0000107263 us-gaap:OperatingSegmentsMember wmb:AtlanticGulfMember 2019-01-01 2019-09-30

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Commission file number 1-4174



~~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)

Registrant’s telephone number, including area code: ~~(918)~~ (918) 573-2000

Securities registered pursuant to Section 12(b) of the Act:



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

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yesþ ☑ No¨ ☐

Indicate by check mark whether the registrant has submitted electronically ~~and posted on its corporate Web site, if any,~~ every Interactive Data File required to be submitted ~~and posted~~ pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit ~~and post~~ such files). Yesþ ☑ No ¨☐

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.

Large accelerated filerþ

☑

Accelerated filer¨

☐

Non-accelerated filer¨

☐

Smaller reporting company¨

☐

Emerging growth company¨

~~(Do not check if a smaller reporting company)~~

☐

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ¨☐

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act.) Yes¨ ☐ Noþ ☑

Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date.



Class		Shares Outstanding at October ~~30, 2017~~28, 2019
Common Stock, $1$1.00 par value		~~826,746,549~~1,212,048,836

The Williams Companies, Inc.

The reports, filings, and other public announcements of The Williams Companies, Inc. (Williams) may contain or incorporate by reference statements that do not directly or exclusively relate to historical facts. Such statements are “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended (Securities Act), and Section 21E of the Securities Exchange Act of 1934, as amended (Exchange Act). These forward-looking statements relate to anticipated financial performance, management’s plans and objectives for future operations, business prospects, outcome of regulatory proceedings, market conditions, and other matters. We make these forward-looking statements in reliance on the safe harbor protections provided under the Private Securities Litigation Reform Act of 1995.

All statements, other than statements of historical facts, included in this report that address activities, events, or developments that we expect, believe, or anticipate will exist or may occur in the future, are forward-looking statements. Forward-looking statements can be identified by various forms of words such as “anticipates,” “believes,” “seeks,” “could,” “may,” “should,” “continues,” “estimates,” “expects,” “forecasts,” “intends,” “might,” “goals,” “objectives,” “targets,” “planned,” “potential,” “projects,” “scheduled,” “will,” “assumes,” “guidance,” “outlook,” “in-service date,” or other similar expressions. These forward-looking statements are based on management’s beliefs and assumptions and on information currently available to management and include, among others, statements regarding:

Forward-looking statements are based on numerous assumptions, uncertainties, and risks that could cause future events or results to be materially different from those stated or implied in this report. Many of the factors that will determine these results are beyond our ability to control or predict. Specific factors that could cause actual results to differ from results contemplated by the forward-looking statements include, among others, the following:

Given the uncertainties and risk factors that could cause our actual results to differ materially from those contained in any forward-looking statement, we caution investors not to unduly rely on our forward-looking statements. We disclaim any obligations to and do not intend to update the above list or announce publicly the result of any revisions to any of the forward-looking statements to reflect future events or developments.

In addition to causing our actual results to differ, the factors listed above and referred to below may cause our intentions to change from those statements of intention set forth in this report. Such changes in our intentions may also cause our results to differ. We may change our intentions, at any time and without notice, based upon changes in such factors, our assumptions, or otherwise.

Because forward-looking statements involve risks and uncertainties, we caution that there are important factors, in addition to those listed above, that may cause actual results to differ materially from those contained in the forward-looking statements. For a detailed discussion of those factors, see Part I, Item 1A. Risk Factors in our Annual Report on Form 10-K filed with the SEC on February ~~22, 2017.~~21, 2019.

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

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

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, ~~2017,~~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

~~UEOM:~~ ~~Utica East Ohio~~RMM: Rocky Mountain Midstream Holdings LLC

Government and ~~Regulatory:~~Regulatory:

EPA: Environmental Protection Agency

FERC: Federal Energy Regulatory Commission

SEC: Securities and Exchange Commission

Other:

~~Merger Agreement: Merger Agreement and Plan of Merger of Williams with Energy Transfer 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

~~PDH facility:~~ ~~Propane dehydrogenation 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

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

PART I – FINANCIAL INFORMATION

Item 1. Financial Statements

The Williams Companies, Inc.

Consolidated Statement of ~~Operations~~Income

(Unaudited)


	Three Months Ended September 30,						Nine Months Ended September 30,						Three Months Ended September 30,						Nine Months Ended September 30,
	2017			2016			2017			2016			2019			2018			2019			2018
	(Millions, except per-share amounts)												(Millions, except per-share amounts)
Revenues:
Service revenues	$	1,310		$	1,247		$	3,853		$	3,678		$	1,495		$	1,371		$	4,424		$	4,062
Service revenues – commodity consideration													38			121			158			316
Product sales	581			658			1,950			1,623			466			811			1,512			2,104
Total revenues	1,891			1,905			5,803			5,301			1,999			2,303			6,094			6,482
Costs and expenses:
Product costs	504			461			1,620			1,180			434			790			1,442			2,039
Processing commodity expenses													19			30			83			91
Operating and maintenance expenses	400			394			1,157			1,179			364			389			1,091			1,134
Depreciation and amortization expenses	433			435			1,308			1,326			435			425			1,275			1,290
Selling, general, and administrative expenses	138			177			452			556			130			174			410			436
Gain on sale of Geismar Interest (Note 3)	(1,095		)	—			(1,095		)	—
Impairment of certain assets (Note 11)	1,210			1			1,236			811
Impairment of certain assets (Note 13)													—			—			76			66
Other (income) expense – net	24			92			34			130			(11		)	(6		)	30			24
Total costs and expenses	1,614			1,560			4,712			5,182			1,371			1,802			4,407			5,080
Operating income (loss)	277			345			1,091			119			628			501			1,687			1,402
Equity earnings (losses)	115			104			347			302			93			105			260			279
Impairment of equity-method investments (Note 11)	—			—			—			(112		)
Other investing income (loss) – net (Note 4)	4			28			278			64
Other investing income (loss) – net (Note 5)													(107		)	2			(54		)	74
Interest incurred	(275		)	(304		)	(842		)	(916		)	(303		)	(286		)	(915		)	(856		)
Interest capitalized	8			7			24			30			7			16			27			38
Other income (expense) – net	20			20			115			52			1			52			19			99
Income (loss) before income taxes	149			200			1,013			(461		)	319			390			1,024			1,036
Provision (benefit) for income taxes	24			69			126			(74		)	77			190			244			297
Net income (loss)	125			131			887			(387		)	242			200			780			739
Less: Net income (loss) attributable to noncontrolling interests	92			70			400			22			21			71			54			323
Net income (loss) attributable to The Williams Companies, Inc.	$	33		$	61		$	487		$	(409	)	221			129			726			416
Amounts attributable to The Williams Companies, Inc.:
Preferred stock dividends													1			—			2			—
Net income (loss) available to common stockholders													$	220		$	129		$	724		$	416
Basic earnings (loss) per common share:
Net income (loss)	$	.04		$	.08		$	.59		$	(.55	)	$	.18		$	.13		$	.60		$	.47
Weighted-average shares (thousands)	826,779			750,754			825,925			750,579			1,212,270			1,023,587			1,211,938			893,706
Diluted earnings (loss) per common share:
Net income (loss)	$	.04		$	.08		$	.59		$	(.55	)	$	.18		$	.13		$	.60		$	.46
Weighted-average shares (thousands)	829,368			751,858			828,150			750,579			1,214,165			1,026,504			1,213,943			896,322
Cash dividends declared per common share	$	.30		$	.20		$	.90		$	1.48

See accompanying notes.

The Williams Companies, Inc.

Consolidated Statement of Comprehensive Income ~~(Loss)~~

(Unaudited)


	Three Months Ended September 30,						Nine Months Ended September 30,						Three Months Ended September 30,						Nine Months Ended September 30,
	2017			2016			2017			2016			2019			2018			2019			2018
	(Millions)												(Millions)
Net income (loss)	$	125		$	131		$	887		$	(387	)	$	242		$	200		$	780		$	739
Other comprehensive income (loss):
Cash flow hedging activities:
Net unrealized gain (loss) from derivative instruments, net of taxes of $2 and $1 in 2017	(9		)	2			(5		)	2
Reclassifications into earnings of net derivative instruments (gain) loss, net of taxes of $1 and $1 in 2017	2			—			—			—
Foreign currency translation activities:
Foreign currency translation adjustments, net of taxes of ($25) and ($37) in 2016	—			(49		)	—			50
Reclassification into earnings upon sale of foreign entities, net of taxes of ($36) in 2016.	—			119			—			119
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, net of taxes of $1 and $2 in 2017 and $0 and $1 in 2016	—			(1		)	(2		)	(3		)
Net actuarial gain (loss) arising during the year, net of taxes of $2 in 2016	—			—			—			(3		)
Amortization of actuarial (gain) loss included in net periodic benefit cost, net of taxes of ($2) and ($7) in 2017 and ($3) and ($9) in 2016	4			5			13			15
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)	(3		)	76			6			180			(1		)	6			4			9
Comprehensive income (loss)	122			207			893			(207		)	241			206			784			748
Less: Comprehensive income (loss) attributable to noncontrolling interests	89			108			398			91			21			72			54			321
Comprehensive income (loss) attributable to The Williams Companies, Inc.	$	33		$	99		$	495		$	(298	)	$	220		$	134		$	730		$	427

See accompanying notes.

The Williams Companies, Inc.

Consolidated Balance Sheet

(Unaudited)


	September 30, 2017			December 31, 2016			September 30, 2019			December 31, 2018
	(Millions, except per-share amounts)						(Millions, except per-share amounts)
ASSETS
Current assets:
Cash and cash equivalents	$	1,172		$	170		$	247		$	168
Trade accounts and other receivables (net of allowance of $6 at September 30, 2017 and $6 at December 31, 2016)	783			938
Trade accounts and other receivables (net of allowance of $6 at September 30, 2019 and $9 at December 31, 2018)							875			992
Inventories	144			138			129			130
Other current assets and deferred charges	194			216			183			174
Total current assets	2,293			1,462			1,434			1,464
Investments	6,615			6,701			6,228			7,821
Property, plant, and equipment	38,712			38,912			41,647			38,661
Accumulated depreciation and amortization	(11,003		)	(10,484		)	(12,034		)	(11,157		)
Property, plant, and equipment – net	27,709			28,428			29,613			27,504
Intangible assets – net of accumulated amortization	8,873			9,663			8,041			7,767
Regulatory assets, deferred charges, and other	630			581			965			746
Total assets	$	46,120		$	46,835		$	46,281		$	45,302
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable	$	773		$	623		$	602		$	662
Accrued liabilities	1,079			1,448			1,184			1,102
Commercial paper	—			93
Long-term debt due within one year	502			785			1,538			47
Total current liabilities	2,354			2,949			3,324			1,811
Long-term debt	20,567			22,624			20,719			22,367
Deferred income tax liabilities	5,211			4,238			1,651			1,524
Regulatory liabilities, deferred income, and other	3,106			2,978			3,728			3,603
Contingent liabilities (Note 12)
Contingent liabilities (Note 14)
Equity:
Stockholders’ equity:
Common stock (960 million shares authorized at $1 par value; 861 million shares issued at September 30, 2017 and 785 million shares issued at December 31, 2016)	861			785
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	18,492			14,887			24,310			24,693
Retained deficit	(9,872		)	(9,649		)	(10,664		)	(10,002		)
Accumulated other comprehensive income (loss)	(331		)	(339		)	(266		)	(270		)
Treasury stock, at cost (35 million shares of common stock)	(1,041		)	(1,041		)	(1,041		)	(1,041		)
Total stockholders’ equity	8,109			4,643			13,621			14,660
Noncontrolling interests in consolidated subsidiaries	6,773			9,403			3,238			1,337
Total equity	14,882			14,046			16,859			15,997
Total liabilities and equity	$	46,120		$	46,835		$	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 – 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


	The Williams Companies, Inc., Stockholders
	Common Stock		Capital in Excess of Par Value		Retained Deficit			Accumulated Other Comprehensive Income (Loss)			Treasury Stock			Total Stockholders’ Equity			Noncontrolling Interests			Total Equity
	(Millions)
Balance – December 31, 2016	$	785	$	14,887	$	(9,649	)	$	(339	)	$	(1,041	)	$	4,643		$	9,403		$	14,046
Balance – June 30, 2018																							$	—	$	862	$	18,552		$	(8,735	)	$	(293	)	$	(1,041	)	$	9,345		$	6,102		$	15,447
Net income (loss)	—		—		487			—			—			487			400			887			—		—		—			129			—			—			129			71			200
Other comprehensive income (loss)	—		—		—			8			—			8			(2		)	6			—		—		—			—			5			—			5			1			6
Issuance of common stock (Note 10)	75		2,043		—			—			—			2,118			—			2,118
Cash dividends – common stock	—		—		(744		)	—			—			(744		)	—			(744		)
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	—		—		—			—			—			—			(679		)	(679		)	—		—		—			—			—			—			—			(196		)	(196		)
Stock-based compensation and related common stock issuances, net of tax	1		59		—			—			—			60			—			60			—		—		16			—			—			—			16			—			16
Adoption of ASU 2016-09 (Note 1)	—		1		36			—			—			37			—			37
Sales of limited partner units of Williams Partners L.P.	—		—		—			—			—			—			43			43
Changes in ownership of consolidated subsidiaries, net	—		1,497		—			—			—			1,497			(2,404		)	(907		)	—		—		1			—			—			—			1			(1		)	—
Contributions from noncontrolling interests	—		—		—			—			—			—			15			15			—		—		—			—			—			—			—			2			2
Other	—		5		(2		)	—			—			3			(3		)	—			—		1		(1		)	(1		)	—			—			(1		)	(1		)	(2		)
Net increase (decrease) in equity	76		3,605		(223		)	8			—			3,466			(2,630		)	836			35		383		6,128			(283		)	2			—			6,265			(4,753		)	1,512
Balance – September 30, 2017	$	861	$	18,492	$	(9,872	)	$	(331	)	$	(1,041	)	$	8,109		$	6,773		$	14,882
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)



	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

See accompanying notes.

The Williams Companies, Inc.

Consolidated Statement of Cash Flows

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, ~~2016,~~2018, in ~~Exhibit 99.1 of~~ our Annual Report on Form ~~8-K dated May 25, 2017.~~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.

~~Financial Repositioning~~WPZ Merger

~~In January 2017,~~On August 10, 2018, we ~~announced agreements~~completed our merger with Williams Partners L.P. (WPZ), ~~wherein~~our previously consolidated master limited partnership, pursuant to which we ~~permanently waived~~acquired all of the ~~general partner’s incentive distribution rights (IDRs) and converted our 2 percent general partner interest in WPZ to a noneconomic interest in exchange for 289~~approximately 256 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~~publicly held outstanding common units of WPZ atin 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 ~~price~~noncash equity transaction resulting in increases to Common stock of ~~$36.08586 per unit~~$382 million, Capital in ~~a private placement transaction, funded with proceeds from our equity offering (see Note 10 – Stockholders’ Equity)~~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. ~~According~~Pursuant to its distribution reinvestment program, WPZ had issued 1,230,657 common units to the ~~terms~~public in 2018 associated with reinvested distributions of this agreement, concurrent with WPZ’s quarterly distributions in February 2017 and May 2017, we paid additional consideration totaling $56 million to WPZ for these units. Subsequent to these transactions and as of September 30, 2017, we own a 74 percent limited partner interest in WPZ.$46 million.

Description of Business

We are a Delaware corporation whose common stock is listed and traded on the New York Stock Exchange. Our operations are located ~~principally~~ in the United ~~States. We have one~~States and are presented within the following reportable ~~segment, Williams Partners.~~segments: Northeast G&P, Atlantic-Gulf, and West, consistent with the manner in which our chief operating decision maker evaluates performance and allocates resources. All remaining business activities as well as corporate activities are included in Other.

~~Williams Partners~~

~~Williams Partners consists~~Northeast G&P is comprised of our ~~consolidated master limited partnership, WPZ,~~midstream gathering, processing, and fractionation businesses in the Marcellus Shale region primarily ~~includes gas pipeline~~in Pennsylvania, New York, and ~~midstream businesses.~~

~~WPZ’s gas pipeline businesses primarily consist~~West Virginia and the Utica Shale region of two interstate natural gas pipelines, which are Transcontinental Gas Pipe Line Company, LLC (Transco) and Northwest Pipeline LLC (Northwest Pipeline), and several joint venture investments in interstate and intrastate natural gas pipeline systems,eastern Ohio, including a 5066 percent ~~equity-method investment in Gulfstream Natural Gas System, L.L.C. (Gulfstream), and a~~ ~~41 percent~~ interest in ~~Constitution Pipeline Company, LLC (Constitution)~~Cardinal Gas Services, L.L.C. (Cardinal) (a consolidated entity), ~~which is under development.~~

~~Notes (Continued)~~

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

The midstream businesses include equity-method investments in natural gas gathering and processing assets and NGL fractionation and transportation assets, including a 62 percent equity-method investment in Utica East Ohio Midstream, LLC (UEOM), a 69 percent equity-method investment in Laurel Mountain Midstream, LLC (Laurel Mountain), a 58 percent equity-method investment in Caiman Energy II, LLC, ~~(Caiman II), a 60 percent equity-method investment in Discovery Producer Services LLC (Discovery), a 50 percent equity-method investment in Overland Pass Pipeline, LLC (OPPL),~~ and Appalachia Midstream Services, LLC, which owns equity-method investments with an approximate average 66 percent interest in multiple 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, as well as ~~our previously owned~~a 50 percent equity-method investment in ~~the Delaware basin gas gathering system (DBJV)~~Gulfstream Natural Gas System, L.L.C., a 60 percent equity-method investment in ~~the Mid-Continent region~~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 4 – ~~Investing Activities)~~Variable Interest Entities).

~~The midstream businesses~~West is comprised of our interstate natural gas pipeline, Northwest Pipeline LLC (Northwest Pipeline), and our gathering, processing, and treating operations in Colorado, Wyoming, 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 and 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, 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 ~~Canadian midstream operations,~~former natural gas gathering and processing assets in the Four Corners area of New Mexico and Colorado, which were ~~comprised~~sold during the fourth quarter of ~~an oil sands offgas processing plant near Fort McMurray, Alberta,~~2018, and ~~an NGL/olefin fractionation facility at Redwater, Alberta. In September 2016, we completed the sale~~our former 50 percent interest in Jackalope Gas Gathering Services, L.L.C. (Jackalope) (an equity-method investment following deconsolidation as of ~~our Canadian operations.~~

~~Other~~

Our former Williams NGL & Petchem Services segment included certain domestic olefins pipeline assets as well as certain Canadian assets, which included a liquids extraction plant located near Fort McMurray, Alberta, that began operations in March 2016, and a propane dehydrogenation facilityJune 30, 2018), which was under development. In September 2016, the Canadian assets were sold. Considering this, the remaining assets are now reported within Other, effective January 1, 2017. Other also includes business activities that are not operating segments, as well as corporate operations. Prior period segment disclosures have been recast for this segment change.sold in April 2019.

Basis of Presentation

~~Consolidated master limited partnership~~

As of September 30, 2017, we own 74 percent of the interests in WPZ, a variable interest entity (VIE) (see Note 2 – Variable Interest Entities). WPZ units issued to us in connection with the Financial Repositioning, WPZ’s quarterly distribution of additional paid-in-kind Class B units to us, and other equity issuances by WPZ had the combined net impact of decreasing ~~Noncontrolling interests in consolidated subsidiaries~~ ~~by $2.404 billion, and increasing~~ ~~Capital in excess of par value~~ ~~by $1.497 billion and~~ ~~Deferred income tax liabilities~~ ~~by $907 million in the Consolidated Balance Sheet.~~

WPZ is self-funding and maintains separate lines of bank credit and cash management accounts and also has a commercial paper program. (See Note 9 – Debt and Banking Arrangements.) Cash distributions from WPZ to us, including any associated with our previous IDRs, occur through the normal partnership distributions from WPZ to all partners.

