements).

Depreciation and amortization expenses increased primarily due to the consolidation of UEOM and new assets placed in service, substantially offset by the 2018 impairment of certain assets in the Barnett Shale region.

Selling, general, and administrative expenses decreased primarily due to the absences of a charge for a 2018 charitable contribution of preferred stock to The Williams Companies Foundation, Inc. and fees associated with the WPZ Merger.

The favorable change in Other (income) expense – net within Operating income (loss) includes net favorable changes to charges and credits to regulatory assets and liabilities, partially offset by the absence of a 2018 gain on asset retirement (see Note 6 – Other Income and Expenses of Notes to Consolidated Financial Statements).

The favorable change in Operating income (loss) includes an increase in Service revenues primarily associated with Transco projects placed in-service and higher gathering volumes in the Northeast region, the absence of a charge for a charitable contribution of preferred stock to the Williams Foundation, Inc., and the absence of fees associated with the WPZ Merger, partially offset by unfavorable commodity margins primarily reflecting lower NGL sales prices and lower volumes.

The unfavorable change in Other investing income (loss) – net is primarily due to 2019 impairments to our equity-method investments, including Laurel Mountain (see Note 13 – Fair Value Measurements and Guarantees of Notes to Consolidated Financial Statements).

Interest expense increased primarily due to an increase in financing obligations associated with Transco’s Atlantic Sunrise project and lower capitalized interest due to projects placed in service.

Management’s Discussion and Analysis (Continued)

The unfavorable change in Other income (expense) – net below Operating income (loss) is primarily due to a decrease in equity AFUDC associated with reduced capital expenditures on projects and 2019 charges for loss contingencies associated with former operations.

Provision (benefit) for income taxes changed ~~unfavorably~~favorably primarily due to the absence of a $105 million 2018 valuation allowance on certain deferred tax assets that may not be realized following the WPZ ~~Merger and~~merger, partially offset by higher pre-tax income ~~partially offset by the decrease in the federal statutory rate from 35 percent~~attributable to ~~21 percent with the enactment of Tax Reform.~~The Williams Companies, Inc. See Note 7 – Provision (Benefit) for Income Taxes of Notes to Consolidated Financial Statements for a discussion of the effective tax rate compared to the federal statutory rate for both periods.

The favorable change in Net income (loss) attributable to noncontrolling interests is primarily due to our third- quarter 2018 acquisition of the publicly held interests in WPZ associated with the WPZ Merger.

Nine months ended September 30, ~~2018~~2019 vs. nine months ended September 30, ~~2017~~2018

Service revenuesincreased primarily due to higher transportation fee revenues at Transco ~~primarily~~ associated with expansion projects placed ~~in-service~~ in ~~2017~~service in 2019 and 2018 and the consolidation of UEOM, as well as higher ~~gathering~~volumes at the Susquehanna Supply Hub, and ~~processing~~higher rates and volumes ~~across most of our operating locations.~~from new wells in the Utica Shale region. These increases ~~were~~are partially offset by the absence of revenues associated with asset divestitures and deconsolidations during 2018, including our former Four Corners area operations, and lower deferred revenue recognition in the Barnett Shale associated with the end of a ~~decrease due to a reduction of rates resulting from a Northwest Pipeline rate case settlement.~~contractual MVC period.

Service revenues – commodity consideration~~increased as~~ decreased due to lower NGL prices and lower volumes primarily due to the ~~result~~absence of ~~implementing ASC 606 using a modified retrospective approach, effective January 1, 2018. Therefore, prior periods have not been recast under the new guidance.~~our former Four Corners area operations. These revenues represent consideration we receive in the form of commodities as full or partial payment for ~~gathering and~~ processing services provided. ~~(See Note 2 – Revenue Recognition of Notes to Consolidated Financial Statements.)~~ Most of these NGL volumes are sold within the month processed and therefore are offset in Product costs below.

Product sales~~increased~~decreased primarily due to ~~higher~~lower NGL and natural gas prices associated with our marketing ~~revenues~~ and ~~higher~~equity NGL sales activities and lower volumes from our equity NGL sales primarily reflecting the absence of our former Four Corners area operations and lower system management gas sales, partially offset by ~~the absence of $268 million~~higher marketing volumes. Marketing revenues and system management gas sales are substantially offset in ~~olefin revenue~~Product costs.

