UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)


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

For the quarterly period ended ~~September 30, 2020~~March 31, 2021


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

For the transition period from _____________ to _____________

Commission file number 1-4174

THE WILLIAMS COMPANIES, INC.


(Exact name of registrant as specified in its charter)


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

One Williams Center
Tulsa	Oklahoma	74172-0172
(Address of principal executive offices)		(Zip Code)

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

NO CHANGE

(Former name, former address and former fiscal year, if changed since last report)

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. Yes ☑ No ☐

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted 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 such files). Yes ☑ 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 filer

☑

Accelerated filer

☐

Non-accelerated filer

☐

Smaller reporting company

☐

Emerging growth 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 ☐ No ☑

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~~April 29, ~~2020~~2021
Common Stock, $1.00 par value						~~1,213,585,717~~1,214,762,352

The Williams Companies, Inc.

Index


						Page
Part I. Financial Information
Item 1. Financial Statements
Consolidated Statement of ~~Income~~Operations – Three ~~and Nine~~ Months Ended ~~September 30,~~March 31, 2021 and 2020 ~~and 2019~~						6
Consolidated Statement of Comprehensive Income (Loss) – Three ~~and Nine~~ Months Ended ~~September 30,~~March 31, 2021 and 2020 ~~and 2019~~						7
Consolidated Balance Sheet – ~~September 30, 2020~~March 31, 2021 and December 31, ~~2019~~2020						8
Consolidated Statement of Changes in Equity – Three ~~and Nine~~ Months Ended ~~September 30,~~March 31, 2021 an d 2020 ~~and 2019~~						9
Consolidated Statement of Cash Flows – ~~Nine~~Three Months Ended ~~September 30,~~March 31, 2021 and 2020 ~~and 2019~~						1110
Notes to Consolidated Financial Statements						1211
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations						3630
Item 3. Quantitative and Qualitative Disclosures About Market Risk						5642
Item 4. Controls and Procedures						5642
Part II. Other Information						5642
Item 1. Legal Proceedings						5642
Item 1A. Risk Factors						5743

Item 5. Other Information						43
Item 6. Exhibits						5845

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, outcomes 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:

•Levels of dividends to Williams stockholders;

•Future credit ratings of Williams and its affiliates;

•Amounts and nature of future capital expenditures;

•Expansion and growth of our business and operations;

•Expected in-service dates for capital projects;

•Financial condition and liquidity;

•Business strategy;

•Cash flow from operations or results of operations;

•Seasonality of certain business components;

•Natural gas, natural gas liquids, and crude oil prices, supply, and demand;

•Demand for our services;

•The impact of the ~~novel~~ coronavirus (COVID-19) pandemic.

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:

•Availability of supplies, market demand, and volatility of prices;

•Development and rate of adoption of alternative energy sources;

•The impact of existing and future laws and regulations, the regulatory environment, environmental ~~liabilities,~~matters, and litigation, as well as our ability to obtain necessary permits and approvals, and achieve favorable rate proceeding outcomes;

•Our exposure to the credit risk of our customers and counterparties;

•Our ability to acquire new businesses and assets and successfully integrate those operations and assets into existing businesses as well as successfully expand our facilities, and to consummate asset sales on acceptable terms;

•Whether we are able to successfully identify, evaluate, and timely execute our capital projects and investment opportunities;

•The strength and financial resources of our competitors and the effects of competition;

•The amount of cash distributions from and capital requirements of our investments and joint ventures in which we participate;

•Whether we will be able to effectively execute our financing plan;

•Increasing scrutiny and changing expectations from stakeholders with respect to our environmental, social, and governance practices;

•The physical and financial risks associated with climate change;

•The impacts of operational and developmental hazards and unforeseen interruptions;

•The risks resulting from outbreaks or other public health crises, including COVID-19;

•Risks associated with weather and natural phenomena, including climate conditions and physical damage to our facilities;

•Acts of terrorism, cybersecurity incidents, and related disruptions;

•Our costs and funding obligations for defined benefit pension plans and other postretirement benefit plans;

•Changes in maintenance and construction costs, as well as our ability to obtain sufficient construction-related inputs, including skilled labor;

•Inflation, interest rates, and general economic conditions (including future disruptions and volatility in the global credit markets and the impact of these events on customers and suppliers);

•Risks related to financing, including restrictions stemming from debt agreements, future changes in credit ratings as determined by nationally recognized credit rating agencies, and the availability and cost of capital;

•The ability of the members of the Organization of Petroleum Exporting Countries (OPEC) and other oil exporting nations to agree to and maintain oil price and production controls and the impact on domestic production;

•Changes in the current geopolitical situation;

•Changes in U.S. governmental administration and policies;

•Whether we are able to pay current and expected levels of dividends;

•Additional risks described in our filings with the Securities and Exchange Commission (SEC).