~~Notes (Continued)~~

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, notably certain acquired assets accounted for as business combinations between 2012 and 2014, may be in excess of current fair value. However, the carrying value of these assets, in our judgment, continues to be recoverable based on our evaluation of undiscounted future cash flows. It is reasonably possible that future strategic decisions, including transactions such as monetizing non-core assets or contributing assets to new ventures with third parties, as well as unfavorable changes in expected producer activities could impact our assumptions and ultimately result in impairments of these assets. Such ~~impairments~~transactions or developments may also indicate that certain of our equity-method investments have experienced other-than-temporary declines in value, which could ~~potentially be caused by indications of~~result in impairment, or that the fair value ~~implied through the monetization process or, in the case of asset dispositions that are part of a broader asset group, the impact~~ of the ~~loss of future estimated cash flows.~~reporting unit for our goodwill is less than its carrying amount, which would result in impairment.

Accounting standards issued and adopted

Effective January 1, 2017, we adopted Accounting Standards Update (ASU) 2016-09, “Compensation - Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting” (ASU 2016-09). ASU 2016-09 changed the accounting for income taxes such that all excess tax benefits and all tax deficiencies are now recognized as a discrete item in the provision for income taxes in the financial reporting period they occur and the recognition of tax benefits is no longer delayed until the tax benefit is realized through a reduction in income taxes payable. These changes are applied prospectively beginning in 2017. We recorded a cumulative-effect adjustment as of January 1, 2017, decreasing ~~Retained deficit~~ by $37 million in the Consolidated Balance Sheet to recognize tax benefits that were not previously recognized. ASU 2016-09 requires entities to classify excess tax benefits as an operating activity on the statement of cash flows. We are applying this part of the guidance prospectively beginning in 2017; therefore, the cash flows for prior periods were not adjusted. In recognizing compensation cost from share-based payments, ASU 2016-09 allows entities to make an accounting policy election to either recognize forfeitures when they occur or estimate the number of forfeitures expected to occur. We are recognizing forfeitures when they occur and as a result of the change in our accounting policy, we increased our ~~Retained deficit~~ for an insignificant cumulative-effect adjustment as of January 1, 2017. ASU 2016-09 requires entities to classify as a financing activity, on the statement of cash flows, cash paid by an employer to a taxing authority when directly withholding shares from an employee’s award to satisfy the employer’s statutory tax withholding obligation. This guidance must be applied retrospectively and we have adjusted operating and financing activities on the Consolidated Statement of Cash Flows for prior periods.

~~Accounting standards issued but not yet adopted~~

~~In August 2017,~~February 2016, the Financial Accounting Standards Board (FASB) issued ~~ASU 2017-12 “Derivatives and Hedging~~Accounting Standards Update (ASU) 2016-02 “Leases (Topic ~~815): Targeted Improvements to Accounting for Hedging Activities”~~842)” (ASU ~~2017-12)~~2016-02). ASU ~~2017-12 applies~~2016-02 establishes a comprehensive new lease accounting model. ASU 2016-02 modifies the definition of a lease, requires a dual approach to ~~entities~~lease classification similar to 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 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 ~~elect hedge accounting~~exist or expired before the effective date of ASU 2016-02 and that were not previously assessed under the previous lease guidance in ~~accordance with~~ Accounting Standards Codification (ASC) ~~815. The~~Topic 840 “Leases.”

In July 2018, the FASB issued ASU ~~affects both~~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 ~~designation and measurement guidance~~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 ~~hedging relationships and~~periods prior to adoption. ASU 2018-11 also allows a

Notes (Continued)

practical expedient that permits lessors to not separate nonlease components from the ~~presentation of hedging results.~~associated lease component if certain conditions are present. ASU ~~2017-12~~2016-02 is effective for interim and annual periods beginning after December 15, 2018. ~~Early~~We prospectively adopted ASU 2016-02 effective January 1, 2019, and did not adjust prior periods as permitted by ASU 2018-11 (see Note 10 – Leases).

We completed our review of contracts to identify leases based on the modified definition of a lease and implemented changes to our internal controls to support management in the accounting for and disclosure of leasing activities upon adoption ~~is permitted.~~of ASU ~~2017-12 will be applied using~~2016-02. We implemented a ~~modified retrospective approach~~financial lease accounting system to assist management in the accounting for ~~cash flow~~leases upon adoption. 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 ~~net investment hedges existing at the date of~~offsetting right-of-use asset in our Consolidated Balance Sheetfor operating leases. We also evaluated ASU 2016-02’s available practical expedients on adoption and ~~prospectively for~~have generally elected to adopt the ~~presentation~~practical expedients, which includes the practical expedient to not separate lease and ~~disclosure guidance. We do not expect ASU 2017-12 to have a material impact on our consolidated financial statements.~~

~~In March 2017, the FASB issued ASU 2017-07 “Compensation - Retirement Benefits (Topic 715): Improving the Presentation~~nonlease components by both lessees and lessors by class 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 a subtotal of income from operations, if one is presented. Only the service cost component is now eligible for capitalization when applicable. ASU 2017-07 is effective beginning January 1, 2018. The presentation aspect of ASU 2017-07 must be applied retrospectivelyunderlying assets and the capitalization requirement prospectively. In light of the settlement charge we expect to recognize in the fourth quarter of 2017 related to a program to payout certain deferred vested pension benefits (see Note 8 – Employee Benefit Plans), we continue to evaluate the impact of ASU 2017-07 on our consolidated financial statements.land easements practical expedient.

~~In January 2017, the FASB~~Accounting standards issued ASU 2017-04 “Intangibles - Goodwill and Other (Topic 350): Simplifying the Test for Goodwill Impairment” (ASU 2017-04). ASU 2017-04 modifies the concept of goodwill impairment to represent the amount by which a reporting unit’s carrying value exceeds its fair value,but not to exceed the carrying amount of goodwill. Under ASU 2017-04, entities will no longer be required to determine the implied fair value of goodwill by assigning the fair value of a reporting unit to its individual assets and liabilities as if that reporting unit had been acquired in a business combination. ASU 2017-04 is effective for goodwill impairment testing for interim and annual periods

~~Notes (Continued)~~

beginning after December 15, 2019, and requires a prospective transition. Early adoption is permitted for interim and annual goodwill impairment tests performed after January 1, 2017, and we plan to adopt ASU 2017-04 in the fourth quarter of 2017. Our Williams Partners reportable segment has $47 million of goodwill included in ~~Intangible assets - net of accumulated amortization~~ ~~in theConsolidated Balance Sheet.~~

In August 2016, the FASB issued ASU 2016-15 “Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments” (ASU 2016-15). ASU 2016-15 provides specific guidance on eight cash flow classification issues, including debt prepayment or debt extinguishment costs and distributions received from equity method investees, to reduce diversity in practice. ASU 2016-15 is effective for interim and annual periods beginning after December 15, 2017. Early adoption is permitted. ASU 2016-15 requires a retrospective transition. We do not expect ASU 2016-15 to have a material impact on our consolidated financial statements.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. ~~Early adoption is permitted.~~We plan to adopt as of January 1, 2020. We anticipate that ASU 2016-13 ~~requires varying transition methods for the different categories of amendments. Although~~will primarily apply to our trade receivables. While we do not expect ~~ASU 2016-13 to have~~ a significant financial impact, ~~it will impact~~we have analyzed our ~~trade receivables~~historical credit loss experience and continue to 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 ~~related allowance for credit losses will be recognized earlier under the expected loss model.~~

In February 2016, the FASB issued ASU 2016-02 “Leases (Topic 842)” (ASU 2016-02). ASU 2016-02 establishes a comprehensive new lease accounting model. ASU 2016-02 clarifies the definition of a lease, requires a dual approach to lease classification similar to current lease classifications, and causes lessees to recognize leases on the balance sheet as a lease liability with a corresponding right-of-use asset. ASU 2016-02 is effective for interim and annual periods beginning after December 15, 2018. Early adoption is permitted. ASU 2016-02 requires a modified retrospective transition for capital or operating leases existing at or entered into after the beginningacquisition of the ~~earliest comparative period presented~~remaining 38 percent interest in ~~the financial statements. We are~~UEOM. Total consideration paid, including post-closing adjustments, was $741 million in ~~the process of reviewing contracts to identify leases, as well as evaluating the applicability of ASU 2016-02 to contracts involving easements/rights-of-way.~~

In May 2014, the 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 servicescash funded through credit facility borrowings and requires significantly enhanced revenue disclosures. In August 2015, the FASB issued ASU 2015-14 “Revenue from Contracts with Customers (Topic 606): Deferral of the Effective Date” (ASU 2015-14). Per ASU 2015-14, the standard is effective for interim and annual reporting periods beginning after December 15, 2017. ASC 606 allows either full retrospective or modified retrospective transition and early adoption is permitted for annual periods beginning after December 15, 2016.

~~We continue to evaluate the impact ASC 606 may have~~cash on ~~our financial statements. For each revenue contract type, we conducted a formal contract review process to evaluate the impact, if any, that ASC 606 may have.~~hand. As a result of ~~that process,~~acquiring this additional interest, we ~~expect our revenues will increase associated with accounting for noncash consideration, which exists~~obtained control of and now consolidate UEOM.

UEOM is involved primarily in ~~certain~~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, contracts where we receive commodities as full or partial consideration for services provided. We also expect the increase in revenues will be offset by a similar increase in costs when the commodities received are subsequently monetized. We continue to evaluateand fractionation contracts with ~~a significant financing component, which may exist in situations where~~customers. Based on the ~~timing~~estimated future revenues during the current contract periods (as estimated at the time of the ~~consideration we receive varies significantly~~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 ~~timing~~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 ~~when~~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 ~~provide the service,~~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 3 – Revenue Recognition

Revenue by Category

The following table presents our revenue disaggregated by major service line:



	Northeast Midstream		Atlantic- Gulf Midstream		West Midstream		Transco		Northwest Pipeline		Other		Intercompany Eliminations			Total
	(Millions)
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

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
Commodity consideration	5		19		97		—		—		—		—			121
Regulated interstate natural gas transportation and storage	—		—		—		457		110		—		(1		)	566
Other	23		4		11		—		—		—		(4		)	34
Total service revenues	247		162		517		457		110		1		(24		)	1,470
Product Sales:
NGL and natural gas	69		88		720		41		—		—		(117		)	801
Other	—		—		12		—		—		—		(3		)	9
Total product sales	69		88		732		41		—		—		(120		)	810
Total revenues from contracts with customers	316		250		1,249		498		110		1		(144		)	2,280
Other revenues (1)	6		5		3		3		—		9		(3		)	23
Total revenues	$	322	$	255	$	1,252	$	501	$	110	$	10	$	(147	)	$	2,303

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)

Revenues not within the scope of 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 equity-method investments, which are reported in Service revenues in our Consolidated Statement of Income, and amounts associated with our derivative contracts, which are reported in Product sales in our Consolidated Statement of Income.

Notes (Continued)

Contract Assets

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

Contract Liabilities

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

Remaining Performance Obligations

Remaining performance obligations primarily include reservation charges on contracted capacity for our gas pipeline firm transportation contracts with ~~tiered pricing structures,~~customers, storage capacity contracts, long-term contracts containing minimum volume commitments associated with our midstream businesses, and ~~prepayments~~fixed payments associated with offshore production handling. For our interstate natural gas pipeline businesses, remaining performance obligations reflect the rates for ~~services. As~~ such ~~we are unable to determine~~services in our current Federal Energy Regulatory Commission (FERC) tariffs for the ~~potential impact upon~~life of the related contracts; however, these rates may change based on future tariffs approved by the FERC and the amount and timing of ~~revenue recognition. We continue to develop and evaluate disclosures required under ASC 606, with a particular focus on the scope of contracts subject to disclosure of~~these changes are not currently known.

Our remaining performance ~~obligations. Additionally,~~obligations exclude variable consideration, including contracts with variable consideration for which we have ~~identified possible financial system~~elected the practical expedient for consideration recognized in revenue as billed. Certain of our contracts contain evergreen and ~~internal control changes necessary~~other renewal provisions for ~~adoption. We currently anticipate utilizing a modified retrospective transition upon~~periods beyond the ~~adoption~~initial term of ~~ASC 606~~the contract. The remaining performance obligation amounts as of ~~January 1, 2018.~~September 30, 2019, do not consider potential future performance obligations for which the renewal has not been exercised and excludes contracts with customers for which the underlying facilities have not received FERC authorization to be placed into service. Consideration received prior to September 30, 2019, that will be recognized in future periods is also excluded from our remaining performance obligations and is instead reflected in contract liabilities.

The following table presents the amount of the contract liabilities balance as of September 30, 2019, expected to be recognized as revenue as performance obligations are satisfied and the transaction price allocated to the remaining performance obligations under certain contracts as of September 30, 2019.

Notes (Continued)

~~Termination of WPZ Merger Agreement~~



	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

~~On May 12, 2015, we entered into an agreement for~~Accounts Receivable

The following is a ~~unit-for-stock transaction whereby we would have acquired all of the publicly held outstanding common units of WPZ in exchange for shares~~summary of our ~~common stock (WPZ Merger Agreement).~~Trade accounts and other receivables:

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



	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

Note 24 – Variable Interest Entities

~~WPZ~~Consolidated VIEs

As of September 30, 2019, we consolidate the following variable interest entities (VIEs):

Gulfstar One

We own a 74 percent interest in WPZ, a master limited partnership that is a VIE due to the limited partners’ lack of substantive voting rights, such as either participating rights or kick-out rights that can be exercised with a simple majority of the vote of the limited partners. We are the primary beneficiary of WPZ because we have the power, through our general partner interest, to direct the activities that most significantly impact WPZ’s economic performance.

~~Notes (Continued)~~

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

September 30,
2017
December 31,
2016
Classification

(Millions)

Assets (liabilities):

Cash and cash equivalents $ 1,165
$ 145

Cash and cash equivalents
Trade accounts and other receivables – net
778
925
Trade accounts and other receivables
Inventories 144
138
Inventories
Other current assets 183
205
Other current assets and deferred charges
Investments 6,615
6,701
Investments
Property, plant, and equipment – net
27,411
28,021

Property, plant, and equipment – net
Intangible assets – net
8,872
9,662
Intangible assets – net of accumulated amortization
Regulatory assets, deferred charges, and other noncurrent assets 467
467
Regulatory assets, deferred charges, and other
Accounts payable (751 ) (589 )
Accounts payable
Accrued liabilities including current asset retirement obligations (818 ) (1,122 ) Accrued liabilities
Commercial paper —
(93 ) Commercial paper
Long-term debt due within one year (502 ) (785 ) Long-term debt due within one year
Long-term debt (16,000 ) (17,685 ) Long-term debt
Deferred income tax liabilities (14 ) (20 ) Deferred income tax liabilities
Noncurrent asset retirement obligations (876 ) (798 ) Regulatory liabilities, deferred income, and other
Regulatory liabilities, deferred income, and other noncurrent liabilities (1,986 ) (1,860 )
Regulatory liabilities, deferred income, and other

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

~~Gulfstar One~~

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

Constitution

~~WPZ owns~~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. ~~WPZ is~~We are the primary beneficiary because ~~it has~~we have the power to direct the activities that most significantly impact Constitution’s economic performance. ~~WPZ,~~We, as ~~construction manager for~~operator of Constitution, isare 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 ~~$691~~$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 ~~WPZ~~us and the other equity partners on a proportional basis.

~~Notes (Continued)~~

In December 2014, Constitution received approval from the ~~Federal Energy Regulatory Commission (FERC)~~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. As to the denial itself, the court determined that NYSDEC’s action was not arbitrary or capricious.denial. Constitution filed a petition for rehearing ofwith the Second Circuit ~~Court’s decision,~~Court of Appeals, but in October 2017 the court denied our petition.

~~We remain steadfastly committed to the project, and in~~

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.

~~In light~~ By 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 ~~NYSDEC’s denial~~application.

Thereafter, we petitioned the D.C. Circuit for review of the FERC’s decision. 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 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 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 ~~actions taken to challenge~~state agency does not act within one year of the ~~decision, the anticipated target in-service date is as early as the first half of 2019, which assumes the timely~~ receipt of ~~a Notice~~the original application, the state agency has “failed or refused to ~~Proceed from~~act under Section 401” and, therefore, has waived its Section 401 authority.

The equity partners are evaluating the ~~FERC. An unfavorable resolution could result~~next steps in connection with advancing the ~~impairment of a significant portion of the~~project.

At September 30, 2019, capitalized project costs total $376 million, of which ~~total $381 million on a consolidated basis at September 30, 2017,~~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

~~WPZ owns~~We own a66 percent interest in Cardinal, ~~Gas Services, L.L.C. (Cardinal),~~ a subsidiary that provides gathering services for the Utica Shale region and is a VIE due to certain risks shared with customers. ~~WPZ is~~We are the primary beneficiary because ~~it has~~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 ~~WPZ~~us and the other equity partner on a proportional basis.

~~Jackalope~~Northeast JV

~~WPZ owns~~As a50 result of the June 2019 sale of a 35 percent interest in ~~Jackalope Gas Gathering Services, L.L.C. (Jackalope)~~the Northeast JV (see Note 2 – Acquisitions), we now own a 65 percent interest in the Northeast JV, a subsidiary that ~~provides gathering and processing services for the Powder River basin and~~ is a VIE due to certain ~~risks shared with customers. WPZ is~~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 ~~it has~~we have the power to direct the activities that most significantly impact ~~Jackalope’s~~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 ~~WPZ~~us and the other equity partner on a proportional basis.

~~Note 3 – Divestitures~~

On July 6, 2017, WPZ completed the sale of Williams Olefins, L.L.C., a wholly owned subsidiary which owned our 88.5 percent undivided interest in the Geismar, Louisiana, olefins plant (Geismar Interest) for total consideration of $2.084 billion in cash. We received a final working capital adjustment of $12 million in October 2017. Upon closing of the sale, WPZ entered into a long-term supply and transportation agreement with the purchaser to provide feedstock to the plant via its Bayou Ethane pipeline system. The assets and liabilities of the Geismar olefins plant were designated as held for sale within the Williams Partners segment during the first quarter of 2017. As a result of this sale, we recorded a gain of $1.095 billion in the third quarter of 2017. Following this sale, the cash proceeds were used to repay WPZ’s $850 million term loan. WPZ also plans to use these proceeds to fund a portion of the capital and investment expenditures that are a part of its growth portfolio.

Notes (Continued)

The following table presents ~~the results of operations~~amounts included in our Consolidated Balance Sheet that are only for the ~~Geismar Interest, excluding~~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		)

Nonconsolidated VIEs

Jackalope

At December 31, 2018, we owned a50 percent interest in Jackalope, which provides gathering and processing services for the ~~gain noted above.~~Powder River basin and was a VIE due to certain risks shared with customers. In April 2019, we sold our interest in Jackalope for $485 million in cash (see Note 5 – Investing Activities).

Brazos Permian II

Three Months Ended September 30, Nine Months Ended September 30,
2017 2016 2017 2016
(Millions)
Income (loss) before income taxes of the Geismar Interest $ 1
$ 61
$ 26
$ 109
Income (loss) before income taxes of the Geismar Interest attributable to The Williams Companies, Inc. 1
36
19
65

In September 2016, we completed the sale of subsidiaries conducting Canadian operations, including subsidiaries of WPZ, (such subsidiaries, the Canada disposal group). Consideration received totaled $1.020 billion, net of $31 million of cash divestedWe own a 15 percent interest in Brazos Permian II, which provides gathering and ~~subject to customary working capital adjustments. In connection with the sale, we waived $150 million of incentive distributions otherwise payable by WPZ to us~~processing services in the ~~fourth quarter of 2016 in recognition of certain affiliate contracts wherein WPZ’s Canadian operations provided services~~Delaware basin and is a VIE due primarily to ~~certain~~our limited participating rights as the minority equity holder. At September 30, 2019, the carrying value of our ~~other businesses. The proceeds were primarily used~~equity-method investment in Brazos Permian II was $197 million. Our maximum exposure to ~~reduce borrowings on credit facilities.~~

~~During~~loss is limited to the ~~second quarter of 2016, we designated these operations as held for sale. As a result, we measured the fair~~carrying value of ~~the disposal group as of June 30, 2016, resulting in an impairment charge of $747 million, reflected in~~ ~~Impairment of certain assets~~ ~~in the~~ ~~Consolidated Statement of Operations~~. (See Note 11 - Fair Value Measurements.) Upon completion of the sale, we recorded an additional loss of $65 million for the three and nine months ended September 30, 2016, primarily reflecting revisions to the sales price and estimated contingent consideration and including a $15 million benefit related to transactions to hedge our ~~foreign currency exchange risk on the Canadian proceeds, reflected in~~ ~~Other (income) expense – net~~ ~~within~~ ~~Costs and expenses~~ ~~in the~~ ~~Consolidated Statement of Operations. The total loss consists of a loss of $32 million and $33 million at Williams Partners and Williams Other segments, respectively.~~

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

Three Months Ended September 30, Nine Months Ended September 30,
2017 2016 2017 2016
(Millions)
Income (loss) before income taxes of the Canadian disposal group $ —
$ (9 ) $ —
$ (98 )
Income (loss) before income taxes of the Canadian disposal group attributable to The Williams Companies, Inc. —
(16 ) —
(95 )
investment.