Product costs decreased primarily due to lower NGL and natural gas prices associated with our ~~former olefin operations in 2017. The increase in~~ marketing ~~revenue is driven by higher~~and equity NGL ~~prices and volumes, partially offset by~~production activities. This decrease also includes lower ~~crude oil and olefin-related volumes.~~

~~The increase in~~ ~~Product costs~~ ~~is primarily due to the impact of ASC 606 in which costs reflected in this line item for 2018 include~~ volumes acquired as commodity consideration for NGL processing services ~~as well as higher marketing~~reflecting the absence of our former Four Corners area operations and lower system management gas ~~costs. This increase is~~costs, partially offset by ~~the absence of $147 million of olefin feedstock~~higher volumes ~~associated with our former olefin operations, as well as the absence of natural gas purchases associated with the production of equity NGLs, which are now reported in~~ ~~Processing commodity expenses~~ ~~in conjunction with the implementation of ASC 606.~~for marketing activities.

~~Processing commodity expenses~~ ~~presents the natural gas purchases associated with the production of equity NGLs as previously described in conjunction with the implementation of ASC 606~~.

Operating and maintenance expensesdecreased primarily due to the absence of ~~$52 million of costs associated with~~ our former ~~olefin~~Four Corners area operations, partially offset by ~~higher operating~~the consolidation of UEOM, and ~~maintenance expenses at Transco~~by an accrual for estimated severance and related costs primarily associated with ~~general maintenance and other testing and labor costs.~~our VSP.

Depreciation and amortization expenses decreased primarily due to the 2018 impairment of certain assets in the Barnett Shale region and the absence of ~~costs associated with~~ our former ~~olefin~~Four Corners area operations, partially offset by new assets placed ~~in-service.~~in service and by the consolidation of UEOM.

Selling, general, and administrative expenses decreased primarily due to the ~~absence~~absences of severance-related, organizational realignment, the absence of $17 million in costs associated with our former olefin operations, Financial Repositioning costs incurred in 2017, and ongoing cost containment efforts. These decreases are partially offset by a charitable contribution of preferred stock to the Williams Foundation, Inc. and fees associated with the WPZ ~~Merger.~~Merger, partially offset by an accrual for estimated severance and related costs primarily associated with our VSP, and transaction expenses associated with the acquisition of UEOM and the formation of the Northeast JV.

The unfavorable change in ~~Gain on sale~~Impairment of ~~Geismar Interest~~ ~~reflects~~certain assets includes a second-quarter 2019 impairment of certain Eagle Ford Shale gathering assets and a first-quarter 2019 impairment of certain idle gathering assets, partially offset by the absence of a 2018 impairment of certain idle pipelines.

The unfavorable change in Other (income) expense – net within Operating income (loss) includes the absence of a 2018 gain ~~recognized~~ on asset retirement, a 2019 charge for the ~~sale~~reversal of ~~our Geismar Interest in July 2017 (see Note 4 – Divestitures~~expenditures previously capitalized, and ~~Assets Held for Sale of Notes to Consolidated Financial Statements.)~~net unfavorable

Management’s Discussion and Analysis (Continued)

~~The favorable change in~~ ~~Impairment of certain~~changes to charges and credits to regulatory assets ~~includes the absence of 2017 impairments associated with certain assets in the Marcellus South, Mid-Continent,~~ and ~~Houston Ship Channel areas, partially offset by the impairment of certain idle pipelines in 2018~~liabilities (see ~~Note 12 – Fair Value Measurements and Guarantees of Notes to Consolidated Financial Statements.)~~

~~The favorable change inOther (income) expense – net~~ ~~within~~ ~~Operating income (loss)~~ includes the benefit of establishing a regulatory asset associated with an increase in Transco’s estimated deferred state income tax rate following the WPZ Merger and favorable adjustments to certain regulatory charges associated with Tax Reform. These favorable adjustments are partially offset by the absence of gains from certain contract settlements and terminations in 2017, the absence of a gain on the sale of our RGP Splitter in 2017, and 2018 regulatory charges associated with both Northwest Pipeline’s approved rates related to Tax Reform and establishing a regulatory liability associated with a decrease in Northwest Pipeline's estimated deferred state income tax rate following the WPZ Merger.