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 for the year ended December 31, ~~2019,~~2020, as filed with the SEC on February 24, ~~2020, as supplemented by the disclosures in Part II, Item 1A. in our Quarterly Report on Form 10-Q for the quarter ended March 31, 2020.~~2021.

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

Mbbls/d: One thousand barrels per day

Bcf: One billion cubic feet of natural gas

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

MMcf/d: One million cubic feet per day

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

Tbtu: One trillion British thermal units

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:

Caiman II: Caiman Energy II, LLC, (renamed Blue Racer Midstream Holdings, LLC, effective February 2, 2021) a former equity-method investment which is a consolidated entity following our November 2020 acquisition of an additional ownership interest

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

Gulfstar One: Gulfstar One LLC

Northwest Pipeline: Northwest Pipeline LLC

Transco: Transcontinental Gas Pipe Line Company, LLC

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

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

Partially Owned Entities: Entities in which we do not own a 100 percent ownership interest and which, as of ~~September 30, 2020,~~March 31, 2021, we account for as equity-method investments, including principally the following:

Aux Sable: Aux Sable Liquid Products LP

~~Caiman II:~~Blue Racer: ~~Caiman Energy II,~~Blue Racer Midstream LLC

Discovery: Discovery Producer Services LLC

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

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

Laurel Mountain: Laurel Mountain Midstream, LLC

OPPL: Overland Pass Pipeline Company LLC

RMM: Rocky Mountain Midstream Holdings LLC

Targa Train 7: Targa Train 7 LLC

Government and Regulatory:

EPA: Environmental Protection Agency

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

FERC: Federal Energy Regulatory Commission

IRS: Internal Revenue Service

SEC: Securities and Exchange Commission

Other:

EBITDA: Earnings before interest, taxes, depreciation, and amortization

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

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

MVC: Minimum volume ~~commitment~~commitments

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, transportation, and fractionation

PART I – FINANCIAL INFORMATION

Item 1. Financial Statements

The Williams Companies, Inc.

Consolidated Statement of ~~Income~~Operations

(Unaudited)


		Three Months Ended September 30,				Nine Months Ended September 30,					Three Months Ended March 31,
		2020		2019		2020		2019				2021		2020
		(Millions, except per-share amounts)										(Millions, except per-share amounts)
Revenues:	Revenues:									Revenues:
Service revenues	Service revenues	$	1,479	$	1,495	$	4,399	$	4,424	Service revenues		$	1,452	$	1,474
Service revenues – commodity consideration	Service revenues – commodity consideration	40		38		93		158		Service revenues – commodity consideration		49		28
Product sales	Product sales	414		466		1,135		1,512		Product sales		1,111		411
Total revenues	Total revenues	1,933		1,999		5,627		6,094		Total revenues		2,612		1,913
Costs and expenses:	Costs and expenses:									Costs and expenses:
Product costs	Product costs	380		434		1,047		1,442		Product costs		932		396
Processing commodity expenses	Processing commodity expenses	21		19		49		83		Processing commodity expenses		21		13
Operating and maintenance expenses	Operating and maintenance expenses	336		364		993		1,091		Operating and maintenance expenses		360		337
Depreciation and amortization expenses	Depreciation and amortization expenses	426		435		1,285		1,275		Depreciation and amortization expenses		438		429
Selling, general, and administrative expenses	Selling, general, and administrative expenses	114		130		354		410		Selling, general, and administrative expenses		123		113
Impairment of certain assets (Note 12)		0		0		0		76
Impairment of goodwill (Note 12)		0		0		187		0