Note 45 – Investing Activities

~~Acquisition of Additional Interests in Appalachia Midstream Investments~~

During the first quarter of 2017, WPZ exchanged all of its 50 percent interest in DBJV for an increased interest in two natural gas gathering systems that are part of the Appalachia Midstream Investments and $155 million in cash. This transaction was recorded based on our estimate of the fair value of the interests received as we have more insight to this value as we operate the underlying assets. Following this exchange, we have an approximate average 66 percent interest in the Appalachia Midstream Investments. We continue to account for this investment under the equity-method due to the significant participatory rights of our partners such that we do not exercise control. WPZ also sold all of its interest in Ranch Westex JV LLC for $45 million. These transactions resulted in a total gain of $269 millionThe following table presents certain items reflected in Other investing income (loss) – netin the Consolidated Statement of ~~Operations.~~Income:

~~The~~



	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. We recorded our interest in Jackalope as an equity-method investment at its estimated fair value, resulting in a deconsolidation gain of

Notes (Continued)

$62 million. We estimated the fair value of ~~the increased interests in the Appalachia Midstream Investments received as consideration was estimated~~our interest to be ~~$1.1 billion~~$310 million using an income approach based on expected future cash flows and an appropriate discount rate

~~Notes (Continued)~~

(a (a Level 3 measurement within the fair value hierarchy). The determination of ~~estimated~~expected future cash flows involved significant assumptions regarding gathering and processing volumes ~~rates,~~ and related capital spending. A ~~9.5~~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.

~~Impairments~~

The ~~nine months ended September 30, 2016, includes $59 million and $50~~deconsolidated carrying value of the net assets of Jackalope included $47 million of ~~other-than-temporary impairment charges related to WPZ’s~~goodwill.

Sale of Jackalope

In April 2019, we sold our 50 percent equity-method ~~investments in DBJV and Laurel Mountain, respectively (see Note 11 – Fair Value Measurements and Guarantees).~~

~~Investing Income~~

~~The three and nine months ended September 30, 2016, includes a $27 million gain from the sale of an equity-method investment~~ interest in Jackalope for $485 million in cash, resulting in a ~~gathering system that was part~~gain on the disposition of ~~WPZ’s Appalachia Midstream Investments.~~

~~Interest Income and Other~~

~~The nine months ended September 30, 2016, includes $36 million of income associated with payments received on a receivable related to the sale of certain former Venezuela assets reflected in~~ ~~Other investing income (loss) – net~~ ~~in theConsolidated Statement of Operations~~.$122 million.

Notes (Continued)

Note 56 – 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 ~~Operations~~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,
2017 2016 2017 2016
(Millions)
Williams Partners
Amortization of regulatory assets associated with asset retirement obligations $ 8
$ 8
$ 25
$ 25
Accrual of regulatory liability related to overcollection of certain employee expenses 5
6
16
19
Project development costs related to Constitution (see Note 2) 4
11
12
19
Gains on contract settlements and terminations —
—
(15 ) —
Gain on sale of Refinery Grade Propylene Splitter —
—
(12 ) —
Net foreign currency exchange (gains) losses (1) —
—
—
11
Loss on sale of Canadian operations (see Note 3) 4
32
—
32
Other
Gain on sale of unused pipe —
—
—
(10 )
Loss on sale of Canadian operations (see Note 3) —
33
1
33


~~(1)~~	~~Primarily relates to gains and losses incurred on foreign currency transactions and the remeasurement of U.S. dollar denominated current assets and liabilities within our former Canadian operations.~~

~~Notes (Continued)~~

~~Additional Items~~

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

~~Service revenues~~ ~~were reduced by $15 million for the nine months ended September 30, 2016, related to potential refunds associated~~In conjunction with a ~~ruling received~~previously announced organizational realignment and considering asset sales in recent years, we are evaluating our cost structure and have implemented a voluntary separation program (VSP) for certain ~~rate case litigation within the Williams Partners segment.~~

~~Selling, general,~~eligible employees. Operating and ~~administrative~~maintenance expenses ~~includes $5 million and $9 million~~ for the three and nine months ended September 30, ~~2017,~~2019, reflect charges of $7 million and $30 million, respectively, and ~~$21~~Selling, general, and administrative expenses for the three and

Notes (Continued)

nine months ended September 30, 2019, reflect charges of $3 million and ~~$40~~$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, ~~2016, respectively,~~2019, are greater than the federal statutory rate, primarily due to the effect of ~~costs associated with our evaluation of strategic alternatives within~~state income taxes.

The effective income tax rates for the ~~Other segment.~~ ~~Selling, general, and administrative expenses~~ ~~also includes $16 million and $61 million~~total provision for the three and nine months ended September 30, 2016, respectively, of project development costs related to a proposed propane dehydrogenation facility in Alberta, Canada within the Other segment. Beginning in the first quarter of 2016, these costs did not qualify for capitalization.

~~Selling, general, and administrative expenses~~ ~~and~~ ~~Operating and maintenance expenses~~ include $5 million and $18 million in severance and other related costs for the three and nine months ended September 30, 2017 for the Williams Partners segment. The nine months ended September 30, 2016 included $26 million in severance and other related costs associated with an approximate 10 percent reduction in workforce in the first quarter of 2016, primarily within the Williams Partners segment.

~~Other income (expense) – net~~ ~~below~~ ~~Operating income (loss)~~ includes $17 million and $55 million for the three and nine months ended September 30, 2017, respectively, and $17 million and $46 million for the three and nine months ended September 30, 2016, respectively, for allowance for equity funds used during construction primarily within the Williams Partners segment. ~~Other income (expense) – net~~ ~~below~~ ~~Operating income (loss)~~ also includes $8 million and $44 million, for the three and nine months ended September 30, 2017, respectively, and $6 million and $16 million for the three and nine months ended September 30, 2016, respectively, of income associated with a regulatory asset related to deferred taxes on equity funds used during construction.

~~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 within the Williams Partners segment reflects $51 million of unamortized premium, offset by $54 million in premiums paid. (See Note 9 – Debt and Banking Arrangements.)

~~Other income (expense) – net~~ ~~below~~ ~~Operating income (loss)~~ for the nine months ended September 30, 2017, includes a net gain of $27 million associated with the early retirement of debt. The gain is comprised of a $30 million net gain associated with the February 23, 2017 early retirement of $750 million of 6.125 percent senior unsecured notes that were due in 2022, partially offset by a $3 million net loss associated with the July 3, 2017 early retirement discussed above. The net gain for the February 23, 2017 early retirement within Williams Partners reflects $53 million of unamortized premium, partially offset by $23 million in premiums paid. (See Note 9 – Debt and Banking Arrangements.)

~~Notes (Continued)~~

~~Note 6 – Provision (Benefit) for Income Taxes~~

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

Three Months Ended
September 30, Nine Months Ended
September 30,
2017 2016 2017 2016
(Millions)
Current:
Federal $ 7
$ —
$ 10
$ —
State 9
1
17
1
Foreign —
—
—
(1 )
16
1
27
—
Deferred:
Federal (11 ) 8
63
(49 )
State 19
71
36
60
Foreign —
(11 ) —
(85 )
8
68
99
(74 )
Provision (benefit) for income taxes $ 24
$ 69
$ 126
$ (74 )

~~The effective income tax rate for the three months ended September 30, 2017, is less~~2018, are higher than the federal statutory ~~rate.~~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 ~~primarily due to~~partially offset by the impact of the allocation of income to nontaxable noncontrolling ~~interests, partially offset by the effect of~~interests. The state income ~~taxes, including an $18~~tax provisions include a $38 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~~ partially offset by a net decrease in valuation allowances of $31 million on state net operating losses, both primarily ~~due to~~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 ~~of income to nontaxable noncontrolling interests and releasing a $127 million~~for state tax purposes.

A valuation allowance ~~on a~~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 ~~associated with a capital loss carryover, partially offset by the effect~~will not be realized. To assess that likelihood, we use estimates and judgment regarding our sources of ~~state~~future taxable income, ~~taxes,~~ including ~~an $18 million provision related~~available tax planning strategies, to ~~an increase in the deferred state income tax rate (net of federal benefit). In 2016, we recorded~~determine whether a valuation allowance ~~on a~~is required. The completion of the WPZ Merger decreased our deferred income tax liability by $1.829 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 asset associated with a capital loss that was incurred with the sale of our Canadian operations. The sale of the Geismar olefins facility in July 2017 (see Note 3 – Divestitures) generated capital gains sufficient to offset the capital loss carryover, thereby allowing us to reverse the valuation allowance in full.assets.

The effective income tax rate for the three months ended September 30, 2016, is less than the federal statutory rate primarily due to the impact of the allocation of income to nontaxable noncontrolling interests and the effects of taxes on foreign operations, partially offset by the effect of state income taxes, including a $43 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, 2016, is less than the federal statutory rate primarily due to the effects of taxes on foreign operations, which includes the reversal of anticipatory foreign tax credits and a valuation allowance associated with impairments and losses on the sale of our Canadian operations (see Note 3 – Divestitures), and the effect of state income taxes, including a $43 million provision related to an increase in the deferred state income tax rate (net of federal benefit). These decreases are partially offset by the impact of the allocation of income to nontaxable noncontrolling interests. The foreign income tax provision includes the tax effect of the impairments associated with our Canadian disposition. (See Note 11 – Fair Value Measurements and Guarantees.)

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 78 – 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,
2017 2016 2017 2016

(Dollars in millions, except per-share
amounts; shares in thousands)
Net income (loss) attributable to The Williams Companies, Inc. available to common stockholders for basic and diluted earnings (loss) per common share $ 33
$ 61
$ 487
$ (409 )
Basic weighted-average shares 826,779
750,754
825,925
750,579
Effect of dilutive securities:
Nonvested restricted stock units 1,889
568
1,567
—
Stock options 700
536
658
—
Diluted weighted-average shares 829,368
751,858
828,150
750,579
Earnings (loss) per common share:
Basic $ .04
$ .08
$ .59
$ (.55 )
Diluted $ .04
$ .08
$ .59
$ (.55 )

Note 89 – 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,

2017
2016
2017
2016

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

Service cost $ 13

$ 13

$ 38

$ 40
Interest cost 15

16

44

47
Expected return on plan assets (21 )
(22 )
(62 )
(64 )
Amortization of net actuarial loss 6

8

20

23
Net actuarial loss from settlements —

—

—

1
Net periodic benefit cost (credit) $ 13

$ 15

$ 40

$ 47



	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,
2017 2016 2017 2016
(Millions)
Components of net periodic benefit cost (credit):
Service cost $ —
$ —
$ 1
$ 1
Interest cost 2
2
6
6
Expected return on plan assets (3 ) (3 ) (9 ) (9 )
Amortization of prior service credit (3 ) (3 ) (10 ) (11 )
Reclassification to regulatory liability 1
1
3
3
Net periodic benefit cost (credit) $ (3 ) $ (3 ) $ (9 ) $ (10 )
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 ~~and~~ ~~net actuarial loss~~ included in ~~net~~Net periodic benefitcost (credit) for our other postretirement benefit plans associated with Transco and Northwest Pipeline ~~are~~is recorded to regulatory assets/liabilities instead of ~~other~~Other comprehensive income (loss). The ~~amounts~~amount of ~~amortization~~Amortization of prior service credit recognized in regulatory liabilities ~~were $2 million for the three months ended September 30, 2017 and 2016, and $6 million and $7~~ was $1 million for the nine months ended September 30, ~~2017 and 2016, respectively.~~2018.

During the nine months ended September 30, ~~2017~~2019, we contributed ~~$83~~$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 $1 million to our other postretirement benefit plans in the remainder of ~~2017.~~2019.

~~In September 2017, we initiated~~Note 10 – Leases

We are a ~~program to pay out certain deferred vested pension benefits to reduce investment risk, cash funding volatility,~~lessee through noncancellable lease agreements for property and equipment consisting primarily of buildings, land, vehicles, and equipment used in both our operations and administrative ~~costs. Eligible participants had until October 31, 2017,~~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 ~~make elections. We expect to make the lump-sum payments~~combine lease and ~~commence the annuity payments in December 2017, and intend to fund the payments from existing~~nonlease components for all classes of leased assets in our ~~pension plans. As~~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 ~~result~~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 ~~payouts~~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 ~~current assumptions,~~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 ~~expect~~may sublease certain unused office space for fixed periods that could extend up to ~~record a pre-tax, non-cash settlement charge in~~ the ~~fourth quarter~~length of ~~2017~~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 ~~estimate will be between $70 million and $100 million. The ultimate amount~~have assessed as being reasonably certain of exercise, for each of the ~~charge will largely depend upon~~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 ~~actual level of participation as well as the actuarial assumptions used~~lessor to ~~measure the pension plans’ assets and obligations, including the discount rates.~~certain lease agreements for office space in our headquarters building, which are insignificant to our financial statements.

Note 911 – Debt and Banking Arrangements

Long-Term Debt

~~Issuances and retirements~~Retirements

~~On July 6, 2017, WPZ repaid its $850 million variable interest rate term loan that was due December 2018 using proceeds from the sale of its Geismar Interest.~~

On June 5, 2017, WPZ issued $1.45 billion of 3.75 percent senior unsecured notes due 2027. WPZ used the proceeds for general partnership purposes, primarily the July 3, 2017 repayment of $1.4 billion of 4.875 percent senior unsecured notes that were due in 2023.

~~On April 3, 2017, Northwest Pipeline issued $250~~We retired approximately $32 million of ~~4.0 percent senior unsecured notes due 2027 to investors in a private debt placement. Northwest Pipeline used the net proceeds to retire $185 million of 5.95~~7.625 percent senior unsecured notes that matured on ~~April~~July 15, 2017, and for general corporate purposes. As part of the issuance, Northwest Pipeline entered into a registration rights agreement with the initial purchasers of the unsecured notes. 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.

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

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

~~Notes (Continued)~~

~~Other financing obligation~~

During the construction of Transco’s Dalton expansion project, WPZ received funding from a partner for its proportionate share of construction costs related to its undivided ownership interest in the project. Amounts received were recorded within noncurrent liabilities. Upon placing the project in service during the third quarter of 2017, WPZ began leasing this partner’s undivided interest in the lateral, including the associated pipeline capacity, and reclassified approximately $237 million of funding previously received from its partner from noncurrent liabilities to debt to reflect the financing obligation payable to its partner over an expected term of 35 years.2019.

Commercial Paper Program

~~As of~~At September 30, ~~2017, no~~ ~~Commercial~~2019, 0 commercial paper was outstanding under ~~WPZ’s $3~~our $4 billion commercial paper program.

Notes (Continued)

Credit Facilities


	September 30, 2017				September 30, 2019
	Stated Capacity		Outstanding		Stated Capacity		Outstanding
	(Millions)				(Millions)
WMB

Long-term credit facility(1)	$	1,500	$	400	$	4,500	$	—
Letters of credit under certain bilateral bank agreements			13				14
WPZ
Long-term credit facility (1)	3,500		—
Letters of credit under certain bilateral bank agreements			1

Note 1012 – Stockholders’ Equity

Issuance of Preferred Shares

In ~~January 2017,~~July 2018, through a wholly owned subsidiary, we contributed 35,000 shares of newly issued 65Series 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. Our certificate of incorporation authorizes 30 million shares of ~~common stock in a public offering at a price of $29.00~~Preferred Stock, $1 par value per ~~share. In February 2017, we issued 9.75 million shares of common stock pursuant to the full exercise of the underwriter’s option to purchase additional~~ shares. The net proceeds of approximately $2.1 billion were used to purchase newly issued common units in WPZ as part of our Financial Repositioning. (See Note 1 – General, Description of Business, and Basis of Presentation.)

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	)

Other comprehensive income (loss) before reclassifications

Amounts reclassified from accumulated other comprehensive income (loss)

~~Notes (Continued)~~

Reclassifications out of AOCI are presented in the following table by component for the nine months ended September 30, ~~2017:~~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 $ (1 ) Product sales

Pension and other postretirement benefits:
Amortization of prior service cost (credit) included in net periodic benefit cost (4 ) Note 8 – Employee Benefit Plans
Amortization of actuarial (gain) loss included in net periodic benefit cost 20
Note 8 – Employee Benefit Plans

Total before tax 15

Income tax benefit (4 ) Provision (benefit) for income taxes
Reclassifications during the period $ 11

Note 1113 – Fair Value Measurements and Guarantees

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



							Fair Value Measurements Using
	Carrying Amount			Fair Value			Quoted Prices In Active Markets for Identical Assets (Level 1)			Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)
	(Millions)
Assets (liabilities) at 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		)

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, 2017:
Measured on a recurring basis:
ARO Trust investments $ 127
$ 127
$ 127
$ —
$ —
Energy derivatives assets not designated as hedging instruments 2
2
1
—
1
Energy derivatives liabilities designated as hedging instruments (6 ) (6 ) (5 ) (1 ) —
Energy derivatives liabilities not designated as hedging instruments (5 ) (5 ) (2 ) —
(3 )
Additional disclosures:
Other receivables 12
12
12
—
—
Long-term debt, including current portion (21,069 ) (22,979 ) —
(22,979 ) —
Guarantees (44 ) (30 ) —
(14 ) (16 )

Assets (liabilities) at December 31, 2016:
Measured on a recurring basis:
ARO Trust investments $ 96
$ 96
$ 96
$ —
$ —
Energy derivatives assets designated as hedging instruments 2
2
—
2
—
Energy derivatives assets not designated as hedging instruments 1
1
—
—
1
Energy derivatives liabilities not designated as hedging instruments (6 ) (6 ) —
—
(6 )
Additional disclosures:
Other receivables 15
15
15
—
—
Long-term debt, including current portion (23,409 ) (24,090 ) —
(24,090 ) —
Guarantees (44 ) (30 ) —
(14 ) (16 )

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

Assets and liabilities measured at fair value on a recurring basis

ARO Trust investments: Transco deposits a portion of its collected rates, pursuant to its rate case settlement, into an external trust (ARO Trust) that is specifically designated to fund future asset retirement obligations (ARO). The ARO Trust invests in a portfolio of actively traded mutual funds that are measured at fair value on a recurring basis based on quoted prices in an active market ~~is classified as available-for-sale,~~ and is reported in Regulatory assets, deferred charges, and other in the Consolidated Balance Sheet. Both realized and unrealized gains and losses are ultimately recorded as regulatory assets or liabilities.

~~Notes (Continued)~~

Energy derivatives: Energy derivatives include commodity-based exchange-traded contracts and over-the-counter contracts, which consist of physical forwards, futures, and swaps that are measured at fair value on a recurring basis. The fair value amounts are presented on a gross basis and do not reflect the netting of asset and liability positions

permitted under the terms of our master netting arrangements. Further, the amounts do not include cash held on deposit in margin accounts that we have received or remitted to collateralize certain derivative positions. Energy derivatives assets are reported in Other current assets and deferred charges and Regulatory assets, deferred charges, and other in the Consolidated Balance Sheet. Energy derivatives liabilities are reported in Accrued liabilities and Regulatory liabilities, deferred income, and other in the Consolidated Balance Sheet.

Reclassifications of fair value between Level 1, Level 2, and Level 3 of the fair value hierarchy, if applicable, are made at the end of each quarter. No transfers between Level 1 and Level 2 occurred during the nine months ended September 30, ~~2017~~2019 or ~~2016~~2018.