~~The favorable change in~~ ~~Operating income (loss)~~ ~~includes the absence of~~ ~~Impairment of certain assets, an increase in~~ ~~Service revenues~~ primarily associated with Transco projects placed in-service in 2017 and 2018, higher gathering and processing volumes across most of our operating locations, the benefit of establishing a regulatory asset associated with an increase in Transco’s estimated deferred state income tax rate following the WPZ Merger, as well as higher NGL and marketing margins, and lower severance-related, organizational realignment, and Financial Repositioning costs. These favorable changes are partially offset by the absence of the 2017 ~~Gain on sale of Geismar Interest~~, the absence of operating income related to our former olefin operations, a charitable contribution of preferred stock, 2018 regulatory charges associated with both Northwest Pipeline’s approved rates related to Tax Reform and establishing a regulatory liability associated with a decrease in Northwest Pipeline's estimated deferred state income tax rate following the WPZ Merger, and higher operating costs at Transco.

~~The unfavorable change in~~ ~~Equity earnings (losses)~~ ~~is primarily due to a decrease in volumes at Discovery, partially offset by improved results at our Appalachia Midstream Investments.~~

~~The unfavorable change in~~ ~~Other investing income (loss) – net~~ is due to the absence of a gain on disposition of our investments in DBJV and Ranch Westex JV LLC in 2017, partially offset by a gain on the deconsolidation of our interest in Jackalope in 2018. (See Note 5 – Investing Activities of Notes to Consolidated Financial Statements.)

~~The unfavorable change in~~ ~~Other income (expense) – net~~ ~~below~~ ~~Operating income (loss)~~ ~~is primarily due to the absence of a net gain on early retirement of debt in 2017 and a loss on early retirement of debt in 2018. (See~~ Note 6 – Other Income and Expenses of Notes to Consolidated Financial ~~Statements.) This unfavorable~~Statements).

The favorable change isin Operating income (loss) includes an increase in Service revenues primarily associated with Transco projects placed in-service and higher gathering volumes in the Northeast region, the favorable impact of acquiring the additional interest of UEOM, the absence of a charitable contribution of preferred stock to the Williams Foundation, Inc., and the absence of fees associated with the WPZ Merger. These favorable changes were partially offset by the impact of asset divestitures and deconsolidations during 2018, including our former Four Corners area operations, unfavorable commodity margins primarily reflecting lower NGL sales prices and lower volumes, an accrual for estimated severance and related costs primarily associated with our VSP, and transaction expenses associated with the acquisition of UEOM and the formation of the Northeast JV.

The unfavorable change in Other investing income (loss) – net reflects noncash impairments to equity method investments (see Note 13 – Fair Value Measurements and Guarantees of Notes to Consolidated Financial Statements) and the absence of a 2018 gain on deconsolidation of our former Jackalope operations, partially offset by a 2019 gain on sale of our equity-method investment in Jackalope.

Interest expense increased primarily due to an increase in financing obligations associated with Transco’s Atlantic Sunrise project.

The unfavorable change in Other income (expense) – net below Operating income (loss) is primarily due to a decrease in equity ~~AFUDC.~~AFUDC associated with reduced capital expenditures on projects.

Provision (benefit) for income taxes changed ~~unfavorably~~favorably primarily due to the absence of ~~releasing a $127 million valuation allowance on a capital loss carryover in 2017,~~ a $105 million 2018 valuation allowance on certain deferred tax assets that may not be realized following the WPZ ~~Merger, and~~merger, partially offset by higher pre-tax income ~~partially offset by the decrease in the federal statutory rate from 35 percent~~attributable to ~~21 percent with the enactment of Tax Reform.~~The Williams Companies, Inc. See Note 7 – Provision (Benefit) for Income Taxes of Notes to Consolidated Financial Statements for a discussion of the effective tax rate compared to the federal statutory rate for both periods.

Period-Over-Period Operating Results - Segments

We evaluate segment operating performance based upon Modified EBITDA. Note 1415 – Segment Disclosures of Notes to Consolidated Financial Statements includes a reconciliation of this non-GAAP measure to Net income (loss). Management uses Modified EBITDA because it is an accepted financial indicator used by investors to compare company performance. In addition, management believes that this measure provides investors an enhanced perspective of the operating performance of our assets. Modified EBITDA should not be considered in isolation or as a substitute for a measure of performance prepared in accordance with GAAP.