Impairment of goodwill (Note 10)										Impairment of goodwill (Note 10)		0		187
Other (income) expense – net	Other (income) expense – net	15		(11)		28		30		Other (income) expense – net		(1)		7
Total costs and expenses	Total costs and expenses	1,292		1,371		3,943		4,407		Total costs and expenses		1,873		1,482
Operating income (loss)	Operating income (loss)	641		628		1,684		1,687		Operating income (loss)		739		431
Equity earnings (losses) (Note 5)		106		93		236		260
Impairment of equity-method investments (Note 12)		0		(114)		(938)		(186)
Other investing income (loss) – net (Note 5)		2		7		6		132
Equity earnings (losses) (Note 4)										Equity earnings (losses) (Note 4)		131		22
Impairment of equity-method investments (Note 10)										Impairment of equity-method investments (Note 10)		0		(938)
Other investing income (loss) – net										Other investing income (loss) – net		2		3
Interest incurred	Interest incurred	(298)		(303)		(898)		(915)		Interest incurred		(296)		(301)
Interest capitalized	Interest capitalized	6		7		16		27		Interest capitalized		2		5
Other income (expense) – net	Other income (expense) – net	(23)		1		(14)		19		Other income (expense) – net		(2)		4
Income (loss) before income taxes	Income (loss) before income taxes	434		319		92		1,024		Income (loss) before income taxes		576		(774)
Provision (benefit) for income taxes		111		77		24		244
Less: Provision (benefit) for income taxes										Less: Provision (benefit) for income taxes		141		(204)

Net income (loss)	Net income (loss)	323		242		68		780		Net income (loss)		435		(570)
Less: Net income (loss) attributable to noncontrolling interests	Less: Net income (loss) attributable to noncontrolling interests	14		21		(27)		54		Less: Net income (loss) attributable to noncontrolling interests		9		(53)
Net income (loss) attributable to The Williams Companies, Inc.	Net income (loss) attributable to The Williams Companies, Inc.	309		221		95		726		Net income (loss) attributable to The Williams Companies, Inc.		426		(517)
Preferred stock dividends		1		1		2		2
Less: Preferred stock dividends										Less: Preferred stock dividends		1		1
Net income (loss) available to common stockholders	Net income (loss) available to common stockholders	$	308	$	220	$	93	$	724	Net income (loss) available to common stockholders		$	425	$	(518)

Basic earnings (loss) per common share:	Basic earnings (loss) per common share:									Basic earnings (loss) per common share:

Net income (loss)	Net income (loss)	$	.25	$	.18	$	.08	$	.60	Net income (loss)		$	.35	$	(.43)
Weighted-average shares (thousands)	Weighted-average shares (thousands)	1,213,912		1,212,270		1,213,512		1,211,938		Weighted-average shares (thousands)		1,214,646		1,213,019
Diluted earnings (loss) per common share:	Diluted earnings (loss) per common share:									Diluted earnings (loss) per common share:

Net income (loss)	Net income (loss)	$	.25	$	.18	$	.08	$	.60	Net income (loss)		$	.35	$	(.43)
Weighted-average shares (thousands)	Weighted-average shares (thousands)	1,215,335		1,214,165		1,214,757		1,213,943		Weighted-average shares (thousands)		1,217,211		1,213,019

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 March 31,
		2020		2019		2020		2019				2021		2020
		(Millions)										(Millions)
Net income (loss)	Net income (loss)	$	323	$	242	$	68	$	780	Net income (loss)		$	435	$	(570)
Other comprehensive income (loss):	Other comprehensive income (loss):									Other comprehensive income (loss):

Cash flow hedging activities:										Cash flow hedging activities:
Net unrealized gain (loss) from derivative instruments, net of taxes of $2 in 2021 and $0 in 2020										Net unrealized gain (loss) from derivative instruments, net of taxes of $2 in 2021 and $0 in 2020		(9)		0
Reclassifications into earnings of net derivative instruments (gain) loss, net of taxes of $0 in 2021 and $0 in 2020										Reclassifications into earnings of net derivative instruments (gain) loss, net of taxes of $0 in 2021 and $0 in 2020		2		0

Pension and other postretirement benefits:	Pension and other postretirement benefits:									Pension and other postretirement benefits:

Net actuarial gain (loss) arising during the year, net of taxes of ($4) and ($7) in 2020 and $1 and $1 in 2019		11		(5)		20		(5)
Amortization of actuarial (gain) loss and net actuarial loss from settlements included in net periodic benefit cost (credit), net of taxes of ($1) and ($6) in 2020 and $0 and ($3) in 2019		5		4		19		9
Net actuarial gain (loss) arising during the year, net of taxes of $0 in 2021 and $4 in 2020										Net actuarial gain (loss) arising during the year, net of taxes of $0 in 2021 and $4 in 2020		0		(14)
Amortization of actuarial (gain) loss and net actuarial loss from settlements included in net periodic benefit cost (credit), net of taxes of ($1) in 2021 and ($2) in 2020										Amortization of actuarial (gain) loss and net actuarial loss from settlements included in net periodic benefit cost (credit), net of taxes of ($1) in 2021 and ($2) in 2020		3		8
Other comprehensive income (loss)	Other comprehensive income (loss)	16		(1)		39		4		Other comprehensive income (loss)		(4)		(6)
Comprehensive income (loss)	Comprehensive income (loss)	339		241		107		784		Comprehensive income (loss)		431		(576)
Less: Comprehensive income (loss) attributable to noncontrolling interests	Less: Comprehensive income (loss) attributable to noncontrolling interests	14		21		(27)		54		Less: Comprehensive income (loss) attributable to noncontrolling interests		9		(53)
Comprehensive income (loss) attributable to The Williams Companies, Inc.	Comprehensive income (loss) attributable to The Williams Companies, Inc.	$	325	$	220	$	134	$	730	Comprehensive income (loss) attributable to The Williams Companies, Inc.		$	422	$	(523)

See accompanying notes.

The Williams Companies, Inc.

Consolidated Balance Sheet

(Unaudited)


		September 30, 2020		December 31, 2019			March 31, 2021		December 31, 2020
		(Millions, except per-share amounts)					(Millions, except per-share amounts)
ASSETS	ASSETS					ASSETS
Current assets:	Current assets:					Current assets:
Cash and cash equivalents	Cash and cash equivalents	$	70	$	289	Cash and cash equivalents	$	1,126	$	142
Trade accounts and other receivables	Trade accounts and other receivables	1,021		1,002		Trade accounts and other receivables	1,059		1,000
Allowance for doubtful accounts	Allowance for doubtful accounts	(10)		(6)		Allowance for doubtful accounts	(1)		(1)
Trade accounts and other receivables – net	Trade accounts and other receivables – net	1,011		996		Trade accounts and other receivables – net	1,058		999
Inventories	Inventories	157		125		Inventories	144		136

Other current assets and deferred charges	Other current assets and deferred charges	165		170		Other current assets and deferred charges	169		152
Total current assets	Total current assets	1,403		1,580		Total current assets	2,497		1,429
Investments	Investments	5,176		6,235		Investments	5,129		5,159
Property, plant, and equipment	Property, plant, and equipment	42,384		41,510		Property, plant, and equipment	42,970		42,489
Accumulated depreciation and amortization	Accumulated depreciation and amortization	(13,277)		(12,310)		Accumulated depreciation and amortization	(13,894)		(13,560)
Property, plant, and equipment – net	Property, plant, and equipment – net	29,107		29,200		Property, plant, and equipment – net	29,076		28,929
Intangible assets – net of accumulated amortization	Intangible assets – net of accumulated amortization	7,531		7,959		Intangible assets – net of accumulated amortization	7,362		7,444
Regulatory assets, deferred charges, and other	Regulatory assets, deferred charges, and other	1,103		1,066		Regulatory assets, deferred charges, and other	1,198		1,204
Total assets	Total assets	$	44,320	$	46,040	Total assets	$	45,262	$	44,165
LIABILITIES AND EQUITY	LIABILITIES AND EQUITY					LIABILITIES AND EQUITY
Current liabilities:	Current liabilities:					Current liabilities:
Accounts payable	Accounts payable	$	464	$	552	Accounts payable	$	538	$	482

Accrued liabilities	Accrued liabilities	965		1,276		Accrued liabilities	855		944
Commercial paper		40		0