Additional fair value disclosures

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

Long-term debt, including current portion: The disclosed fair value of our long-term debt is determined primarily by a market approach using broker quoted indicative period-end bond prices. The quoted prices are based on observable transactions in less active markets for our debt or similar instruments. The fair ~~value~~values of the financing ~~obligation~~obligations associated with our Dalton lateral and Atlantic Sunrise projects, which isare included within long-term debt, ~~was~~were determined using an income ~~approach (see Note 9 - Debt and Banking Arrangements).~~approach.

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

To estimate the ~~disclosed~~ fair value of the WilTel guarantee, an estimated default rate is applied to the sum of the future contractual lease payments using an income approach. The estimated default rate is determined by obtaining the average cumulative issuer-weighted corporate default rate based on the credit rating of WilTel’s current owner and the term of the underlying obligation. The default rate is published by Moody’s Investors Service. The carrying value of the WilTel guarantee is reported in Accrued liabilities in the Consolidated Balance Sheet. The maximum potential undiscounted exposure is approximately ~~$31~~$28 millionat September 30, ~~2017.~~2019. Our exposure declines systematically through the remaining term of WilTel’s obligation.

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

We are required by our revolving credit ~~agreements~~agreement to indemnify lenders for certain taxes required to be withheld from payments due to the lenders and for certain tax payments made by the lenders. The maximum potential amount of future payments under these indemnifications is based on the related borrowings and such future payments cannot currently be determined. These indemnifications generally continue indefinitely unless limited by the underlying tax regulations and have no0 carrying value. We have never been called upon to perform under these indemnifications and have no current expectation of a future claim.

Nonrecurring fair value measurements

The following table presents impairments of assets and equity-method investments associated with certain nonrecurring fair value measurements within Level 3 of the fair value ~~hierarchy.~~hierarchy, except as specifically noted.

Impairments
Nine Months Ended September 30,
Classification Segment Date of Measurement Fair Value 2017 2016
(Millions)
Certain gathering operations (1)
Property, plant, and equipment - net and Intangible assets - net of accumulated amortization
Williams Partners September 30, 2017 $ 439
$ 1,019

Certain gathering operations (2)
Property, plant, and equipment - net and Intangible assets - net of accumulated amortization
Williams Partners September 30, 2017 21
115

Certain NGL pipeline (3) Property, plant, and equipment – net Other September 30, 2017 32
68

Certain olefins pipeline project (4) Property, plant, and equipment – net Other June 30, 2017 18
23

Canadian operations (5) Assets held for sale Williams Partners June 30, 2016 924

$ 341
Canadian operations (5) Assets held for sale Other June 30, 2016 206

406
Certain gathering operations (6) Property, plant, and equipment – net Williams Partners June 30, 2016 18

48
Level 3 fair value measurements of certain assets 1,225
795
Other impairments and write-downs (7) 11
16
Impairment of certain assets $ 1,236
$ 811

Equity-method investments (8) Investments Williams Partners March 31, 2016 $ 1,294

$ 109
Other equity-method investment Investments Williams Partners March 31, 2016 —

3
Impairment of equity-method investments
$ 112



					Impairments
					Nine Months Ended September 30,
	Segment	Date of Measurement	Fair Value		2019			2018
			(Millions)
Impairment of certain assets:
Certain gathering assets (1)	West	June 30, 2019	$	40	$	59
Certain idle gathering assets (2)	West	March 31, 2019	—		12
Certain idle pipeline assets (3)	Other	June 30, 2018	25					$	66
Other impairments and write-downs					5			—
Impairment of certain assets					$	76		$	66
Impairment of equity-method investments:
Laurel Mountain (4)	Northeast G&P	September 30, 2019	$	242	$	79
Appalachia Midstream Investments (5)	Northeast G&P	September 30, 2019	102		17
Pennant (6)	Northeast G&P	August 31, 2019	11		17
UEOM (7)	Northeast G&P	March 17, 2019	1,210		74
Other					(1		)
Impairment of equity-method investments					$	186

Relates to ~~certain~~a gas gathering ~~operations~~system in the ~~Mid-Continent region. During~~Eagle Ford region with expected declines in asset utilization and possible idling of the ~~third quarter of 2017, we received solicitations and engaged in negotiations for the sale of certain of these assets which led to our impairment evaluation.~~gathering system. The estimated fair value of the Property, plant, and equipment – netwas determined using ~~an income~~a market approach ~~and~~which incorporated ~~market inputs based on ongoing negotiations for a potential sale~~indications of ~~a portion of the underlying assets. For the income approach, we utilized a discount rate of 10.2 percent, reflecting an estimate of our cost of capital and risks associated with the underlying assets.~~interest from third parties.

~~Notes (Continued)~~

Reflects impairment of ~~observable inputs in the principal market.~~

Relates to ~~Williams Partners’ previously owned interest in DBJV and current equity-method investment in Laurel Mountain. Our carrying values in these equity-method investments had been written down to~~certain idle pipelines. The estimated fair value ~~at December 31, 2015. Our first-quarter 2016 analysis reflected higher discount rates~~of the Property, plant, and equipment – net was determined by a market approach incorporating information derived from bids received for ~~both~~these assets, which we marketed for sale together with certain other assets. These inputs resulted in a fair value measurement within Level 2 of ~~these equity-method investments, along with lower natural gas prices for Laurel Mountain. We estimated~~ the fair value hierarchy. We sold these assets in the fourth quarter of ~~these equity-method investments~~2018.

Relates to a gas gathering system in the Marcellus region that was adversely impacted by lower sustained forward natural gas price expectations and changes in expected producer activity. The estimated fair value was determined using an income approach. We utilized a discount rate of 10.2 percent in our analysis. This impairment is reported in Other investing income (loss) – net in the Consolidated Statement of Income.

Relates to a certain gathering system held in Appalachia Midstream Investments that was adversely impacted by changes in the timing of expected producer activity. The estimated fair value was determined using an income approach. We utilized a discount rate of 9.0 percent in our analysis. This impairment is reported in Other investing income (loss) – net in the Consolidated Statement of Income.

The estimated fair value of Pennant Midstream, LLC (“Pennant”) was determined by a market approach based on ~~expected future cash flows~~recent observable third-party transactions. These inputs resulted in a fair value measurement within Level 2 of the fair value hierarchy. This impairment is reported in Other investing income (loss) – net in the Consolidated Statement of Income.

The estimated fair value was determined by a market approach based on the transaction price for the purchase of the remaining interest in UEOM as finalized just prior to the signing and ~~appropriate discount rates. The determination~~closing of estimated future cash flows involved significant assumptions regarding gathering volumes and related capital spending. Discount rates utilized ranged from 13.0 percent to 13.3 percent and reflected increasesthe acquisition in ~~our estimated cost~~March 2019 (see Note 2 – Acquisitions). These inputs resulted in a fair value measurement within Level 2 of ~~capital, revised estimates~~the fair value hierarchy. This impairment is reported in Other investing income (loss) - net in the Consolidated Statement of ~~expected future cash flows, and risks associated with the underlying businesses.~~Income.

Note 1214 – Contingent Liabilities

Reporting of Natural Gas-Related Information to Trade Publications

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

In the individual action, filed by Farmland Industries Inc. (Farmland), the court issued an order on May 24, 2016, granting one of our co-defendant’s motion for summary judgment as to Farmland’s claims. On January 5, 2017, the court extended such ruling to us, entering final judgment in our favor. Farmland appealed. On March 27, 2018, the appellate court reversed the district court’s grant of summary judgment, and on April 10, 2018, the defendants filed a petition for rehearing with the appellate court, which was denied on May 9, 2018. The case was remanded to the Nevada federal district court and subsequently has ~~appealed.~~been remanded to its originally filed court, the Kansas federal district court.

In the putative class actions, on March 30, 2017, the court issued an order denying the plaintiffs’ motions for class certification. On June 13, 2017, the United States Court of Appeals for the Ninth Circuit granted the plaintiffs’ petition for permission to appeal the order. On August 6, 2018, the Ninth Circuit reversed the order denying class certification and remanded the ~~appeal is now pending.~~case to the Nevada federal district court.

We reached an agreement to settle two of the actions, and on April 22, 2019, the Nevada federal district court preliminarily approved the settlements, which are on behalf of Kansas and Missouri class members. The final fairness hearing on the settlement occurred August 5, 2019, and a final judgment of dismissal with prejudice was entered the same day.

Two putative class actions remain unresolved, and they have been remanded to their originally filed court, the Wisconsin federal district court.

Because of the uncertainty around the remaining pending unresolved issues, we cannot reasonably estimate a range of potential exposure at this time. However, it is reasonably possible that the ultimate resolution of these actions and our related indemnification obligation could result in a potential loss that may be material to our results of operations.

~~Notes (Continued)~~

In connection with this indemnification, we have an accrued liability balance associated with this matter, and as a result, have exposure to future ~~developments in this matter.~~

~~Geismar Incident~~

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

On October 21, 2013, the U.S. Environmental Protection Agency (EPA) issued an Inspection Report pursuant to the Clean Air Act’s Risk Management Program following its inspection of the facility on June 24 through June 28, 2013. The report notes the EPA’s preliminary determinations about the facility’s documentation regarding process safety, process hazard analysis, as well as operating procedures, employee training, and other matters. On June 16, 2014, we received a request for information related to the Geismar Incident from the EPA under Section 114 of the Clean Air Act to which we responded on August 13, 2014. The EPA could issue penalties pertaining to final determinations. Multiple lawsuits, including class actions for alleged offsite impacts, property damage, customer claims, and personal injury, have been filed against us. The first two trials, for nine plaintiffs claiming personal injury, were held in Louisiana state court in Iberville Parish, Louisiana in September and November 2016. The juries returned adverse verdicts against us, our subsidiary Williams Olefins, LLC, and other defendants. To date, we have settled those cases as well as settled or agreed in principle to settle numerous other personal injury claims, and such aggregate amount greater than our $2 million retention (deductible) value has been or will be recovered from our insurers. We believe these settlements to date substantially resolve any material exposure to such claims arising from the Geismar Incident. We believe that any additional losses arising from our alleged liability will be immaterial to our expected future annual results of operations, liquidity, and financial position and will be substantially covered by our general liability insurance policy, which has an aggregate limit of $610 million applicable to this event.developments.

Alaska Refinery Contamination Litigation

~~In 2010, James West filed a class action lawsuit~~We are involved in ~~state court in Fairbanks, Alaska on behalf~~litigation arising from our ownership and operation of ~~individual property owners whose water contained sulfolane contamination allegedly emanating from~~ the ~~Flint Hills Oil~~North Pole Refinery in North Pole, ~~Alaska. The suit named~~Alaska, from 1980 until 2004, through our ~~subsidiary,~~wholly owned subsidiaries, Williams Alaska Petroleum Inc. (WAPI), and MAPCO Inc. We sold the refinery to Flint Hills Resources Alaska, LLC (FHRA), a subsidiary of Koch Industries, Inc., in 2004. The litigation involves three cases, with filing dates ranging from 2010 to 2014. The actions arise from sulfolane contamination allegedly emanating from the refinery. A putative class action lawsuit was filed by James West in 2010 naming us, WAPI, and FHRA as defendants. We ~~owned and operated the refinery until 2004 when we sold it to FHRA. We~~ and FHRA ~~made claims under the pollution liability insurance policy issued in connection with the sale of the North Pole refinery to FHRA. We and FHRA also~~ filed claims against each other seeking, among other things, contractual indemnification alleging that the other party caused the sulfolane contamination. In 2011, we and FHRA

settled the claim with James ~~West claim.~~West. Certain claims by FHRA against us were resolved by the Alaska Supreme Court in our favor. FHRA’s claims against us for contractual indemnification and statutory claims for damages related to off-site sulfolane remain pending.

~~On March 6, 2014, the~~ The State of Alaska filed ~~suit against FHRA, WAPI, and us~~its action in ~~state court in Fairbanks~~March 2014, seeking injunctive relief and damages in connection with sulfolane contamination of the water supply near the Flint Hills Oil Refinery in North Pole, Alaska. On May 5, 2014, FHRA filed cross-claims against us in the State of Alaska suit for contractual indemnification and statutory claims for damages related to off-site sulfolane.

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

~~In October of 2015, the court consolidated the State of Alaska and North Pole cases.~~damages. Both we and WAPI asserted counterclaims against ~~both~~ the State of Alaska and North Pole, and cross-claims against FHRA. FHRA has also filed cross-claims against us.

The underlying factual basis and claims in the ~~consolidated State of Alaska and North Pole action~~cases are similar to and may duplicate ~~exposure in the James West case.~~exposure. As such, onin February 9, 2017, the three cases were consolidated into one action in state court containing the remaining claims infrom the James West case ~~were consolidated into~~and those of the State of Alaska and North ~~Pole action. A~~Pole. Several trial dates encompassing all three ~~consolidated~~ cases ~~was originally~~have been scheduled

~~Notes (Continued)~~

~~to commence~~ and stricken. Trial commenced in ~~May 2017, but has been continued. A new trial date has not been scheduled.~~October 2019. Due to the ongoing assessment of the level and extent of sulfolane contamination, the lack of an articulated cleanup level for sulfolane, and the lack of a concrete remedial proposal and cost estimate, we are unable to estimate a range of exposure to the State of Alaska or North Pole at this time. We currently estimate that our reasonably possible loss exposure to FHRA could range from an insignificant amount up to $32 million, although uncertainties inherent in the litigation process, expert evaluations, and jury dynamics might cause our exposure to exceed that amount.

Independent of the litigation matter described in the preceding paragraphs, in 2013, the Alaska Department of Environmental Conservation indicated that it views FHRA and us as responsible parties, and that it ~~intended~~intends to enter a compliance order to address the environmental remediation of sulfolane and other possible contaminants including cleanup work outside the refinery’s boundaries. To date, no compliance order has been issued. Due to the ongoing assessment of the level and extent of sulfolane contamination, ~~and~~ the ultimate cost of remediation and division of costs among the potentially responsible parties, and the previously described separate litigation, we are unable to estimate a range of exposure at this time.

Certain of our customers, including one major customer, have been named in various lawsuits alleging underpayment of royalties and claiming, among other things, violations of anti-trust laws and the Racketeer Influenced and Corrupt Organizations Act. We have also been named as a defendant in certain of these cases filed in Pennsylvania ~~and Oklahoma~~ based on allegations that we improperly participated with that major customer in causing the alleged royalty underpayments. ~~The Oklahoma case was transferred to Texas and, on October 2, 2017, voluntarily dismissed by the plaintiff.~~ We believe that the claims asserted are subject to indemnity obligations owed to us by that major customer. ~~Due~~That customer has reached a tentative settlement to resolve substantially all Pennsylvania royalty cases pending, which settlement would apply to both the ~~preliminary status of the cases, we are unable to estimate a range of potential loss at this time.~~

~~Shareholder Litigation~~

~~Between October 2015~~customer and December 2015, purported shareholders of us filed six putative class action lawsuits in the Delaware Court of Chancery that were consolidated into a single suit on January 13, 2016. This consolidated putative class action lawsuit relates to our terminated merger with Energy Transfer Equity, L.P. (Energy Transfer).us. The complaint asserts various claims against the individual members of our Board of Directors, including that they breached their fiduciary duties by agreeing to sell us through an allegedly unfair process and for an allegedly unfair price and by allegedly failing to disclose allegedly material information about the merger. The complaint seeks, among other things, an injunction against the merger and an award of costs and attorneys’ fees. On March 22, 2016, the court granted the parties’ proposed order in the consolidated action to stay the proceedings pending the close of the transaction with Energy Transfer. The plaintiffs havesettlement as reported would not ~~filed an amended complaint. On July 19, 2017, the court dismissed the action with prejudice as to plaintiffs and without prejudice as to all other shareholders of~~require any contribution from us.

A purported shareholder filed a separate class action lawsuit in the Delaware Court of Chancery on January 15, 2016. The putative class action complaint alleged that the individual members of our Board of Directors breached their fiduciary duties by, among other things, agreeing to the WPZ Merger Agreement, which purportedly reduced the merger consideration to have been received in the subsequently proposed but now terminated merger with Energy Transfer. The plaintiff filed a motion to voluntarily dismiss, which the court granted on January 13, 2017. On September 2, 2016, the same purported shareholder filed a derivative action claiming that the members of our Board of Directors breached their fiduciary duties by executing the WPZ Merger Agreement as a defensive measure against Energy Transfer. On September 28, 2016, we requested the court dismiss this action, and on May 15, 2017, the court dismissed the action. On June 6, 2017, the plaintiff filed a notice of appeal.

On March 7, 2016, a purported unitholder of WPZ filed a putative class action on behalf of certain purchasers of WPZ units in U.S. District Court in Oklahoma. The action names as defendants us, WPZ, Williams Partners GP LLC, Alan S. Armstrong, and former Chief Financial Officer Donald R. Chappel and alleges violations of certain federal securities laws for failure to disclose Energy Transfer’s intention to pursue a purchase of us conditioned on us not closing the WPZ Merger Agreement when announcing the WPZ Merger Agreement. The complaint seeks, among other things, damages and an award of costs and attorneys’ fees. The plaintiff filed an amended complaint on August 31, 2016. On October 17, 2016, we requested the court dismiss the action, and on March 8, 2017, the court dismissed the complaint with prejudice. On April 7, 2017, the plaintiff filed a notice of appeal.

~~Notes (Continued)~~

~~We cannot reasonably estimate a range of potential loss related to these matters at this time.~~

Litigation Against Energy Transfer and Related Parties

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

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

The Court of Chancery coordinated the Special Offering and Tax Opinion suits. On May 20, 2016, the Energy Transfer defendants filed amended affirmative defenses and verified counterclaims in the Special Offering and Tax Opinion suits, alleging certain breaches of the ETE Merger Agreement by us and seeking, among other things, a declaration that we were not entitled to specific performance, that Energy Transfer could terminate the ETC Merger, and that Energy Transfer is entitled to a $1.48 billion termination fee. On June 24, 2016, following a two-day trial, the court issued a Memorandum Opinion and Order denying our requested relief in the Tax Opinion suit. The court did not rule on the substance of our claims related to the Special Offering or on the substance of Energy Transfer’s counterclaims. On June 27, 2016, we filed an appeal of the court’s decision with the Supreme Court of Delaware, seeking reversal and remand to pursue damages. On March 23, 2017, the Supreme Court of Delaware affirmed the Court of Chancery’s ruling. On March 30, 2017, we filed a motion for reargument with the Supreme Court of Delaware, which was denied on April 5, 2017.

On September 16, 2016, we filed an amended complaint with the Court of Chancery seeking damages for breaches of the ETE Merger Agreement by defendants. On September 23, 2016, Energy Transfer filed a second amended and supplemental affirmative defenses and verified counterclaim with the Court of Chancery seeking, among other things, payment of the $1.48 billion termination fee due to our alleged breaches of the ETE Merger Agreement. WeOn December 1, 2017, the court granted our motion to dismiss certain of Energy Transfer’s counterclaims, including its claim seeking payment of the $1.48 billion termination fee. On December 8, 2017, Energy Transfer filed a motion for reargument, which the Court of Chancery denied on April 16, 2018. The Court of Chancery previously scheduled trial for May 20 through May 24, 2019; the court struck the trial setting and has re-scheduled trial for June 8 through June 11 and June 15, 2020.

Former Olefins Business

SABIC Petrochemicals, the other interest owner in our former Geismar, Louisiana, olefins facility we sold in July 2017, is seeking recovery from us for losses it allegedly suffered, including its share of personal injury settlements in which it was a co-defendant, as well as amounts related to ~~dismiss Energy Transfer’s counterclaims,~~lost income, defense costs, and property damage associated with an explosion and fire at the plant in June 2013. Due to the complexity of the various claims and available defenses, we are unable to reliably estimate any reasonably possible losses at this time. Trial began on October 14, 2019, as scheduled, but on October 21, 2019, the Court declared a mistrial due to the conduct of an officer of SABIC Petrochemicals and SABIC Petrochemicals’ expert witness. No new trial date has been set. We believe that certain losses incurred arising directly from the explosion and fire will be covered by our general liability policy and any uninsured losses are not expected to be material.