Management’s Discussion and Analysis (Continued)

Northeast G&P


	Three Months Ended September 30,						Nine Months Ended September 30,						Three Months Ended September 30,						Nine Months Ended September 30,
	2018			2017			2018			2017			2019			2018			2019			2018
	(Millions)												(Millions)
Service revenues	$	247		$	214		$	707		$	648		$	353		$	247		$	959		$	707
Service revenues – commodity consideration	6			—			14			—			1			6			9			14
Product sales	69			61			242			181			30			69			114			242
Segment revenues	322			275			963			829			384			322			1,082			963

Product costs	(69		)	(61		)	(245		)	(179		)	(29		)	(69		)	(114		)	(245		)
Processing commodity expenses	(3		)	—			(7		)	—			(1		)	(3		)	(6		)	(7		)
Other segment costs and expenses	(100		)	(98		)	(279		)	(273		)	(117		)	(100		)	(348		)	(279		)
Impairment of certain assets	—			(121		)	—			(123		)
Proportional Modified EBITDA of equity-method investments	131			120			354			334			108			131			333			354
Northeast G&P Modified EBITDA	$	281		$	115		$	786		$	588		$	345		$	281		$	947		$	786

Commodity margins													$	1		$	3		$	3		$	4



~~DELAWARE~~Delaware		73-0569878
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)

~~ONE WILLIAMS CENTER~~One Williams Center
~~TULSA, OKLAHOMA~~Tulsa	Oklahoma	74172-0172
~~(Address~~ (Address of principal executive offices)		(Zip Code)



Title of each class	Trading Symbol(s)	Name of each exchange on which registered
Common Stock, $1.00 par value	WMB	New York Stock Exchange



Class		Shares Outstanding at October ~~29, 2018~~28, 2019
Common Stock, $1$1.00 par value		~~1,210,542,031~~1,212,048,836



		Page
Part I. Financial Information
Item 1. Financial Statements
Consolidated Statement of Income – Three and Nine Months Ended September 30, ~~2018~~2019 and ~~2017~~2018		6
Consolidated Statement of Comprehensive Income – Three and Nine Months Ended September 30, ~~2018~~2019 and ~~2017~~2018		7
Consolidated Balance Sheet – September 30, ~~2018~~2019 and December 31, ~~2017~~2018		8
Consolidated Statement of Changes in Equity – Three and Nine Months Ended September 30, 2019 and 2018		9
Consolidated Statement of Cash Flows – Nine Months Ended September 30, ~~2018~~2019 and ~~2017~~		10
~~Notes to Consolidated Financial Statements~~2018		11
Notes to Consolidated Financial Statements		12
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations		4640
Item 3. Quantitative and Qualitative Disclosures About Market Risk		7161
Item 4. Controls and Procedures		7161
Part II. Other Information		7161
Item 1. Legal Proceedings		7161
Item 1A. Risk Factors		7363
Item 6. Exhibits		7464



þ☑	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934



¨☐	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934



	Quarter-to-Date September 30, 2018		Year-to-Date September 30, 2018
	(Millions)
Balance at beginning of period	$	39	$	4
Revenue recognized in excess of cash received	17		53
Minimum volume commitments invoiced	—		(1		)
Balance at end of period	$	56	$	56



	(Millions)
2018 (remainder)	$	191
2019	257
2020	129
2021	110
2022	103
2023	100
Thereafter	595
Total	$	1,485



	September 30, 2018		January 1, 2018
	(Millions)
Accounts receivable related to revenues from contracts with customers	$	795	$	958
Other accounts receivable	88		18
Total reflected in Trade accounts and other receivables	$	883	$	976



	As Reported			Adjustments resulting from adoption of ASC 606			Balance without adoption of ASC 606
	(Millions)
Consolidated Statement of Income
Three Months Ended September 30, 2018
Service revenues	$	1,371		$	5		$	1,376
Service revenues – commodity consideration	121			(121		)	—
Product sales	811			44			855
Total revenues	2,303			(72		)	2,231
Product costs	790			(48		)	742
Processing commodity expenses	30			(30		)	—
Depreciation and amortization expenses	425			1			426
Total costs and expenses	1,802			(77		)	1,725
Operating income (loss)	501			5			506
Interest incurred	(286		)	4			(282		)
Interest capitalized	16			(2		)	14
Income (loss) before income taxes	390			7			397
Provision (benefit) for income taxes	190			1			191
Net income (loss)	200			6			206
Less: Net income (loss) attributable to noncontrolling interests	71			(1		)	70
Net income (loss) attributable to The Williams Companies, Inc.	129			7			136
Basic earnings (loss) per common share	$	0.13		$	0.01		$	0.14
Diluted earnings (loss) per common share	$	0.13		$	0.01		$	0.14