Long-term debt due within one year	Long-term debt due within one year	392		2,140		Long-term debt due within one year	2,142		893
Total current liabilities	Total current liabilities	1,861		3,968		Total current liabilities	3,535		2,319
Long-term debt	Long-term debt	21,951		20,148		Long-term debt	21,092		21,451
Deferred income tax liabilities	Deferred income tax liabilities	1,846		1,782		Deferred income tax liabilities	2,065		1,923
Regulatory liabilities, deferred income, and other	Regulatory liabilities, deferred income, and other	3,764		3,778		Regulatory liabilities, deferred income, and other	4,097		3,889
Contingent liabilities (Note 13)
Contingent liabilities (Note 11)						Contingent liabilities (Note 11)	0		0
Equity:	Equity:					Equity:
Stockholders’ equity:	Stockholders’ equity:					Stockholders’ equity:
Preferred stock	Preferred stock	35		35		Preferred stock	35		35
Common stock ($1 par value; 1,470 million shares authorized at September 30, 2020 and December 31, 2019; 1,248 million shares issued at September 30, 2020 and 1,247 million shares issued at December 31, 2019)		1,248		1,247
Common stock ($1 par value; 1,470 million shares authorized at March 31, 2021 and December 31, 2020; 1,249 million shares issued at March 31, 2021 and 1,248 million shares issued at December 31, 2020)						Common stock ($1 par value; 1,470 million shares authorized at March 31, 2021 and December 31, 2020; 1,249 million shares issued at March 31, 2021 and 1,248 million shares issued at December 31, 2020)	1,249		1,248
Capital in excess of par value	Capital in excess of par value	24,359		24,323		Capital in excess of par value	24,384		24,371
Retained deficit	Retained deficit	(12,376)		(11,002)		Retained deficit	(12,825)		(12,748)
Accumulated other comprehensive income (loss)	Accumulated other comprehensive income (loss)	(160)		(199)		Accumulated other comprehensive income (loss)	(100)		(96)
Treasury stock, at cost (35 million shares of common stock)	Treasury stock, at cost (35 million shares of common stock)	(1,041)		(1,041)		Treasury stock, at cost (35 million shares of common stock)	(1,041)		(1,041)
Total stockholders’ equity	Total stockholders’ equity	12,065		13,363		Total stockholders’ equity	11,702		11,769
Noncontrolling interests in consolidated subsidiaries	Noncontrolling interests in consolidated subsidiaries	2,833		3,001		Noncontrolling interests in consolidated subsidiaries	2,771		2,814
Total equity	Total equity	14,898		16,364		Total equity	14,473		14,583
Total liabilities and equity	Total liabilities and equity	$	44,320	$	46,040	Total liabilities and equity	$	45,262	$	44,165

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, 2020 $ 35 $ 1,248 $ 24,343 $ (12,197) $ (176) $ (1,041) $ 12,212 $ 2,868 $ 15,080
Net income (loss) 0 0 0 309 0 0 309 14 323
Other comprehensive income (loss) 0 0 0 0 16 0 16 0 16
Cash dividends – common stock ($0.40 per share)
0 0 0 (485) 0 0 (485) 0 (485)
Dividends and distributions to noncontrolling interests 0 0 0 0 0 0 0 (49) (49)
Stock-based compensation and related common stock issuances, net of tax 0 0 16 0 0 0 16 0 16
Contributions from noncontrolling interests 0 0 0 0 0 0 0 1 1
Other 0 0 0 (3) 0 0 (3) (1) (4)
Net increase (decrease) in equity 0 0 16 (179) 16 0 (147) (35) (182)
Balance – September 30, 2020 $ 35 $ 1,248 $ 24,359 $ (12,376) $ (160) $ (1,041) $ 12,065 $ 2,833 $ 14,898

Balance – June 30, 2019 $ 35 $ 1,246 $ 24,296 $ (10,423) $ (265) $ (1,041) $ 13,848 $ 3,233 $ 17,081
Net income (loss) 0 0 0 221 0 0 221 21 242
Other comprehensive income (loss) 0 0 0 0 (1) 0 (1) 0 (1)
Cash dividends – common stock ($0.38 per share)
0 0 0 (461) 0 0 (461) 0 (461)
Dividends and distributions to noncontrolling interests 0 0 0 0 0 0 0 (18) (18)
Stock-based compensation and related common stock issuances, net of tax 0 1 16 0 0 0 17 0 17
Changes in ownership of consolidated subsidiaries, net (Note 2) 0 0 (1) 0 0 0 (1) 2 1
Other 0 0 (1) (1) 0 0 (2) 0 (2)
Net increase (decrease) in equity 0 1 14 (241) (1) 0 (227) 5 (222)
Balance – September 30, 2019 $ 35 $ 1,247 $ 24,310 $ (10,664) $ (266) $ (1,041) $ 13,621 $ 3,238 $ 16,859

*~~Accumulated Other Comprehensive Income (Loss)~~

~~See accompanying notes.~~

The Williams Companies, Inc.