On August 31, 2018, Transco submitted to the FERC a general rate filing principally designed to recover increased costs and to comply with the terms of the settlement in its prior rate proceeding. The new rates became effective March 1, 2019, subject to refund and the outcome of a hearing. In October 2019, we reached an agreement on the terms of 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 subject to the filing of a formal stipulation and agreement with, and subsequent approval by, the FERC. As of September 30, 2019, we have provided a $131 million reserve for rate refunds which ~~was fully briefed on November 14, 2016, and oral argument occurred on November 30, 2016.~~we believe is adequate for any refunds that may be required.

Environmental Matters

We are a participant in certain environmental activities in various stages including assessment studies, cleanup operations, ~~and~~and/or remedial processes at certain sites, some of which we currently do not own. We are monitoring these sites in a coordinated effort with other potentially responsible parties, the ~~EPA, and~~U.S. Environmental Protection Agency (EPA), or other governmental authorities. We are jointly and severally liable along with unrelated third parties in some of these activities and solely responsible in others. Certain of our subsidiaries have been identified as potentially responsible parties at various Superfund and state waste disposal sites. In addition, these subsidiaries have incurred, or are alleged to have incurred, various other hazardous materials removal or remediation obligations under environmental laws. As of September 30, ~~2017,~~2019, we have accrued liabilities totaling ~~$40~~$33 million for these matters, as discussed below. ~~Our accrual reflects~~Estimates of the most likely costs of cleanup ~~which~~ are generally based on completed assessment studies, preliminary results of studies,

or our experience with other similar cleanup operations. ~~Certain~~At September 30, 2019, certain assessment studies ~~are~~were still in process for which the ultimate outcome may yield ~~significantly~~ different estimates of most likely costs. ~~Any incremental amount in excess of amounts currently accrued cannot be reasonably estimated at this time due to uncertainty about~~Therefore, the actual ~~number of contaminated sites ultimately~~

~~Notes (Continued)~~

~~identified,~~costs incurred will depend on the ~~actual~~final amount, type, and extent of contamination discovered ~~and~~at these sites, the final cleanup standards mandated by the EPA or other governmental authorities, and other ~~governmental authorities.~~factors.

The EPA and various state regulatory agencies routinely promulgate and propose new rules and issue updated guidance to existing rules. ~~More recent rules and~~These rulemakings include, but are not limited to, rules for reciprocating internal combustion engine maximum achievable control technology, air quality standards for ~~one hour~~one-hour nitrogen dioxide emissions, and volatile organic compound and methane new source performance standards impacting design and operation of storage vessels, pressure valves, and compressors. ~~On October 1, 2015, the~~The EPA previously issued its rule regarding National Ambient Air Quality Standards for ground-level ~~ozone, setting a standard of 70 parts per billion.~~ozone. We are monitoring the rule’s implementation as it will trigger additional federal and ~~evaluating potential~~state regulatory actions that may impact our operations. Implementation of the regulations is expected to result in impacts to our ~~operations. For these~~operations and ~~other~~increase the cost of additions to Property, plant, and equipment – net in the Consolidated Balance Sheet for both new ~~regulations, we~~and existing facilities in affected areas. We are unable to reasonably estimate the ~~costs~~cost of ~~asset~~ additions ~~or modifications necessary~~that may be required to ~~comply~~meet the regulations at this time due to uncertainty created by ~~the~~ various legal challenges to these regulations and the need for further specific regulatory guidance.

Continuing operations

Our interstate gas pipelines are involved in remediation activities related to certain facilities and locations for polychlorinated biphenyls, mercury, and other hazardous substances. These activities have involved the EPA and various state environmental authorities, resulting in our identification as a potentially responsible party at various Superfund waste sites. At September 30, ~~2017~~2019, we have accrued liabilities of $8$5 million for these costs. We expect that these costs will be recoverable through rates.

We also accrue environmental remediation costs for natural gas underground storage facilities, primarily related to soil and groundwater contamination. At September 30, ~~2017~~2019, we have accrued liabilities totaling $8 million for these costs.

Former operations ~~including operations classified as discontinued~~

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

Other Divestiture Indemnifications

Pursuant to various purchase and sale agreements relating to divested businesses and assets, we have indemnified certain purchasers against liabilities that they may incur with respect to the businesses and assets acquired from us. The indemnities provided to the purchasers are customary in sale transactions and are contingent upon the purchasers incurring liabilities that are not otherwise recoverable from third parties. The indemnities generally relate to breach of

warranties, tax, historic litigation, personal injury, property damage, environmental matters, right of way, and other representations that we have provided.

At September 30, ~~2017~~2019, other than as previously disclosed, we are not aware of any material claims against us involving the indemnities; thus, we do not expect any of the indemnities provided pursuant to the sales agreements to

~~Notes (Continued)~~

have a material impact on our future financial position. Any claim for indemnity brought against us in the future may have a material adverse effect on our results of operations in the period in which the claim is made.

In addition to the foregoing, various other proceedings are pending against us which are incidental to our operations, none of which are expected to be material to our expected future annual results of operations, liquidity, and financial position.

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

Note 1315 – Segment Disclosures

~~We have one~~Our reportable ~~segment, Williams Partners.~~segments are Northeast G&P, Atlantic-Gulf, and West. All remaining business activities are included in Other. (See Note 1 – General, Description of Business, and Basis of Presentation.)

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

We evaluate segment operating performance based upon Modified EBITDA (earnings before interest, taxes, depreciation, and amortization). This measure represents the basis of our internal financial reporting and is the primary performance measure used by our chief operating decision maker in measuring performance and allocating resources among our reportable segments. Intersegment revenues primarily represent the sale of NGLs from our natural gas processing plants to our marketing business.

We define Modified EBITDA as follows:

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.

~~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 ~~Operations~~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

Williams
Partners
Other Eliminations Total
(Millions)
Three Months Ended September 30, 2017
Segment revenues:
Service revenues
External $ 1,304
$ 6
$ —
$ 1,310
Internal —
2
(2 ) —
Total service revenues 1,304
8
(2 ) 1,310
Product sales
External 581
—
—
581
Internal —
—
—
—
Total product sales 581
—
—
581
Total revenues $ 1,885
$ 8
$ (2 ) $ 1,891

Three Months Ended September 30, 2016
Segment revenues:
Service revenues
External $ 1,241
$ 6
$ —
$ 1,247
Internal 11
3
(14 ) —
Total service revenues 1,252
9
(14 ) 1,247
Product sales
External 655
3
—
658
Internal —
6
(6 ) —
Total product sales 655
9
(6 ) 658
Total revenues $ 1,907
$ 18
$ (20 ) $ 1,905

Nine Months Ended September 30, 2017
Segment revenues:
Service revenues
External $ 3,836
$ 17
$ —
$ 3,853
Internal 1
8
(9 ) —
Total service revenues 3,837
25
(9 ) 3,853
Product sales
External 1,950
—
—
1,950
Internal —
—
—
—
Total product sales 1,950
—
—
1,950
Total revenues $ 5,787
$ 25
$ (9 ) $ 5,803

Nine Months Ended September 30, 2016
Segment revenues:
Service revenues
External $ 3,656
$ 22
$ —
$ 3,678
Internal 32
17
(49 ) —
Total service revenues 3,688
39
(49 ) 3,678
Product sales
External 1,613
10
—
1,623
Internal —
16
(16 ) —
Total product sales 1,613
26
(16 ) 1,623
Total revenues $ 5,301
$ 65
$ (65 ) $ 5,301

September 30, 2017
Total assets $ 45,635
$ 570
$ (85 ) $ 46,120
December 31, 2016
Total assets $ 46,265
$ 685
$ (115 ) $ 46,835

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

The following table reflects the reconciliation of Modified EBITDA to Net income (loss) as reported in the Consolidated Statement of ~~Operations~~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,
2017 2016 2017 2016
(Millions)
Modified EBITDA by segment:
Williams Partners $ 1,000
$ 1,070
$ 3,208
$ 2,629
Other (61 ) (67 ) (60 ) (534 )
939
1,003
3,148
2,095
Accretion expense associated with asset retirement obligations for nonregulated operations (7 ) (9 ) (23 ) (24 )
Depreciation and amortization expenses (433 ) (435 ) (1,308 ) (1,326 )
Equity earnings (losses) 115
104
347
302
Impairment of equity-method investments —
—
—
(112 )
Other investing income (loss) – net 4
28
278
64
Proportional Modified EBITDA of equity-method investments (202 ) (194 ) (611 ) (574 )
Interest expense (267 ) (297 ) (818 ) (886 )
(Provision) benefit for income taxes (24 ) (69 ) (126 ) 74
Net income (loss) $ 125
$ 131
$ 887
$ (387 )

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.~~NGLs through our gas pipeline and midstream business. Our operations are located ~~principally~~ in the United States. ~~We have one reportable segment, Williams Partners. All remaining business activities are included in Other.~~

~~Williams Partners~~

~~Williams Partners consists of our consolidated master limited partnership, WPZ, which includes gas pipeline and midstream businesses. The gas pipeline businesses include~~Our interstate natural gas ~~pipelines and~~ pipeline ~~joint project investments; and~~strategy is to create value by maximizing the midstream businesses provide natural gas gathering, treating, and processing services; NGL production, fractionation, storage, marketing, and transportation; deepwater production handling and crude oilutilization of our pipeline capacity by providing high quality, low cost transportation ~~services; and is comprised of several wholly owned and partially owned subsidiaries and joint project investments. As of September 30, 2017, we own 74 percent of the interests in WPZ.~~

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

~~Williams Partners’ midstream businesses primarily consist of (1) natural~~growing markets. Our gas gathering, treating, compression, and processing; (2) NGL fractionation, storage, and transportation; (3) crude oil production handling and transportation; and (4) olefins production. (See Note 3 – Divestitures of Notes to Consolidated Financial Statements.) The primary service areas are concentrated in major producing basins in Colorado, Texas, Oklahoma, Kansas, New Mexico, Wyoming, the Gulf of Mexico, Louisiana, Pennsylvania, West Virginia, New York, and Ohio which include the Barnett, Eagle Ford, Haynesville, Marcellus, Niobrara, and Utica shale plays as well as the Mid-Continent region.

The midstream businesses include equity-method investments in natural gas gathering and processing assets and NGL fractionation and transportation assets, including a 62 percent equity-method investment in UEOM, a 69 percent equity-method investment in Laurel Mountain, a 58 percent equity-method investment in Caiman II, a 60 percent equity-method investment in Discovery, a 50 percent equity-method investment in OPPL, and Appalachia Midstream Services, LLC, which owns an approximate average 66 percent equity-method investment interest in multiple gas gathering systems in the Marcellus Shale (Appalachia Midstream Investments), as well as our previously owned 50 percent equity-method investment in the Delaware basin gas gathering system (DBJV) in the Mid-Continent region (see Note 4 – Investing Activities of Notes to Consolidated Financial Statements).

The midstream businesses previously included Canadian midstream operations, which were comprised of an oil sands offgas processing plant near Fort McMurray, Alberta and an NGL/olefin fractionation facility at Redwater, Alberta. In September 2016, these Canadian operations were sold.

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

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

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

limited near-term impact on these revenues because the majority of cost of service is recovered through firm capacity reservation charges in transportation rates.

~~Other~~

~~Our former~~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 ~~& Petchem Services segment included certain domestic olefins pipeline assets~~fractionation and transportation, crude oil production handling and transportation, marketing services for NGL, crude oil, and natural gas, as well as ~~certain Canadian assets,~~storage facilities.

Our operations are presented within the following reportable segments: Northeast G&P, Atlantic-Gulf, and West, consistent with the manner in which ~~included a liquids extraction plant located near Fort McMurray, Alberta, that began operations in March 2016,~~our chief operating decision maker evaluates performance and ~~a propane dehydrogenation facility which was under development. In September 2016, the Canadian assets were sold. Considering this, the~~allocates resources. All remaining ~~assets are now reported within Other, effective January 1, 2017. Other also includes~~ business activities ~~that are not operating segments,~~ as well as corporate ~~operations. Prior period segment disclosures have been recast for this segment change.~~activities are included in Other. Our reportable segments are comprised of the following businesses:

~~Financial Repositioning~~

~~In January 2017, we announced agreements with WPZ, wherein we permanently waived~~Northeast G&P is comprised of our midstream gathering, processing, and fractionation businesses in the ~~general partner’s IDRs~~Marcellus Shale region primarily in Pennsylvania, New York, and ~~converted our 2~~West Virginia and the Utica Shale region of eastern Ohio, including a 66 percent ~~general partner~~ interest in ~~WPZ to~~Cardinal (a consolidated entity), as well as a ~~noneconomic~~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 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 atmultiple gas gathering systems in the Marcellus Shale (Appalachia Midstream Investments). Northeast G&P includes a ~~price of $36.08586 per unit~~65 percent interest in ~~a private placement transaction, funded with proceeds from~~the Northeast JV (a consolidated entity), which includes our ~~equity offering~~existing Ohio Valley assets and UEOM (see Note 102 – ~~Stockholders’ Equity~~Acquisitions of Notes to Consolidated Financial Statements). ~~According~~

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, 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 4 – Variable Interest Entities of Notes to Consolidated Financial Statements).

West is comprised of our interstate natural gas pipeline, Northwest Pipeline, and our gathering, processing, and treating operations in Colorado, Wyoming, the ~~terms~~Barnett Shale region of ~~this agreement, concurrent with WPZ’s quarterly distributions~~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 and Arkoma basins. This segment also includes our NGL and natural gas marketing business, storage facilities, an undivided 50 percent interest in ~~February 2017~~an NGL fractionator near Conway, Kansas, a 50 percent equity-method investment in OPPL, a 50 percent equity-method investment in RMM, and ~~May 2017, we paid additional consideration totaling $56 million to WPZ for these units. Subsequent to these transactions~~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 ~~September~~June 30, ~~2017, we own a 74 percent limited partner interest~~2018), which was sold in ~~WPZ.~~

~~Termination of WPZ Merger Agreement~~

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

On September 28, 2015, prior to our entry into the Merger Agreement, we entered into a Termination Agreement and Release (Termination Agreement), terminating the WPZ Merger Agreement. Under the terms of the Termination Agreement, we were required to pay a $428 million termination fee to WPZ, at which time we owned approximately 60 percent, including the interests of the general partner and IDRs. Such termination fee settled through a reduction of quarterly incentive distributions we were entitled to receive from WPZ (such reduction not to exceed $209 million per quarter). The distributions from WPZ in November 2015, February 2016, and May 2016 were reduced by $209 million, $209 million, and $10 million, respectively, related to this termination fee.April 2019.

Management’s Discussion and Analysis (Continued)

Dividends

In September ~~2017,~~2019, we paid a regular quarterly dividend of ~~$0.30~~$0.38 per share.

Overview of Nine Months Ended September 30, ~~2017~~2019

Net income (loss) attributable to The Williams Companies, Inc., for the nine months ended September 30, ~~2017, changed favorably by $896~~2019, increased $310 millioncompared to the nine months ended September 30, ~~2016,~~2018, reflecting ~~an increase~~$362 million of ~~$972 million in operating income, a $214 million increase in~~ ~~Other investing income (loss) – net~~increased service revenues primarily associated with expansion projects, a $269 million decrease to Net income (loss) attributable to noncontrolling interests primarily due to the ~~disposition~~WPZ Merger, a $122 million gain on the second-quarter 2019 sale of ~~certain equity-method investments~~our 50 percent interest in ~~2017,~~Jackalope, and the absence of ~~$112~~a 2018 charge for a valuation allowance on foreign tax credits. These increases are partially offset by $186 million of impairments of equity-method investments ~~incurred~~ in ~~2016, and reduced~~2019, lower commodity margins, the absence of the Four Corners area business which was sold in October 2018, higher interest expense, ~~partially~~the absence of a prior year $62 million 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 current year were substantially offset by ~~a $200 million increase~~similar levels of impairments in the provision for income taxes, driven by higher pre-tax income, partially offset by a $127 million benefit associated with the release of a valuation allowance on a capital loss carryover and a $378 million increase in net income attributable to noncontrolling interests primarily due to increased income at WPZ. The improvement in operating income reflects a gain of $1.095 billion from the sale of our Geismar Interest, increase service revenue from expansion projects, and lower costs and expenses, partially offset by a $113 million decrease in product margins primarily due to the loss of olefins volumes as a result of the sale of our Gulf Olefins and Canadian operations, and a $425 million increase in impairments of certain assets.prior year.

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

~~Unless indicated otherwise, the~~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~~Annual Report on Form 10-K dated February 21, 2019.

Acquisition of 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 ~~notes thereto~~closed the acquisition of the remaining 38 percent interest in ~~Exhibit 99.1 of our Form 8-K dated May 25, 2017.~~

~~Pension Deferred Vested Benefit Early Payout Program~~

~~In September 2017, we initiated a program to pay out certain deferred vested pension benefits to reduce investment risk,~~UEOM. Total consideration paid, including post-closing adjustments, was $741 million in cash ~~funding volatility,~~funded through credit facility borrowings and administrative costs. Eligible participants had until October 31, 2017, to make elections. We expect to make the lump-sum payments and commence the annuity payments in December 2017, and intend to fund the payments from existing assets in our pension plans.cash on hand. As a result of ~~these payouts~~acquiring this additional interest, we obtained control of and ~~based on current assumptions,~~now consolidate UEOM. (See Note 2 – Acquisitions of Notes to Consolidated Financial Statements.)

Northeast JV

Concurrent with the UEOM acquisition, we ~~expect~~executed an agreement whereby we contributed our consolidated interests in UEOM and our Ohio Valley midstream business to ~~record~~ a ~~pre-tax, non-cash settlement charge in the fourth quarter~~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, ~~2017 that we estimate will be between $70 million and $100 million. The ultimate amount of the charge will largely depend upon the actual level of participation~~ as well as operate and consolidate, the ~~actuarial assumptions used to measure the pension plans’ assets and obligations, including the discount rates.~~Northeast JV business.

~~Williams Partners~~

~~New York Bay Expansion~~Sale of Jackalope

In ~~October 2017,~~April 2019, we sold our interest in Jackalope for $485 million in cash, resulting in a gain on the ~~New York Bay~~ disposition of $122 million.

Expansion Project Update

Rivervale South to Market

In August 2018, we received approval from the ~~Transco system was placed into service. The project expanded~~FERC to expand Transco’s existing natural gas transmission system to provide incremental firm transportation capacity from ~~Station 195 in Pennsylvania~~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 ~~Rockaway Delivery Lateral transfer point and the Narrows meter station in New York.~~project was placed into service on September 1, 2019. The full project increased capacity by ~~115~~190 Mdth/d.

~~Dalton~~Ohio River Supply Hub Expansion

~~In August 2017, the Dalton expansion~~We agreed to ~~the Transco system was placed into service. This project expanded Transco’s existing natural gas transmission system together with greenfield facilities~~expand our services for certain customers to provide ~~incremental firm transportation~~additional rich gas processing capacity ~~from our Station 210~~ in ~~New Jersey to markets~~the Marcellus and Upper Devonian Shale in ~~northwest Georgia. On April 1, 2017, we began providing firm transportation service through the mainline portion of the project on an interim basis~~West Virginia and ~~we placed the full project into service in August 2017. The project increased capacity by 448 Mdth/d.~~

~~Hillabee~~

In July 2017, Phase I of the Hillabee Expansion Project was placed into service. The project involves an expansion of Transco’s existing natural gas transmission system from our Station 85 in west central Alabama to a new interconnection with the Sabal Trail pipeline in Alabama. The project will be constructed in phases, and all of the project expansion capacity will be leased to Sabal Trail. We placed a portion of Phase I into service in June of 2017 and the remainder of Phase I into service in July of 2017. Phase I increased capacity by 818 Mdth/d. The in-service date of Phase II is planned for the second quarter of 2020 and together they are expected to increase capacity by 1,025 Mdth/d.