Nine Months Ended September 30, 2018
Service revenues	$	4,062		$	16		$	4,078
Service revenues – commodity consideration	316			(316		)	—
Product sales	2,104			86			2,190
Total revenues	6,482			(214		)	6,268
Product costs	2,039			(143		)	1,896
Processing commodity expenses	91			(91		)	—
Operating and maintenance expenses	1,134			3			1,137
Depreciation and amortization expenses	1,290			2			1,292
Total costs and expenses	5,080			(229		)	4,851



	September 30, 2018			December 31, 2017 (1)			Classification
	(Millions)
Assets (liabilities):
Cash and cash equivalents	$	32		$	881		Cash and cash equivalents
Trade accounts and other receivables – net	57			972			Trade accounts and other receivables
Inventories	—			113			Inventories
Other current assets	1			176			Other current assets and deferred charges
Investments	—			6,552			Investments
Property, plant, and equipment – net	2,398			27,912			Property, plant, and equipment – net
Intangible assets – net	1,189			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	(16		)	(957		)	Accounts payable
Accrued liabilities including current asset retirement obligations	(98		)	(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	(104		)	(944		)	Regulatory liabilities, deferred income, and other
Regulatory liabilities, deferred income, and other noncurrent liabilities	(189		)	(2,809		)	Regulatory liabilities, deferred income, and other



	Carrying Amount
	September 30, 2018
	(Millions)
Assets:
Current assets	$	23
Property, plant, and equipment – net	539
Other noncurrent assets	12
	$	574

Liabilities:
Current liabilities	$	22
Other noncurrent liabilities	23
	$	45



							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 September 30, 2019:
Measured on a recurring basis:
ARO Trust investments	$	187		$	187		$	187		$	—		$	—
Energy derivatives assets not designated as hedging instruments	4			4			4			—			—
Energy derivatives liabilities not designated as hedging instruments	(5		)	(5		)	(2		)	—			(3		)
Additional disclosures:
Long-term debt, including current portion	(22,257		)	(25,234		)	—			(25,234		)	—
Guarantees	(42		)	(29		)	—			(13		)	(16		)

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		)



						Impairments
						Nine Months Ended September 30,
	Classification	Segment	Date of Measurement	Fair Value		2018		2017
				(Millions)
Certain idle pipeline assets (1)	Property, plant, and equipment – net	Other	June 30, 2018	$	25	$	66
Certain gathering operations (2)	Property, plant, and equipment – net and Intangible assets - net of accumulated amortization	West	September 30, 2017	439				$	1,019
Certain gathering operations (3)	Property, plant, and equipment – net and Intangible assets - net of accumulated amortization	Northeast G&P	September 30, 2017	21				115
Certain NGL pipeline (4)	Property, plant, and equipment – net	Other	September 30, 2017	32				68
Certain olefins pipeline project (5)	Property, plant, and equipment – net	Other	June 30, 2017	18				23
Fair value measurements of certain assets						66		1,225
Other impairments and write-downs (6)						—		11
Impairment of certain assets						$	66	$	1,236


(1)	Relates to a gas gathering system in the Eagle Ford region with expected declines in asset utilization and possible idling of the gathering system. The estimated fair value of the Property, plant, and equipment – net was determined using a market approach which incorporated indications of interest from third parties.


(2)	Reflects impairment of Property, plant, and equipment – net that is no longer in use for which the fair value was determined to be lower than the carrying value.


(7)	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.~~


~~(4)~~	~~Relates to an NGL pipeline near the Houston Ship Channel region which we anticipate will be underutilized for the foreseeable future. The estimated fair value was primarily determined by using~~ a market approach based on ~~our analysis of observable inputs in~~ the ~~principal market.~~


~~(6)~~	~~Reflects multiple individually insignificant impairments and write-downs of other certain assets that may no longer be in use or are surplus in nature for which~~ the fair value ~~was determined to be lower than~~hierarchy. This impairment is reported in Other investing income (loss) - net in the ~~carrying value.~~Consolidated Statement of Income.