Consolidated Statement of Changes in Equity ~~(Continued)~~

(Unaudited)


		The Williams Companies, Inc. Stockholders																			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			Preferred Stock		Common Stock		Capital in Excess of Par Value		Retained Deficit		AOCI*		Treasury Stock		Total Stockholders’ Equity		Noncontrolling Interests		Total Equity
		(Millions)																			(Millions)
Balance – December 31, 2019		$	35	$	1,247	$	24,323	$	(11,002)	$	(199)	$	(1,041)	$	13,363	$	3,001	$	16,364
Balance – December 31, 2020																				Balance – December 31, 2020	$	35	$	1,248	$	24,371	$	(12,748)	$	(96)	$	(1,041)	$	11,769	$	2,814	$	14,583
Net income (loss)	Net income (loss)	0		0		0		95		0		0		95		(27)		68		Net income (loss)	0		0		0		426		0		0		426		9		435
Other comprehensive income (loss)	Other comprehensive income (loss)	0		0		0		0		39		0		39		0		39		Other comprehensive income (loss)	0		0		0		0		(4)		0		(4)		0		(4)
Cash dividends – common stock ($1.20 per share)		0		0		0		(1,456)		0		0		(1,456)		0		(1,456)
Cash dividends – common stock ($0.41 per share)																				Cash dividends – common stock ($0.41 per share)	0		0		0		(498)		0		0		(498)		0		(498)
Dividends and distributions to noncontrolling interests	Dividends and distributions to noncontrolling interests	0		—		0		0		0		0		0		(147)		(147)		Dividends and distributions to noncontrolling interests	0		0		0		0		0		0		0		(54)		(54)
Stock-based compensation and related common stock issuances, net of tax	Stock-based compensation and related common stock issuances, net of tax	0		1		36		0		0		0		37		0		37		Stock-based compensation and related common stock issuances, net of tax	0		1		10		0		0		0		11		0		11

Contributions from noncontrolling interests	Contributions from noncontrolling interests	0		0		0		0		0		0		0		5		5		Contributions from noncontrolling interests	0		0		0		0		0		0		0		2		2
Other	Other	0		0		0		(13)		0		0		(13)		1		(12)		Other	0		0		3		(5)		0		0		(2)		0		(2)
Net increase (decrease) in equity	Net increase (decrease) in equity	0		1		36		(1,374)		39		0		(1,298)		(168)		(1,466)		Net increase (decrease) in equity	0		1		13		(77)		(4)		0		(67)		(43)		(110)
Balance – September 30, 2020		$	35	$	1,248	$	24,359	$	(12,376)	$	(160)	$	(1,041)	$	12,065	$	2,833	$	14,898
Balance – March 31, 2021																				Balance – March 31, 2021	$	35	$	1,249	$	24,384	$	(12,825)	$	(100)	$	(1,041)	$	11,702	$	2,771	$	14,473


Balance – December 31, 2018		$	35	$	1,245	$	24,693	$	(10,002)	$	(270)	$	(1,041)	$	14,660	$	1,337	$	15,997
Balance – December 31, 2019																				Balance – December 31, 2019	$	35	$	1,247	$	24,323	$	(11,002)	$	(199)	$	(1,041)	$	13,363	$	3,001	$	16,364

Net income (loss)	Net income (loss)	0		0		0		726		0		0		726		54		780		Net income (loss)	0		0		0		(517)		0		0		(517)		(53)		(570)
Other comprehensive income (loss)	Other comprehensive income (loss)	0		0		0		0		4		0		4		0		4		Other comprehensive income (loss)	0		0		0		0		(6)		0		(6)		0		(6)