In March 2016, WPZ entered into an agreement with the member-sponsors of Sabal Trail to resolve several matters. In accordance with the agreement, the member-sponsors paid us an aggregate amount of $240 million in three equal installments as certain milestones of the project were met. The first $80 million payment was received in March 2016, the second installment was received in September 2016 and the third installment was received in July 2017. WPZ expects to recognize income associatedPennsylvania. Associated with these ~~receipts over~~agreements, we have expanded the ~~term~~inlet processing capacity of ~~the capacity lease agreement.~~

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 matterour Oak Grove facility to the FERC for preparation of an Environmental Impact Statement 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).400 MMdf/d. We ~~along with other intervenors, and the FERC~~ have ~~filed petitions for rehearing with the court to overturn~~also constructed

Management’s Discussion and Analysis (Continued)

a new NGL pipeline from Moundsville to the ~~remedy~~Harrison Hub fractionation facility to provide an 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 provide deepwater gas gathering services to the Appomattox development in the Gulf of Mexico. We completed modifications to install an alternate delivery route to our Main Pass 261 Platform, as well as modifications to our 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 from the Appomattox development to 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. 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 a settlement with the participants that would ~~involve vacating~~resolve all issues in the ~~FERC certificate order. If~~rate case without the ~~court’s mandate~~need for a hearing. Final resolution of the rate case is ~~issued prior~~subject to the ~~FERC re-issuing certificate authority~~filing of a formal stipulation and agreement with, and subsequent approval by, the FERC. We have provided a reserve of $131 million for ~~the projects,~~rate refunds which we believe is adequate for any refunds that ~~the FERC will take the necessary steps (which~~ may ~~include issuing temporary certificate authority) to avoid any lapse in federal authorization for the projects.~~

~~Hurricanes Harvey and Irma~~

~~We are not aware of any major damage to our facilities as a result of Hurricanes Harvey and Irma.~~

~~Geismar olefins facility monetization~~

In July 2017, WPZ completed the sale of its Geismar Interest for $2.084 billion in cash. WPZ received a final working capital adjustment of $12 million in October 2017. Additionally, WPZ entered into a long-term supply and transportation agreement with the purchaser to provide feedstock to the plant via its Bayou Ethane pipeline system, which is expected to provide a long-term, fee-based revenue stream. (See~~Note 3 – Divestitures of Notes to Consolidated Financial Statements.)~~

Following this sale, the cash proceeds were used to repay WPZ’s $850 million term loan. WPZ also plans to use these proceeds to fund a portion of the capital and investment expenditures that are a part of its growth portfolio.

~~Acquisition of additional interests in Appalachia Midstream Investments~~

During the first quarter of 2017, WPZ exchanged all of its 50 percent interest in DBJV for an increased interest in two natural gas gathering systems that are part of the Appalachia Midstream Investments and $155 million in cash. Following this exchange, WPZ has an approximate average 66 percent interest in the Appalachia Midstream Investments. WPZ also sold all of its interest in Ranch Westex JV LLC for $45 million. These transactions resulted in a total gain of $269 million reflected in ~~Other investing income (loss) – net~~ ~~in the Consolidated Statement of Operations within the Williams Partners segment. (See Note 4 – Investing Activities of Notes to Consolidated Financial Statements.)~~be required.

Commodity Prices

NGL per-unit margins were approximately 6451 percent ~~higher~~lower in the first nine months of ~~2017~~2019 compared to the same period of ~~2016~~2018 primarily due to a 4232 percent ~~increase~~decrease in per-unit non-ethane prices. The per-unit margin increase also reflects the absence of our former Canadian operations which had lower per-unit non-ethane margins in the prior year compared to our domestic operations. These favorable impacts were partially offset byprices and an approximate 373 percent 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.

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

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

The potential impact of commodity prices on our business for the remainder of ~~2017~~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.

Our business plan for ~~2017~~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 by Transco expansion projects and continued expansion in the ~~previously discussed financial repositioning transactions~~Northeast region.

Management’s Discussion and the monetization of our Geismar Interest. For WPZ, these transactions serve to improve its cost of capital, remove its need to access the public equity markets for the next several years, enhance growth, and provide for debt reduction, solidifying WPZ as an attractive financing vehicle. The transactions also facilitate a reduction of our parent-level debt and provide for dividend growth flexibility, while retaining strategic and financing flexibility.Analysis (Continued)

Our growth capital and investment expenditures in ~~2017~~2019 are expected to be ~~between $2.1 billion and $2.8 billion. Approximately $1.4~~in a range from $2.3 billion to ~~$1.9 billion of our growth~~$2.5 billion. 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 2017 primarily reflects investment in~~agreements, and continuing to develop our gathering and processing ~~systems~~infrastructure in the Northeast ~~region limited primarily to known new producer volumes, including volumes that support Transco expansion projects including our Atlantic Sunrise project.~~G&P and West segments. In addition to growth capital and investment expenditures, we also

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

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, ~~as well as the sale of our Canadian operations and Geismar Interest,~~ fee-based businesses are ~~becoming an even more~~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 ~~the remainder of 2017,~~2019, current forward market prices indicate crude oil, ~~and~~ natural gas, ~~prices are expected to be relatively comparable to the same period in 2016, while~~and NGL prices are expected to be ~~higher. However, some of our customers may~~lower compared to 2018. We 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. The credit profiles~~address certain pricing risks through the utilization of ~~certain of our producer customers have been, and may continue to be, challenged as a result of lower energy~~ commodity ~~prices. Unfavorable changes in energy commodity prices or the credit profile of our producer customers may also result in noncash impairments of our assets.~~hedging strategies.

In ~~2017,~~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 ~~2017.~~its general rate case as previously discussed. For our non-regulated businesses, we anticipate increases in fee-based revenue ~~due to expanded capacity in the Eastern Gulf area and a slight increase in fee-based revenue~~ in the Northeast ~~region. Partially offsetting these increases are expected declines in fee-based revenue~~G&P segment driven by expansion projects, partially offset with a decrease in the ~~Western region.~~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 associated with the end of a contractual MVC period. We expect overall gathering and processing volumes to ~~remain steady~~grow in ~~2017 and increase thereafter to meet~~2019 for our continuing businesses. Additionally, we believe our expenses will be impacted by the ~~growing demand for natural gas and natural gas products. We also anticipate lower general and administrative expenses due to cost reduction initiatives~~changes in our asset portfolio, including the UEOM acquisition and asset ~~monetizations.~~divestitures, as well as severance charges and other costs associated with our 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;

~~Lower than expected distributions from WPZ;~~

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, 2018, as filed with the SEC on February ~~22, 2017.~~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

~~Williams Partners’~~Our ongoing major expansion projects include the following:

~~Appalachian Basin~~Northeast G&P

Susquehanna Supply Hub Expansion

We ~~recently agreed~~continue to expand ~~our services to a customer to provide 660 MMcf/d of processing wet gas capacity~~the gathering systems in the ~~Marcellus and Upper Devonian Shale in West Virginia. Associated with this agreement, we expect~~Susquehanna Supply Hub that are needed to ~~further~~

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

~~expand~~meet our customers’ production plans by 2020. This next expansion of the ~~processing capacity of our Oak Grove facility, which has the ability to increase capacity by~~gathering infrastructure includes an additional ~~1.8~~40,000 horsepower of new compression and gathering pipelines to bring the capacity to approximately 4.5 Bcf/d. Additionally, with the same customer, we secured a gathering dedication agreement to gather dry gas in this same region. These expansions will be supported by long-term, fee-based agreements and volumetric commitments.

~~Atlantic Sunrise~~

In February 2017, we received approval from the FERC to expand Transco’s existing natural gas transmission system along with greenfield facilities to provide incremental firm transportation capacity from the northeastern Marcellus producing area to markets along Transco’s mainline as far south as Station 85 in west central Alabama. We placed a portion of the mainline project facilities into service on September 1, 2017 and it increased capacity by 400 Mdth/d. We plan to place the full project into service during mid-2018, assuming timely receipt of all remaining regulatory approvals. The full project is expected to increase capacity by 1,700 Mdth/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 ~~will be~~are the operator of Constitution. The 126-mile Constitution pipeline ~~will~~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. As to the denial itself, the court determined that NYSDEC’s action was not arbitrary or capricious. Constitution filed a petition for rehearing of the Second Circuit Court’s decision, but in October the court denied our petition.

~~We remain steadfastly committed to the~~this project, and in October 2017 we filed a petition for declaratory order requesting the FERC to find that, by operation of law, the Section 401 certification requirement for the New York State portion of Constitution’s pipeline project was waived due to the failure by the NYSDEC to act on Constitution’s Section 401 application within a reasonable period of time as required by the express terms of such statute.

In light of the NYSDEC’s denial of the water quality certification and the actions taken to challenge the decision, the anticipated target in-service date is as early as the first half of 2019, which assumes the timely receipt of a Notice to Proceed from the FERC. (Seesee Note 24 – Variable Interest Entities of Notes to Consolidated Financial Statements.)

~~Eagle Ford~~

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

~~Garden State~~Gateway

In ~~April 2016,~~December 2018, we 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 proposed interconnection with Transco’s mainline south of Station ~~210~~205 in New Jersey to ~~a new interconnection on our Trenton Woodbury Lateral in~~other existing Transco meter stations within New Jersey. ~~The project will be constructed in phases and is expected~~We plan to ~~increase capacity by 180 Mdth/d. We placed the initial phase of~~place the project into service ~~on September 9, 2017 and plan to place the remaining portion of the project into service during the second quarter of 2018.~~

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

~~Gulf Connector~~

~~In August 2016, we filed an application with the FERC to expand Transco’s existing natural gas transmission system to provide incremental firm transportation capacity from Station 65~~ in ~~Louisiana to delivery points in Wharton and San Patricio Counties, Texas. The project will be constructed in two phases and we plan to place both phases into service during~~ the first half of ~~2019,~~2020, assuming timely receipt of all necessary regulatory approvals. The project is expected to increase capacity by ~~475~~65 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 ~~will be~~is being constructed in phases, and all of the project expansion capacity ~~will be leased~~is dedicated to Sabal ~~Trail. We placed~~Trail pursuant to a ~~portion of~~capacity lease agreement. 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 ~~they~~Phases I and II are expected to increase capacity by 1,025 Mdth/d. ~~See Williams Partners within Overview of Nine Months Ended September 30, 2017.~~

~~Norphlet Project~~Northeast Supply Enhancement

In ~~March 2016,~~May 2019, we ~~announced that we have reached an agreement~~received approval from the FERC to expand Transco’s existing natural gas transmission system to provide ~~deepwater gas gathering services~~incremental firm transportation capacity from Station 195 in Pennsylvania to the ~~Appomattox development~~Rockaway Delivery Lateral transfer point in New York. Approvals required for the 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 applications for such approvals. We have refiled our applications for those approvals and have addressed the technical issues identified by the agencies. We plan to place the project into service in the ~~Gulf~~fourth quarter 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.2020, assuming timely receipt of these remaining approvals. The project is ~~scheduled~~expected to goincrease capacity by 400 Mdth/d.

Southeastern Trail

In 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 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 ~~during~~in the second half of ~~2019.~~2022, assuming timely receipt of all necessary regulatory approvals. The project is expected to increase capacity by 582 Mdth/d.

West

North Seattle Lateral Upgrade

In ~~May 2017,~~July 2018, we ~~filed an application with~~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. The project is expected to increase delivery capacity by ~~up to~~approximately 159 Mdth/d.

~~Northeast Supply Enhancement~~Wamsutter Expansion

~~In March 2017, we filed an application with~~We have expanded our gathering and processing infrastructure in the ~~FERC~~Wamsutter region of Wyoming in order to ~~expand Transco’s existing natural gas transmission system~~meet our customers’ production plans. We have completed construction of new compressor stations and modifications to ~~provide incremental firm transportation capacity from Station 195~~our processing facilities, which are now in ~~Pennsylvania~~service. The expansion added approximately 20 miles of gathering pipelines and approximately 15,000 horsepower of compression. Additional expansion is expected in 2020, subject to the ~~Rockaway Delivery Lateral transfer point~~level of production activity in ~~New York.~~ the area.

Project Bluestem

We ~~plan~~are expanding our presence in the Mid-Continent region through building a 188-mile pipeline from our fractionator near Conway, Kansas to ~~place~~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, ~~into service in late 2019 or~~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 ~~half~~quarter of ~~2020, assuming timely receipt of all necessary regulatory approvals.~~2019, we exercised an option to purchase a 20 percent equity interest in a Mt. Belvieu fractionation train developed by the third party. The ~~project is~~pipeline and extension projects are expected to ~~increase capacity by 400 Mdth/d.~~

~~Susquehanna Supply Hub Expansion~~

The Susquehanna Supply Hub Expansion, which involves two new compression facilities with an additional 49,000 horsepower and 59 miles of 12 inch to 24 inch pipeline, is expected to increase gathering capacity, allowing a certain producer to fulfill its commitment to deliver 850 Mdth/d to our Atlantic Sunrise development. We anticipate this expansion will be ~~completed by the end of 2017.~~

~~Virginia Southside II~~

In July 2016, we received approval from the FERC to expand Transco’s existing natural gas transmission system together with greenfield facilities to provide incremental firm transportation capacity from our Station 210 in New Jersey and our Station 165 in Virginia to a proposed delivery point on a new lateral extending from our Brunswick Lateral in Virginia. We plan to place the projectplaced into service during the ~~fourth~~first quarter of ~~2017 and it is expected to increase capacity by 250 Mdth/d.~~2021.

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

Critical Accounting Estimates

Constitution Pipeline Capitalized Project Costs

As of September 30, ~~2017,~~ 2019, Property, plant, and equipmentinour Consolidated Balance Sheet includes approximately ~~$381~~$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 September 30, 2017,~~ and determined that no impairment was necessary. Our evaluation considered probability-weighted scenarios of undiscounted future net cash flows, including ~~a scenario~~scenarios assuming construction of the pipeline, as well as a scenario where the project does not proceed. It is reasonably possible that future unfavorable developments, such as failure to successfully renegotiate associated customer contracts, increased estimates of construction costs, or further significant delays, could result in a future impairment.

Regulatory Liabilities Resulting from Tax Reform

In December 2017, the Tax 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. 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. As a result, we established regulatory liabilities during 2017 and at September 30, 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 rate proceedings, including other costs of providing service.

Equity-Method Investments

We continue to monitor ~~the capitalized project costs associated with Constitution~~our equity-method investments for ~~potential impairment.~~

~~Property, Plant, and Equipment and Other Identifiable Intangible Assets~~

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

As disclosed in our 2016 Annual Report on Form 10–K and subsequent Quarterly Reports on Form 10–Q, we may monetize assets that are not core to our strategy which could result in impairments of certain equity–method investments, property, plant, and equipment, and intangible assets. Such impairments could potentially be caused by indications of fair value implied through the monetization process or, in the case of asset dispositions that are part of a broader asset group, the impact of the loss of future estimated cash flows.

During the third quarter of 2017, we received solicitations and engaged in negotiations for the sale of certain gas gathering assets within the Mid-Continent region. As a result of these events, we evaluated the Mid-Continent asset group, which includes property, plant, and equipment and intangible assets, for impairment. Our evaluation considered the likelihood of divesting certain assets within the Mid-Continent region as well as information developed from the negotiation process that impacted ouroccurred. We generally estimate of future cash flows associated with these assets. The estimated undiscounted future cash flows were determined to be below the carrying amount for these assets. We computed the estimated fair value using an income approach and incorporated market inputs based on ongoing negotiations for the potential sale of a portion of the underlying assets. For the income approach, we utilized a discount rate of 10.2 percent, reflecting an estimate of our cost of capital and risks associated with the underlying assets. As a result of this evaluation, we recorded an impairment charge of $1.019 billion for the difference between the estimated fair value and carrying amount of these assets.

Judgments and assumptions are inherent in estimating undiscounted future cash flows, fair values, and the probability-weighting of possible outcomes. The use of alternate judgments and assumptions could result in a different determination affecting the consolidated financial statements.

~~Equity-Method Investment in UEOM~~

As of September 30, 2017, the carrying value of our equity-method investment in UEOM is $1.4 billion. During the third quarter of 2017, we became aware of potential changes to the future drilling plans of a certain producer which could delay and/or reduce volumes available for processing at UEOM. As a result, we evaluated this investment for impairment at September 30, 2017, and determined that no impairment was necessary.

~~We estimated~~ the fair value of our ~~investment in UEOM~~investments using an income approach ~~that included probability-weighted scenarios assuming varying levels~~where significant judgments and assumptions include expected future cash flows and the appropriate discount rate. In some cases, we may utilize a form of ~~volume declines, as well as a scenario with less volume degradation as a result~~market approach to estimate the fair value of ~~an assumed sale~~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 ~~the underlying reserves~~Notes to ~~another producer. We utilized a discount rate of 10.8 percent.~~Consolidated Financial Statements.)

Management’s Discussion and Analysis (Continued)

The estimated fair value of our investment in UEOM exceeded its carrying value by more than 10 percent. Judgments and assumptions are inherent in our estimates of future cash flows, discount rates, and scenario probabilities. The use of alternate judgments and assumptions could result in a different calculation of fair value, which could ultimately result in the recognition of an impairment charge in the 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, ~~2017,~~2019, compared to the three and nine months ended September 30, ~~2016.~~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,
	2017			2016			$ Change*	% Change*		2017			2016			$ Change*	% Change*		2019			2018			$ Change*	% Change*		2019			2018			$ Change*	% Change*
	(Millions)									(Millions)									(Millions)									(Millions)
Revenues:
Service revenues	$	1,310		$	1,247		+63	+5	%	$	3,853		$	3,678		+175	+5	%	$	1,495		$	1,371		+124	+9	%	$	4,424		$	4,062		+362	+9	%
Service revenues – commodity consideration																			38			121			-83	-69	%	158			316			-158	-50	%
Product sales	581			658			-77	-12	%	1,950			1,623			+327	+20	%	466			811			-345	-43	%	1,512			2,104			-592	-28	%
Total revenues	1,891			1,905						5,803			5,301						1,999			2,303						6,094			6,482
Costs and expenses:
Product costs	504			461			-43	-9	%	1,620			1,180			-440	-37	%	434			790			+356	+45	%	1,442			2,039			+597	+29	%
Processing commodity expenses																			19			30			+11	+37	%	83			91			+8	+9	%
Operating and maintenance expenses	400			394			-6	-2	%	1,157			1,179			+22	+2	%	364			389			+25	+6	%	1,091			1,134			+43	+4	%
Depreciation and amortization expenses	433			435			+2	—	%	1,308			1,326			+18	+1	%	435			425			-10	-2	%	1,275			1,290			+15	+1	%
Selling, general, and administrative expenses	138			177			+39	+22	%	452			556			+104	+19	%	130			174			+44	+25	%	410			436			+26	+6	%
Gain on sale of Geismar Interest	(1,095		)	—			+1,095	NM		(1,095		)	—			+1,095	NM
Impairment of certain assets	1,210			1			-1,209	NM		1,236			811			-425	-52	%	—			—			—	—		76			66			-10	-15	%
Other (income) expense – net	24			92			+68	+74	%	34			130			+96	+74	%	(11		)	(6		)	+5	+83	%	30			24			-6	-25	%
Total costs and expenses	1,614			1,560						4,712			5,182						1,371			1,802						4,407			5,080
Operating income (loss)	277			345						1,091			119						628			501						1,687			1,402
Equity earnings (losses)	115			104			+11	+11	%	347			302			+45	+15	%	93			105			-12	-11	%	260			279			-19	-7	%
Impairment of equity-method investments	—			—			—	NM		—			(112		)	+112	+100	%
Other investing income (loss) – net	4			28			-24	-86	%	278			64			+214	NM		(107		)	2			-109	NM		(54		)	74			-128	NM
Interest expense	(267		)	(297		)	+30	+10	%	(818		)	(886		)	+68	+8	%	(296		)	(270		)	-26	-10	%	(888		)	(818		)	-70	-9	%
Other income (expense) – net	20			20			—	—	%	115			52			+63	+121	%	1			52			-51	-98	%	19			99			-80	-81	%
Income (loss) before income taxes	149			200						1,013			(461		)				319			390						1,024			1,036
Provision (benefit) for income taxes	24			69			+45	+65	%	126			(74		)	-200	NM		77			190			+113	+59	%	244			297			+53	+18	%
Net income (loss)	125			131						887			(387		)				242			200						780			739
Less: Net income (loss) attributable to noncontrolling interests	92			70			-22	-31	%	400			22			-378	NM		21			71			+50	+70	%	54			323			+269	+83	%
Net income (loss) attributable to The Williams Companies, Inc.	$	33		$	61					$	487		$	(409	)				$	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, ~~2017~~2019 vs. three months ended September 30, ~~2016~~2018

Service revenuesincreased primarily due to higher revenues from the Barnett Shale related to the amortization of deferred revenue associated with the restructuring of contracts in the fourth quarter of 2016, as well as higher volumes primarily associated with Transco’s natural gas transportation fee revenues at Transco associated with expansion projects placed ~~in-service during 2016~~in service in 2019 and ~~2017, partially offset by lower rates~~2018, from UEOM, which is now a consolidated entity after the remaining ownership interest was purchased in March 2019, and from higher volumes at the ~~western region also associated with the fourth quarter 2016 contract restructuring. The increase in~~ ~~Service revenues~~ ~~was also partially offset by lower volumes in most of the Utica Shale and western regions, driven by natural declines.~~

~~Product sales~~ decreased primarily due to lower olefin sales associated with decreased volumes related to the sale of our Geismar Interest in July 2017, our Canadian operations in September 2016, and our RGP Splitter in June 2017. The decrease in ~~Product sales~~ ~~is partially offset by higher marketing sales primarily due to significantly higher prices, partially offset by lower volumes.~~

~~The increase in~~ ~~Product costs~~ ~~is primarily due to the same factors that increased marketing sales, partially offset by lower olefin feedstock and natural gas purchases associated with decreased volumes.~~

~~Operating and maintenance expenses~~ ~~increased primarily due to an increase in Transco pipeline integrity testing and costs, and general maintenance.~~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 decreased primarily due to lower NGL prices, and lower volumes due to the absence of 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 processing services provided. Most of these NGL volumes are sold within the month processed and therefore are offset in Product costs below.