•	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.



Sources:
	Cash and cash equivalents on hand
	Cash generated from operations
	Distributions from our equity-method investees
	Utilization of our credit facility and/or commercial paper program
	Cash proceeds from issuance of debt and/or equity securities
	Proceeds from asset monetizations
	Contributions from noncontrolling interests

Uses:
	Working capital requirements
	Capital and investment expenditures
	Quarterly dividends to our shareholders
	Debt service payments, including payments of long-term debt
	Distributions to noncontrolling interests


Available Liquidity	September 30, 2018		September 30, 2019
	(Millions)		(Millions)
Cash and cash equivalents	$	42	$	247
Capacity available under our $4.5 billion credit facility, less amounts outstanding under our $4 billion commercial paper program (1)	3,676		4,500
	$	3,718	$	4,747



Rating Agency	Outlook	Senior Unsecured Debt Rating	Corporate Credit Rating
S&P Global Ratings	~~Negative~~Stable	BBB	BBB
Moody’s Investors Service	Stable	Baa3	N/A
Fitch Ratings	Rating Watch Positive	BBB-	N/A



	Cash Flow	Nine Months Ended September 30,
	Category	2018			2017
		(Millions)
Sources of cash and cash equivalents:
Operating activities – net	Operating	$	2,331		$	2,231
Proceeds from long-term debt (see Note 10)	Financing	2,065			1,698
Proceeds from credit-facility borrowings	Financing	1,680			1,315
Proceeds from commercial paper – net	Financing	821			—
Contributions in aid of construction	Investing	395			253
Proceeds from equity issuances	Financing	15			2,130
Proceeds from sale of businesses, net of cash divested (see Note 4)	Investing	—			2,056
Proceeds from dispositions of equity-method investments (see Note 5)	Investing	—			200

Uses of cash and cash equivalents:
Capital expenditures	Investing	(2,659		)	(1,700		)
Payments on credit-facility borrowings	Financing	(1,950		)	(1,690		)
Payments of long-term debt (see Note 10)	Financing	(1,251		)	(3,785		)
Common dividends paid	Financing	(974		)	(744		)
Purchases of and contributions to equity-method investments	Investing	(803		)	(103		)
Dividends and distributions paid to noncontrolling interests	Financing	(552		)	(636		)
Payments of commercial paper – net	Financing	—			(93		)

Other sources / (uses) – net	Financing and Investing	25			(130		)
Increase (decrease) in cash and cash equivalents		$	(857	)	$	1,002