Product salesdecreased primarily due to lower NGL and natural gas prices associated with our marketing and equity NGL sales activities. This decrease also includes lower volumes from our equity NGL sales primarily reflecting the absence of our former ~~Canadian and Gulf Olefins~~Four Corners area operations and ~~ongoing cost containment efforts.~~lower system management gas sales, partially offset by higher marketing volumes. Marketing revenues and system management gas sales are substantially offset in Product costs.

~~Depreciation~~Product costs decreased primarily due to lower NGL and ~~amortization~~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 reflecting the absence of our former Four Corners area operations and lower system management gas costs, partially offset by higher volumes for marketing activities.

Operating and maintenance expenses decreased primarily due to the absence of our former ~~Canadian~~Four Corners area operations and ~~Gulf Olefins operations, offset by new assets placed in-service.~~

~~Selling, general, and administrative expenses~~ ~~decreased primarily~~a decrease in Transco’s contracted services mainly due to the ~~absence~~timing of ~~project development~~required engine overhauls and integrity testing, partially offset by the consolidation of UEOM, and by an accrual for estimated severance and related costs ~~incurred in the third quarter of 2016~~primarily associated with our former Canadian PDH facility, lower strategic alternatives costs, and the absence of costs associated with our former Canadian and Gulf Olefins operations. These decreases were partially offset by higher organizational realignment and severance costs. (Seevoluntary separation program (VSP) (see Note 56 – 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 ~~Gain~~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 ~~sale of Geismar Interest~~ ~~reflects the gain recognized on the sale of our Geismar Interest in July 2017. (See~~asset retirement (see Note 36 – ~~Divestitures~~Other Income and Expenses of Notes to Consolidated Financial ~~Statements.)~~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 ~~Impairment of certain assets~~ ~~reflects the 2017~~Other investing income (loss) – net is primarily due to 2019 impairments ~~of certain gathering operations in the Mid-Continent and Marcellus South regions and certain NGL pipeline assets~~to our equity-method investments, including Laurel Mountain (see Note 1113 – Fair Value Measurements and Guarantees of Notes to Consolidated Financial Statements).

~~The favorable change inOther (income)~~Interest expense ~~– net~~ ~~within~~ ~~Operating income (loss)~~ ~~includes the absence of the 2016 loss on the sale of our Canadian operations, as well as lower product development costs at Constitution.~~

~~Operating income (loss)~~ ~~changed unfavorably~~ increased primarily due to the 2017 impairment of certain gathering operations in the Mid-Continent and Marcellus South regions and lower olefin product margins resulting from the sale of our Geismar Interest and Canadian operations, partially offset by the gain on sale of our Geismar Interest, higher service revenues associated with certain projects placed in-service, and the absence of a 2016 loss on the sale of our Canadian operations.

~~The favorable change in~~ ~~Equity earnings (losses)~~ is due to an increase in ~~ownership of our Appalachian Midstream Investments, partially offset by~~financing obligations associated with Transco’s Atlantic Sunrise project and lower ~~Discovery results~~capitalized interest due to ~~lower fee revenues, and lower UEOM results driven by lower processing volumes from the Utica gathering system.~~

~~Other investing income (loss) – net~~ ~~decreased due to the absence of a 2016 gain on the sale of an equity-method investment interest~~projects placed in ~~a gathering system that was part of our Appalachia Midstream Investments gathering system. (See Note 4 – Investing Activities of Notes to Consolidated Financial Statements.)~~service.

Management’s Discussion and Analysis (Continued)

~~Interest expense~~ ~~decreased~~The unfavorable change in Other income (expense) – net below Operating income (loss) is primarily due to ~~lower~~ ~~Interest incurred~~ ~~primarily attributable to debt retirements~~a decrease in equity AFUDC associated with reduced capital expenditures on projects and ~~lower borrowings on our credit facilities in 2017. (See Note 9 – Debt and Banking Arrangements of Notes to Consolidated Financial Statements.)~~2019 charges for loss contingencies associated with former operations.

Provision (benefit) for income taxes changed favorably primarily due to ~~lower pretax income.~~the absence of a $105 million 2018 valuation allowance on certain deferred tax assets that may not be realized following the WPZ merger, partially offset by higher pre-tax income attributable to The Williams Companies, Inc. See Note 67 – 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 ~~unfavorable~~favorable change in Net income (loss) attributable to noncontrolling interests is primarily due to ~~the impact of decreased income allocated to the WPZ general partner driven by the permanent waiver of IDRs, partially offset by a decrease in the ownership~~our third- quarter 2018 acquisition of the ~~noncontrolling~~publicly held interests ~~and lower operating results at WPZ. Both the permanent waiver of IDRs and the change~~ in ~~ownership are~~WPZ associated with the ~~first-quarter 2017 Financial Repositioning (see Note 1 – General, Description of Business, and Basis of Presentation of Notes to Consolidated Financial Statements).~~WPZ Merger.

Nine months ended September 30, ~~2017~~2019 vs. nine months ended September 30, ~~2016~~2018

Service revenuesincreased ~~due to the recognition of deferred revenue in the Barnett Shale region associated with the restructuring of contracts in the fourth quarter of 2016.~~ ~~Service revenues~~ ~~also increased~~primarily due to higher ~~volumes primarily~~transportation fee revenues at Transco associated with expansion projects placed in service in 2019 and 2018 and the ~~eastern Gulf Coast region, including the impact~~consolidation of new volumes at Gulfstar One related to the Gunflint expansion placed in-service in the third quarter of 2016, the absence of the temporary shut-down of Gulfstar One in the second quarter of 2016 to tie into Gunflint, the absence of producers’ 2016 operational issues in the Tubular Bells field in the first quarter of 2016, andUEOM, as well as higher volumes at ~~Devils Tower related to Kodiak field production. Additionally, Transco experienced~~the Susquehanna Supply Hub, and higher ~~natural gas transportation fee revenues reflecting expansion projects placed in-service~~rates and volumes from new wells in 2016 and 2017, as well as an increase in storage revenues due to the absence of an accrual for potential refunds associated with a ruling received in certain rate case litigation in 2016. These increases were partially offset by lower rates primarily in the Barnett Shale region associated with the previously discussed contract restructure, as well as lower volumes in most of the Utica Shale ~~and western regions driven by natural declines and extreme weather conditions in the Rocky Mountains in 2017.~~ ~~Service revenues~~region. These increases ~~were also~~are partially offset by the absence of revenues associated with asset divestitures and deconsolidations during 2018, including our former ~~Canadian~~Four Corners area operations, and ~~Gulf Olefins operations.~~

~~Product sales~~ ~~increased due to higher marketing revenues primarily~~lower deferred revenue recognition in the Barnett Shale associated with ~~significantly higher prices and volumes. Revenues from~~ the ~~sale~~end of ~~our equity NGLs increased primarily due to higher non-ethane NGL prices, partially offset by lower volumes. These increases were partially offset by lower olefin production sales~~a contractual MVC period.

Service revenues – commodity consideration decreased due to lower ~~volumes resulting from the sale of our former Gulf Olefins~~NGL prices and ~~Canadian operations.~~

~~The increase in~~ ~~Product costs~~ ~~is primarily due to the same factors that increased marketing sales, partially offset by~~ lower ~~olefin feedstock purchases associated with the sale of our Gulf Olefins and Canadian operations.~~

~~Operating and maintenance expenses~~ ~~decreased~~volumes primarily due to the absence of our former Four Corners area operations. These revenues represent consideration we receive in the form of commodities as full or partial payment for processing services provided. Most of these NGL volumes are sold within the month processed and therefore are offset in Product costs below.

Product salesdecreased primarily due to lower NGL and natural gas prices associated with our marketing and equity NGL sales activities and lower volumes from our equity NGL sales primarily reflecting the absence of our former ~~Canadian and Gulf Olefins~~Four Corners area operations and lower ~~labor-related costs resulting from our workforce reductions that occurred late in first-quarter 2016, and ongoing cost containment efforts. These decreases are~~system management gas sales, partially offset by ~~an increase~~higher marketing volumes. Marketing revenues and system management gas sales are substantially offset in ~~pipeline integrity testing on Transco,~~Product costs.

Product costs decreased primarily due to lower NGL and ~~general maintenance.~~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 reflecting the absence of our former Four Corners area operations and lower system management gas costs, partially offset by higher volumes for marketing activities.

~~Depreciation~~Operating and ~~amortization~~maintenance expensesdecreased primarily due to the absence of our former ~~Canadian~~Four Corners area operations, partially offset by the consolidation of UEOM, and ~~Gulf Olefins~~by an accrual for estimated severance and related costs primarily associated with 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 our former 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 ~~certain project development costs~~a charitable contribution of preferred stock to the Williams Foundation, Inc. and fees associated with the ~~Canadian PDH facility that we expensed~~WPZ 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 ~~2016, lower labor-related costs resulting from our workforce reductions that occurred late in~~Impairment of certain assets includes a second-quarter 2019 impairment of certain Eagle Ford Shale gathering assets and a first-quarter ~~2016, ongoing cost containment efforts,~~2019 impairment of certain idle gathering assets, partially offset by the absence of ~~costs associated with our former Canadian operations, as well as lower strategic development costs. These decreases were partially offset by higher severance~~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 on asset retirement, a 2019 charge for the reversal of expenditures previously capitalized, and ~~organizational realignment costs. (See~~net unfavorable

Management’s Discussion and Analysis (Continued)

changes to charges and credits to regulatory assets and liabilities (see Note 56 – Other Income and Expenses of Notes to Consolidated Financial ~~Statements.)~~Statements).

The ~~Gain on sale~~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 favorable impact of ~~Geismar Interest~~ ~~reflects~~acquiring the ~~gain recognized on~~additional interest of UEOM, the ~~sale~~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 ~~Geismar Interest in July 2017. (See Note 3 – Divestitures~~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 ~~Notes to Consolidated Financial Statements.)~~UEOM and the formation of the Northeast JV.

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

The unfavorable change in ~~Impairment of certain assets~~Other investing income (loss) – netreflects ~~2017~~noncash impairments of certain gathering operations in the Mid-Continent and Marcellus South regions, certain NGL pipeline assets, and an olefins pipeline project in the Gulf coast region. These 2017 impairments are partially offset by the absence of 2016 impairments of our former Canadian operations and certain Mid-Continent assetsto equity method investments (see Note 1113 – Fair Value Measurements and Guarantees of Notes to Consolidated Financial Statements).

~~The favorable change in~~ ~~Other (income) expense – net~~ ~~within~~ ~~Operating income (loss)~~ ~~includes the absence of the 2016 loss on the sale of our Canadian operations, gains from certain contract settlements~~ and terminations in 2017, a gain on the sale of our RGP Splitter in 2017, the absence of an unfavorable change in foreign currency exchange associated with our former Canadian operations, insurance proceeds received in 2017 associated with the Geismar Incident, and lower project development costs at Constitution. These favorable changes were partially offset by the accrual of additional expenses in 2017 related to the Geismar Incident, as well as 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 ~~first-quarter 2016~~Jackalope.

Interest expense increased primarily due to an increase in financing obligations associated with ~~the sale of unused pipe.~~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 associated with reduced capital expenditures on projects.

Provision (benefit) for income taxes changed favorably primarily due to the gain on sale of our Geismar Interest, the absence of the 2016 impairments of our former Canadian operations and certain Mid-Continent assets, higher service revenues from expansion projects placed in-service in 2016 and 2017, as well as ongoing cost containment efforts, including workforce reductions in first-quarter 2016. ~~Operating income (loss)~~ ~~also improved due to the~~ absence of a ~~2016 loss~~$105 million 2018 valuation allowance on certain deferred tax assets that may not be realized following the sale of our Canadian operations, the absence of an operating loss associated with our former Canadian operations, gains from certain contract settlements, and the sale of our RGP Splitter. These favorable changes wereWPZ merger, partially offset by ~~a 2017 impairment of certain gathering operations in the Mid-Continent and Marcellus South regions, and certain NGL pipeline assets, as well as the absence of operating~~higher pre-tax income ~~associated with our former Gulf Olefins operations.~~

~~The favorable change in~~ ~~Equity earnings (losses)~~ ~~is due to an increase in ownership of our Appalachian Midstream Investments, improved results at Laurel Mountain Midstream due to higher rates, and improved results at Discovery~~ attributable to ~~the accelerated recognition of previously deferred revenue, partially offset by lower UEOM results driven by lower processing volumes from the Utica gathering system.~~

The ~~decrease in~~ ~~Impairment of equity-method investments~~ reflects the absence of first-quarter 2016 impairment charges associated with our DBJV and Laurel Mountain equity-method investments. (See Note 11 – Fair Value Measurements and Guarantees of Notes to Consolidated Financial Statements.)

~~Other investing income (loss) – net~~ reflects the gain on disposition of our investments in DBJV and Ranch Westex JV LLC in 2017 (see Note 4 – Investing Activities of Notes to Consolidated Financial Statements), partially offset by the absence of interest income received in 2016 associated with a receivable related to the sale of certain former Venezuelan assets and the absence of a 2016 gain on the sale of an equity-method investment interest in a gathering system that was part of our Appalachia Midstream Investments gathering system.

~~Interest expense~~ ~~decreased primarily due to lower~~ ~~Interest incurred~~ primarily attributable to debt retirements and lower borrowings on our credit facilities in the first quarter of 2017. (See Note 9 – Debt and Banking Arrangements of Notes to Consolidated Financial Statements.)

~~Other income (expense) – net~~ ~~below~~ ~~Operating income (loss)~~ changed favorably primarily due to a net gain on early debt retirements in 2017, and favorable changes related to equity funds used during construction (AFUDC). (See Note 5 – Other Income and Expenses of Notes to Consolidated Financial Statements.)

~~Provision (benefit) for income taxes~~ ~~changed unfavorably primarily due to higher pretax income.~~Williams Companies, Inc. See Note 67 – 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 ~~unfavorable~~favorable change in Net income (loss) attributable to noncontrolling interests is primarily due to ~~higher operating results at WPZ, the impact of decreased income allocated to the WPZ general partner driven by the permanent waiver of IDRs, partially offset by a decrease in the ownership~~our third- quarter 2018 acquisition of the ~~noncontrolling interests. Both the permanent waiver of IDRs and the change~~publicly held interests in ~~ownership are~~WPZ associated with the ~~first-quarter 2017 Financial Repositioning (see Note 1 – General, Description of Business,~~WPZ Merger and ~~Basis of Presentation of Notes to Consolidated Financial Statements).~~

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

~~In addition, improved results in our Gulfstar operations also contributed to the unfavorable change in~~ ~~Net income (loss) attributable to noncontrolling interests,~~ ~~partially offset by~~ lower results ~~for our Cardinal gathering system.~~at Gulfstar.

Period-Over-Period Operating Results - Segments

We evaluate segment operating performance based upon Modified EBITDA. Note 1315 – Segment Disclosures of Notes to Consolidated Financial Statements includes a reconciliation of this non-GAAP measure to Net income (loss). Management uses Modified EBITDA because it is an accepted financial indicator used by investors to compare company performance. In addition, management believes that this measure provides investors an enhanced perspective of the operating performance of our assets. Modified EBITDA should not be considered in isolation or as a substitute for a measure of performance prepared in accordance with GAAP.

~~Williams Partners~~

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,
	2017			2016			2017			2016			2019			2018			2019			2018
	(Millions)												(Millions)
Service revenues	$	1,304		$	1,252		$	3,837		$	3,688		$	353		$	247		$	959		$	707
Service revenues – commodity consideration													1			6			9			14
Product sales	581			655			1,950			1,613			30			69			114			242
Segment revenues	1,885			1,907			5,787			5,301			384			322			1,082			963

Product costs	(504		)	(463		)	(1,620		)	(1,183		)	(29		)	(69		)	(114		)	(245		)
Processing commodity expenses													(1		)	(3		)	(6		)	(7		)
Other segment costs and expenses	(536		)	(567		)	(1,520		)	(1,660		)	(117		)	(100		)	(348		)	(279		)
Gain on sale of Geismar Interest	1,095			—			1,095			—
Impairment of certain assets	(1,142		)	(1		)	(1,145		)	(403		)
Proportional Modified EBITDA of equity-method investments	202			194			611			574			108			131			333			354
Williams Partners Modified EBITDA	$	1,000		$	1,070		$	3,208		$	2,629
Northeast G&P Modified EBITDA													$	345		$	281		$	947		$	786

NGL margin	$	46		$	45		$	139		$	119
Olefin margin	2			122			126			267
Commodity margins													$	1		$	3		$	3		$	4

Three months ended September 30, ~~2017~~2019 vs. three months ended September 30, ~~2016~~2018

Northeast G&P Modified EBITDA increased primarily due to higher Service revenues due to increased gathering volumes and the favorable impact of acquiring the additional interest of UEOM, which is a consolidated entity after the remaining ownership interest was purchased in March 2019.

Service revenues increased primarily due to:

Product salesdecreased primarily due to ~~impairments~~lower non-ethane prices and volumes within our marketing activities. The changes in marketing revenues are offset by similar changes in marketing purchases, reflected above as Product costs.

Other segment costs and expenses increased primarily due to expenses associated with the consolidation of ~~certain gathering operations and lower olefin margins~~UEOM.

Proportional Modified EBITDA of equity-method investments decreased primarily due to the ~~sale~~consolidation of UEOM.

Northeast G&P Modified EBITDA increased primarily due to higher Service revenues due to increased gathering volumes and the favorable impact of acquiring the additional interest of UEOM, partially offset by 2019 severance and related costs.

Management’s Discussion and Analysis (Continued)

Service revenues increased primarily due to:

Product sales decreased primarily due to lower non-ethane volumes and prices within our ~~Gulf Olefins (Geismar olefin~~marketing activities. The changes in marketing revenues are offset by similar changes in marketing purchases, reflected above as Product costs.

Other segment costs and ~~RGP Splitter plants) operations~~expenses increased due to multiple factors, including:

Proportional Modified EBITDA of equity-method investments decreased $37 million as a result of the consolidation of UEOM. This decrease was partially offset by a ~~$1.095 billion gain on the sale of our Geismar Interest in third-quarter 2017, the absence of the $32~~$20 million ~~loss on the sale of our former Canadian operations in third-quarter 2016,~~increase at Appalachia Midstream Investments, reflecting higher volumes.