Exhibit No.		Description

2.1+	—	Agreement and Plan of Merger dated as of May 16, 2018, by and among The Williams Companies, Inc., SCMS LLC, Williams Partners L.P., and WPZ GP LLC (filed on May 17, 2018 as Exhibit 2.1 to The Williams Companies, Inc.’s current report on Form 8-K (File No. 001-04174) and incorporated herein by reference).
2.2	—	Amendment No 1. to Agreement and Plan of Merger dated as of May 1, 2016, by and among The Williams Companies, Inc., Energy Transfer Corp LP, Energy Transfer Corp GP, LLC, Energy Transfer Equity, L.P., LE GP, LLC and Energy Transfer Equity GP, LLC (filed on May 3, 2016 as Exhibit 2.1 to The Williams Companies, Inc.’s current report on Form 8-K (File No. 001-04174) and incorporated herein by reference).
2.3+	—	Agreement and Plan of Merger dated as of September 28, 2015, by and among The Williams Companies, Inc., Energy Transfer Corp LP, Energy Transfer Corp GP, LLC, Energy Transfer Equity, L.P., LE GP, LLC and Energy Transfer Equity GP, LLC (filed on October 1, 2015 as Exhibit 2.1 to The Williams Companies, Inc.’s current report on Form 8-K (File No. 001-04174) and incorporated herein by reference).
~~2.4+~~	—	Membership Interest Purchase Agreement, dated as of April 13, 2017, among Williams Field Services Group, LLC, Williams Partners L.P., Williams Olefins, L.L.C., NOVA Chemicals Inc., and NOVA Chemicals Corporation (filed on August 3, 2017 as Exhibit 2.2 to Williams Partners L.P.’s quarterly report on Form 10-Q (File No. 001-34831) and incorporated herein by reference).
3.1	—	Amended and Restated Certificate of Incorporation as supplemented (filed on May 26, 2010, as Exhibit 3.1 to The Williams Companies, Inc.’s current report on Form 8-K (File No. 001-04174) and incorporated herein by reference).
3.2	—	Certificate of Designations of Series B Preferred Stock of The Williams Companies, Inc. (filed on July 17, 2018 as Exhibit 3.1 to The Williams Companies, Inc. current report on Form 8-K (File No. 001-04174) and incorporated herein by reference).
3.3	—	Certificate of Amendment dated August 10, 2018 (filed on August 10, 2018 as Exhibit 3.1 to The Williams Companies, Inc.’s current report on Form 8-K (File No. 001-04174) and incorporated herein by reference).
3.4	—	By-Laws (filed on January 20, 2017, as Exhibit 3.1 to The Williams Companies, Inc.’s current report on Form 8-K (File No. 001-04174) and incorporated herein by reference).
~~4.1~~	—	Eleventh Supplemental Indenture, dated as of August 10, 2018, between The Williams Companies, Inc. and The Bank of New York Mellon Trust Company, N.A. (filed on August 10, 2018 as Exhibit 4.1 to The Williams Companies, Inc.’s current report on Form 8-K (File No. 001-04174) and incorporated herein by reference).
~~4.2~~	—	Second Supplemental Indenture, dated as of August 10, 2018, between The Williams Companies, Inc. and The Bank of New York Mellon Trust Company, N.A. (filed on August 10, 2018 as Exhibit 4.2 to The Williams Companies, Inc.’s current report on Form 8-K (File No. 001-04174) and incorporated herein by reference).
~~10.1~~	—	Credit Agreement dated as of July 13, 2018, between The Williams Companies, Inc., Northwest Pipeline LLC, and Transcontinental Gas Pipeline Company, LLC, as co-borrowers, the lenders named therein, and Citibank, N.A. as Administrative Agent (filed on July 17, 2018 as Exhibit 10.1 to The Williams Companies, Inc.’s Current Report on Form 8-K (File No. 001-04174) and incorporated herein by reference).
~~10.2~~	—	Form of Commercial Paper Dealer Agreement, dated as of August 10, 2018, between The Williams Companies, Inc., as Issuer, and the Dealer party thereto (filed on August 10, 2018 as Exhibit 10.1 to The Williams Companies, Inc.’s current report on Form 8-K (File No. 001-04174) and incorporated herein by reference).



~~Exhibit~~ ~~No.~~		~~Description~~

31.1*	—	Certification of Chief Executive Officer pursuant to Rules 13a-14(a) and 15d-14(a) promulgated under the Securities Exchange Act of 1934, as amended, and Item 601(b)(31) of Regulation S-K, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2*	—	Certification of Chief Financial Officer pursuant to Rules 13a-14(a) and 15d-14(a) promulgated under the Securities Exchange Act of 1934, as amended, and Item 601(b)(31) of Regulation S-K, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32**	—	Certification of Chief Executive Officer and Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
101.INS*	—	XBRL Instance Document. The instance document does not appear in the interactive data file because its XBRL tags are embedded within the inline XBRL document.
101.SCH*	—	XBRL Taxonomy Extension Schema.
101.CAL*	—	XBRL Taxonomy Extension Calculation Linkbase.
101.DEF*	—	XBRL Taxonomy Extension Definition Linkbase.
101.LAB*	—	XBRL Taxonomy Extension Label Linkbase.
101.PRE*	—	XBRL Taxonomy Extension Presentation Linkbase.
104*	—	Cover Page Interactive Data File. The cover page interactive data file does not appear in the interactive data file because its XBRL tags are embedded within the inline XBRL document (contained in Exhibit 101).


+	Pursuant to item 601(b)(2) of Regulation S-K, the registrant agrees to furnish supplementally a copy of any omitted exhibit or schedule to the SEC upon request.



	THE WILLIAMS COMPANIES, INC.
	(Registrant)

	/s/ TED T. TIMMERMANS
	Ted T. Timmermans
	Vice President, Controller and Chief Accounting Officer (Duly Authorized Officer and Principal Accounting Officer)