	Three Months Ended September 30,						Nine Months Ended September 30,
	2019			2018			2019			2018
	(Millions)
Service revenues	$	731		$	607		$	2,138		$	1,806
Service revenues – commodity consideration	7			18			33			45
Product sales	76			131			226			329
Segment revenues	814			756			2,397			2,180

Product costs	(75		)	(134		)	(226		)	(332		)
Processing commodity expenses	(2		)	(3		)	(12		)	(10		)
Other segment costs and expenses	(182		)	(176		)	(606		)	(556		)
Proportional Modified EBITDA of equity-method investments	44			49			130			136
Atlantic-Gulf Modified EBITDA	$	599		$	492		$	1,683		$	1,418

Commodity margins	$	6		$	12		$	21		$	32

Management’s Discussion and ~~higher service revenues primarily driven by expansions of our Transco pipeline and our Gulfstar One facilities.~~Analysis (Continued)

~~Service revenues~~

Atlantic-Gulf Modified EBITDAincreased primarily due ~~to:~~to higher Service revenues.

~~A $53 million increase related~~Service revenues increased due to ~~the amortization of deferred revenue associated with the up-front cash payment received in conjunction with the fourth quarter 2016 Barnett Shale contract restructuring;~~

The net sum of Service revenues – commodity consideration, Product sales, Product costs, and Processing commodity expenses comprise our commodity product margins. Our commodity product margins associated with our equity NGLs decreased $7 million driven by unfavorable NGL prices. Additionally, the decrease in Product sales includes a $44 million decrease in commodity marketing sales due to lower NGL prices and volumes. Marketing sales are substantially offset in Product costs and therefore have little impact to Modified EBITDA.

Other segment costs and expenses increased primarily due to a ~~$45~~$23 million ~~increase~~unfavorable change in equity AFUDC due to lower construction activity, an $11 million accrual in 2019 for estimated severance and related costs primarily associated with ~~expansion projects placed in-service~~our VSP (see Note 6 – Other Income and Expenses of Notes to Consolidated Financial Statements), the absence of a $10 million 2018 gain on asset retirements, and higher reimbursable power and storage expenses at Transco. These unfavorable changes were partially offset by $33 million of net favorable changes to charges and credits associated with regulatory assets and liabilities, which were significantly driven by the previously mentioned agreement to the terms of a settlement in ~~2016~~Transco’s general rate case (see Note 6 – Other Income and ~~2017;~~Expenses of Notes to Consolidated Financial Statements), and a $21 million decrease in Transco’s contracted services compared to 2018 mainly due to the timing of required engine overhauls and integrity testing.

Atlantic-Gulf Modified EBITDA increased primarily due to higher Service revenues, partially offset by higher costs and expenses.

Service revenues increased primarily due to a $361 million increase in ~~fee~~Transco’s natural gas transportation revenues ~~in the eastern Gulf Coast region associated~~ primarily ~~with higher volumes, including the impact of new volumes at Gulfstar One from the Gunflint~~driven by a $335 million increase related to expansion projects placed in service in 2018 and 2019, as well as an adjustment associated with Transco’s reserve for rate refunds. Partially offsetting these increases were lower gathering and processing fees of $40 million primarily due to maintenance downtime at Gulfstar and the ~~third~~sale of certain Gulf Coast pipeline assets in the fourth quarter of ~~2016,~~2018. Additionally, certain of Transco’s natural gas transportation revenues, which decreased due to lower rates effective October 2018, were substantially offset by higher revenue related to reimbursable power and storage expenses.

The net sum of Service revenues – commodity consideration, Product sales, Product costs, and Processing commodity expenses comprise our commodity product margins. Our commodity product margins associated with our equity NGLs decreased $12 million driven by unfavorable NGL prices, partially offset by higher volumes. Additionally, the decrease in Product sales includes a $74 million decrease in commodity marketing sales due to lower NGL prices and volumes and an $19 million decrease in system management gas sales. Marketing sales and system management gas sales are substantially offset in Product costs and therefore have little impact to Modified EBITDA.

Other segment costs and expenses increased primarily due a $55 million unfavorable change in equity AFUDC due to lower construction activity, a $30 million accrual in 2019 for estimated severance and related costs primarily associated with our VSP, a $15 million increase in reimbursable power and storage expenses, $15 million of expense in 2019 related to the reversal of expenditures previously capitalized, and the absence of a $10 million 2018 gain on asset retirements. These unfavorable changes were partially offset by $43 million of net favorable changes to charges and credits associated with regulatory assets and liabilities, which were significantly driven by the ~~temporary shutdown and subsequent ramp-up of Gulfstar One in the second and third quarters of 2016 to tie-in Gunflint;~~previously mentioned

Management’s Discussion and Analysis (Continued)

~~A $29 million decrease related to lower gathering rates in the Barnett Shale related~~agreement to the ~~fourth quarter 2016 contract restructuring, along with lower rates recognized~~terms of a settlement in ~~the Niobrara~~Transco’s general rate case, and ~~Eagle Ford Shale regions. Rates recognized in the Niobrara region represent~~ a ~~portion of the total contractual rate, with the difference reflected as deferred revenue;~~

~~A decrease of $15 million~~



	Three Months Ended September 30,						Nine Months Ended September 30,
	2019			2018			2019			2018
	(Millions)
Service revenues	$	433		$	533		$	1,384		$	1,599
Service revenues – commodity consideration	30			97			116			257
Product sales	389			732			1,302			1,822
Segment revenues	852			1,362			2,802			3,678

Product costs	(382		)	(730		)	(1,294		)	(1,813		)
Processing commodity expenses	(13		)	(26		)	(63		)	(76		)
Other segment costs and expenses	(175		)	(219		)	(531		)	(637		)
Impairment of certain assets	—			—			(76		)	—
Proportional Modified EBITDA of equity-method investments	29			25			83			62
West Modified EBITDA	$	311		$	412		$	921		$	1,214

Commodity margins	$	24		$	73		$	61		$	190

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

West Modified EBITDA decreased primarily due to the absence of EBITDA of certain of our former sold or deconsolidated assets, lower service revenues associated with the expiration of a certain MVC, and lower commodity margins due to unfavorable commodity prices related to our ~~former Canadian operations that were sold in September 2016;~~ongoing operations.

~~In the Northeast region, a $10 million increase in fee~~Service revenues in the Susquehanna Supply Hub driven by 10 percent higher gathered volumes reflecting increased customer production, offset by a $10 million decrease in the Utica gathering system associated with 6 percent lower gathered volumes driven by natural declines in the wet gas areas, partially offset by higher volumes from new development in the dry gas areas.

~~Product sales~~ decreased primarily due to:

These decreases were partially offset by a $17 million increase associated with higher other MVC deficiency fee revenues, higher volumes, and higher other fee revenues.

~~A $142 million increase in marketing revenues primarily due to significantly higher prices~~

Management’s Discussion and ~~NGL volumes, partially offset by lower crude, natural gas, and propylene volumes (offset in marketing purchases).~~Analysis (Continued)

~~Product costs~~ ~~increased primarily due to:~~

Additionally, the ~~production of equity NGLs reflecting~~decrease in Product sales includes a $263 million decrease in marketing sales, which is due to lower ~~volumes as previously discussed,~~sales prices, partially offset by higher sales volumes, a ~~slight increase~~$14 million decrease related to the sale of other products, and a $7 million decrease in ~~per-unit natural~~system management gas ~~prices.~~sales. These decreases are substantially offset in Product costs. Marketing margins decreased by $12 million primarily due to unfavorable changes in pricing.

~~The favorable change in~~ Other segment costs and expenses ~~includes~~ decreased primarily due a $37 million reduction associated with the absence of our former Four Corners area assets and the absence of a 2018 unfavorable charge of $12 million for a regulatory liability associated with a decrease in Northwest Pipeline’s estimated deferred state income tax rate following the WPZ Merger.

Proportional Modified EBITDA of equity-method investments increased primarily due to the addition of the RMM equity-method investment during the third quarter of 2018, partially offset by the absence of the ~~$32 million loss on~~Jackalope equity-method investment sold in April 2019.

Nine months ended September 30, 2019 vs. Nine months ended September 30, 2018

West Modified EBITDA decreased primarily due to the ~~sale~~absence of EBITDA of certain of our former ~~Canadian~~sold or deconsolidated assets, 2019 impairments of certain assets, lower commodity margins due to unfavorable commodity prices and lower volumes associated with equity NGL production related to our ongoing operations, and lower service revenues associated with the expiration of a certain MVC.

Service revenues decreased primarily due to:

~~Gain on sale of Geismar Interest~~ ~~reflects the gain recognized on the sale of our Geismar Interest in July 2017. (See Note 3 – Divestitures of Notes to Consolidated Financial Statements.)~~

~~Impairment of certain assets~~ ~~increased~~17 percent lower ethane sales volumes primarily due to ~~a $1.019 billion impairment of certain gathering operations~~well freeze-offs and temporary shut-ins associated with more severe weather conditions in ~~the Mid-Continent region, a $115 million impairment of certain gathering operations in the Marcellus South region,~~first-quarter 2019, natural declines, and ethane rejection;

Management’s Discussion and Analysis (Continued)

Additionally, the decrease in Product sales includes a $332 million decrease in marketing sales, which is due to lower sales prices, partially offset by higher sales volumes, a $31 million decrease related to the sale of other products, and a $26 million decrease in system management gas sales. These decreases are substantially offset in Product costs. Marketing margins decreased by $15 million primarily due to unfavorable changes in pricing.

Other segment costs and expenses decreased primarily due to a $124 million reduction associated with the absences of our former Four Corners area assets and from the Jackalope deconsolidation in second-quarter 2018, as well as the absence of a 2018 unfavorable charge of $12 million for a regulatory liability associated with a decrease in Northwest Pipeline’s estimated deferred state income tax rate following the WPZ Merger as previously discussed. These decreases were partially offset by an unfavorable accrual in 2019 for estimated severance and related costs of $16 million primarily associated with our VSP (see Note 6 – Other Income and Expensesof Notes to Consolidated Financial Statements) and the absence of a $7 million favorable adjustment to the regulatory liability associated with Tax Reform at Northwest Pipeline in first-quarter 2018.

Impairment of certain assets ~~that are no longer~~ increased primarily due to the $59 million impairment of certain Eagle Ford Shale gathering assets and a $12 million impairment of certain idle gathering assets in ~~use or are surplus in nature. (See~~2019 (see Note 1113 – Fair Value Measurements and Guarantees of Notes to Consolidated Financial ~~Statements.)~~Statements).

~~The increase in~~ Proportional Modified EBITDA of equity-method investments ~~includes a $31 million increase at Appalachian Midstream Investments reflecting our~~ increased ~~ownership and higher gathering volumes reflecting the absence of shut-in volumes from 2016 and increased customer production. This increase is partially offset by a $9 million decrease from Discovery~~ primarily due to ~~production issues on certain wells~~the additions of the RMM and temporary hurricane related shut-ins, an $8 million decrease at UEOM driven by lower processing volumes from the Utica gathering system, as noted above, and the divestiture of our interests in DBJV and Ranch Westex JV LLC lateBrazos Permian II equity-method investments in the ~~first quarter~~second half of ~~2017.~~2018.



	Three Months Ended September 30,					Nine Months Ended September 30,
	2019			2018		2019		2018
	(Millions)
Other Modified EBITDA	$	(2	)	$	6	$	1	$	(49	)

Three months ended September 30, ~~2017~~2019 vs. ~~nine~~three months ended September 30, ~~2016~~2018

Other Modified EBITDA~~increased~~ decreased primarily due to a $1.095 billion gain on the sale of our Geismar Interest in third-quarter 2017, the absence of impairments of our Canadian operations and certain gathering assets in the Mid-Continent region in the second quarter of 2016, theto:

~~Service revenues~~ ~~increased primarily due to:~~2018;

These decreases were partially offset by:

Management’s Discussion and Analysis (Continued)

million increase in gathering fee revenue at Susquehanna Supply Hub driven by 12 percent higher gathered volumes reflecting increased customer production, and a $22 million increase in fee revenue at Ohio Valley Midstream reflecting the absence of shut-in volumes from the first half of 2016, as well as new production coming online.Nine months ended September 30, 2019 vs. nine months ended September 30, 2018

~~Product sales~~Other Modified EBITDA increased primarily due to:



		Page
Part I. Financial Information
Item 1. Financial Statements
Consolidated Statement of ~~Operations~~Income – Three and Nine Months Ended September 30, ~~2017~~2019 and ~~2016~~2018		6
Consolidated Statement of Comprehensive Income ~~(Loss)~~ – Three and Nine Months Ended September 30, ~~2017~~2019 and ~~2016~~2018		7
Consolidated Balance Sheet – September 30, ~~2017~~2019 and December 31, ~~2016~~2018		8
Consolidated Statement of Changes in Equity – Three and Nine Months Ended September 30, ~~2017~~2019 and 2018		9
Consolidated Statement of Cash Flows – Nine Months Ended September 30, ~~2017~~2019 and ~~2016~~		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		3740
Item 3. Quantitative and Qualitative Disclosures About Market Risk		61
Item 4. Controls and Procedures		61
Part II. Other Information		61
Item 1. Legal Proceedings		61
Item ~~6. Exhibits~~1A. Risk Factors		63
Item 6. Exhibits		64



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


(1)	In managing our available liquidity, we do not expect a maximum outstanding amount in excess of the capacity of ~~WPZ’s~~our credit facility inclusive of any outstanding amounts under ~~its~~our commercial paper program.



	Cash Flow Hedges			Foreign Currency Translation			Pension and Other Post Retirement Benefits			Total
	(Millions)
Balance at December 31, 2016	$	—		$	(2	)	$	(337	)	$	(339	)
Other comprehensive income (loss) before reclassifications	(3		)	—			—			(3		)
Amounts reclassified from accumulated other comprehensive income (loss)	—			—			11			11
Other comprehensive income (loss)	(3		)	—			11			8
Balance at September 30, 2017	$	(3	)	$	(2	)	$	(326	)	$	(331	)


(2)	Relates to certain gathering operations in the Marcellus South region resulting from an anticipated decline in future volumes following a third-quarter 2017 shut-in by the primary producer. The estimated fair value was


~~(3)~~	Relates to an NGL pipeline near the Houston Ship Channel region which we anticipate will be underutilized for the foreseeable future. The estimated fair value was primarily determined by using a market approach based on our analysis Reflects impairment of ~~observable inputs in the principal market.~~


~~(6)~~	~~Relates to certain gathering assets within the Mid-Continent region. The estimated fair value was determined by a market approach based on our analysis of observable inputs in the principal market.~~


~~(7)~~	~~Reflects multiple individually insignificant impairments and write-downs of other certain assets~~– net that ~~may~~is no longer be in use ~~or are surplus in nature~~ for which the fair value was determined to be lower than the carrying value.



	Williams Partners		Other		Eliminations			Total
	(Millions)
Three Months Ended September 30, 2017
Segment revenues:
Service revenues
External	$	1,304	$	6	$	—		$	1,310
Internal	—		2		(2		)	—
Total service revenues	1,304		8		(2		)	1,310
Product sales
External	581		—		—			581
Internal	—		—		—			—
Total product sales	581		—		—			581
Total revenues	$	1,885	$	8	$	(2	)	$	1,891

Three Months Ended September 30, 2016
Segment revenues:
Service revenues
External	$	1,241	$	6	$	—		$	1,247
Internal	11		3		(14		)	—
Total service revenues	1,252		9		(14		)	1,247
Product sales
External	655		3		—			658
Internal	—		6		(6		)	—
Total product sales	655		9		(6		)	658
Total revenues	$	1,907	$	18	$	(20	)	$	1,905

Nine Months Ended September 30, 2017
Segment revenues:
Service revenues
External	$	3,836	$	17	$	—		$	3,853
Internal	1		8		(9		)	—
Total service revenues	3,837		25		(9		)	3,853
Product sales
External	1,950		—		—			1,950
Internal	—		—		—			—
Total product sales	1,950		—		—			1,950
Total revenues	$	5,787	$	25	$	(9	)	$	5,803

Nine Months Ended September 30, 2016
Segment revenues:
Service revenues
External	$	3,656	$	22	$	—		$	3,678
Internal	32		17		(49		)	—
Total service revenues	3,688		39		(49		)	3,678
Product sales
External	1,613		10		—			1,623
Internal	—		16		(16		)	—
Total product sales	1,613		26		(16		)	1,623
Total revenues	$	5,301	$	65	$	(65	)	$	5,301

September 30, 2017
Total assets	$	45,635	$	570	$	(85	)	$	46,120
December 31, 2016
Total assets	$	46,265	$	685	$	(115	)	$	46,835



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

Uses:
	Working capital requirements	ü	ü
	Capital and investment expenditures	ü
	~~Investment in WPZ~~		ü
	~~Quarterly distributions to unitholders~~	ü
	Quarterly dividends to our shareholders		ü
	Debt service payments, including payments of long-term debt
	ü	üDistributions to noncontrolling interests


	September 30, 2017
Available Liquidity	WPZ		WMB		Total		September 30, 2019
	(Millions)						(Millions)
Cash and cash equivalents	$	1,165	$	7	$	1,172	$	247
Capacity available under our $1.5 billion credit facility (1)			1,100		1,100
Capacity available to WPZ under its $3.5 billion credit facility, less amounts outstanding under its $3 billion commercial paper program (2)	3,500				3,500
Capacity available under our $4.5 billion credit facility, less amounts outstanding under our $4 billion commercial paper program (1)							4,500
	$	4,665	$	1,107	$	5,772	$	4,747


(1)	Through September 30, 2017, the highest amount outstanding under our credit facility during 2017 was $805 million. At September 30, 2017, we were in compliance with the financial covenants associated with this credit facility. Borrowing capacity available under this facility as of October 31, 2017, was $1.125 billion.



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

~~WPZ:~~	S&P Global Ratings	Stable	BBB	BBB
	Moody’s Investors Service	~~Positive~~Stable	Baa3	N/A
	Fitch Ratings	Rating Watch Positive	BBB-	N/A



	Cash Flow	Nine Months Ended September 30,
	Category	2017			2016
		(Millions)
Sources of cash and cash equivalents:
Operating activities – net	Operating	$	1,837		$	2,097
Proceeds from equity offerings	Financing	2,130			8
Proceeds from sale of businesses, net of cash divested (see Note 3)	Investing	2,056			712
Proceeds from long-term debt (see Note 9)	Financing	1,698			998
Proceeds from our credit-facility borrowings	Financing	1,315			2,045
Distributions from unconsolidated affiliates in excess of cumulative earnings	Investing	394			341
Proceeds from dispositions of equity-method investments (see Note 4)	Investing	200			—
Proceeds from WPZ’s credit-facility borrowings	Financing	—			2,665

Uses of cash and cash equivalents:
Payments of long-term debt (see Note 9)	Financing	(3,785		)	(375		)
Capital expenditures	Investing	(1,700		)	(1,577		)
Payments on our credit-facility borrowings	Financing	(1,690		)	(1,845		)
Quarterly dividends on common stock	Financing	(744		)	(1,111		)
Dividends and distributions to noncontrolling interests	Financing	(636		)	(715		)
Purchases of and contributions to equity-method investments	Investing	(103		)	(132		)
Payments of WPZ’s commercial paper – net	Financing	(93		)	(499		)
Payments on WPZ’s credit-facility borrowings	Financing	—			(2,745		)
Contribution to Gulfstream for repayment of debt	Financing	—			(148		)

Other sources / (uses) – net	Financing and Investing	123			258
Increase (decrease) in cash and cash equivalents		$	1,002		$	(23	)



Exhibit No.		Description

2.1+	—	Agreement and Plan of Merger dated as of May ~~12, 2015,~~16, 2018, by and among The Williams Companies, Inc., SCMS LLC, Williams Partners L.P., and WPZ GP LLC (filed on May ~~13, 2015~~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).
~~10.1~~	—	Termination Agreement and Release, dated as of September 28, 2015, by and among The Williams Companies, Inc., SCMS LLC, Williams Partners L.P. and WPZ GP LLC (filed on September 28, 2015 as Exhibit 10.1 to Williams Partners L.P.’s current report on Form 8-K (File No. 001-34831) and incorporated herein by reference).
12*	—	~~Computation of Ratio of Earnings to Fixed Charges.~~
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.



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

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)