Cash dividends – common stock ($1.14 per share)		0		0		0		(1,382)		0		0		(1,382)		0		(1,382)
Cash dividends – common stock ($0.40 per share)																				Cash dividends – common stock ($0.40 per share)	0		0		0		(485)		0		0		(485)		0		(485)
Dividends and distributions to noncontrolling interests	Dividends and distributions to noncontrolling interests	0		0		0		0		0		0		0		(86)		(86)		Dividends and distributions to noncontrolling interests	0		0		0		0		0		0		0		(44)		(44)
Stock-based compensation and related common stock issuances, net of tax	Stock-based compensation and related common stock issuances, net of tax	0		2		43		0		0		0		45		0		45		Stock-based compensation and related common stock issuances, net of tax	0		1		7		0		0		0		8		0		8
Sale of partial interest in consolidated subsidiary (Note 2)		0		0		0		0		0		0		0		1,333		1,333
Changes in ownership of consolidated subsidiaries, net (Note 2)		0		0		(426)		0		0		0		(426)		568		142

Contributions from noncontrolling interests	Contributions from noncontrolling interests	0		0		0		0		0		0		0		32		32		Contributions from noncontrolling interests	0		0		0		0		0		0		0		2		2

Other	Other	0		0		0		(6)		0		0		(6)		0		(6)		Other	0		0		0		(9)		0		0		(9)		(1)		(10)
Net increase (decrease) in equity	Net increase (decrease) in equity	0		2		(383)		(662)		4		0		(1,039)		1,901		862		Net increase (decrease) in equity	0		1		7		(1,011)		(6)		0		(1,009)		(96)		(1,105)
Balance – September 30, 2019		$	35	$	1,247	$	24,310	$	(10,664)	$	(266)	$	(1,041)	$	13,621	$	3,238	$	16,859
Balance – March 31, 2020																				Balance – March 31, 2020	$	35	$	1,248	$	24,330	$	(12,013)	$	(205)	$	(1,041)	$	12,354	$	2,905	$	15,259

*Accumulated Other Comprehensive Income (Loss)

See accompanying notes.

109

The Williams Companies, Inc.

Consolidated Statement of Cash Flows

(Unaudited)


		Nine Months Ended September 30,					Three Months Ended March 31,
		2020		2019			2021		2020
		(Millions)					(Millions)
OPERATING ACTIVITIES:	OPERATING ACTIVITIES:					OPERATING ACTIVITIES:
Net income (loss)	Net income (loss)	$	68	$	780	Net income (loss)	$	435	$	(570)
Adjustments to reconcile to net cash provided (used) by operating activities:	Adjustments to reconcile to net cash provided (used) by operating activities:					Adjustments to reconcile to net cash provided (used) by operating activities:
Depreciation and amortization	Depreciation and amortization	1,285		1,275		Depreciation and amortization	438		429
Provision (benefit) for deferred income taxes	Provision (benefit) for deferred income taxes	52		268		Provision (benefit) for deferred income taxes	144		(177)
Equity (earnings) losses	Equity (earnings) losses	(236)		(260)		Equity (earnings) losses	(131)		(22)
Distributions from unconsolidated affiliates	Distributions from unconsolidated affiliates	466		458		Distributions from unconsolidated affiliates	176		169

Gain on disposition of equity-method investments (Note 5)		0		(122)
Impairment of goodwill (Note 12)		187		0
Impairment of equity-method investments (Note 12)		938		186

Impairment of certain assets (Note 12)		0		76
Impairment of goodwill (Note 10)						Impairment of goodwill (Note 10)	0		187
Impairment of equity-method investments (Note 10)						Impairment of equity-method investments (Note 10)	0		938

Amortization of stock-based awards	Amortization of stock-based awards	39		44		Amortization of stock-based awards	20		9

Cash provided (used) by changes in current assets and liabilities:	Cash provided (used) by changes in current assets and liabilities:					Cash provided (used) by changes in current assets and liabilities:
Accounts receivable	Accounts receivable	(18)		159		Accounts receivable	(59)		67
Inventories	Inventories	(33)		7		Inventories	(8)		19
Other current assets and deferred charges	Other current assets and deferred charges	(15)		(10)		Other current assets and deferred charges	(6)		20
Accounts payable	Accounts payable	(77)		(76)		Accounts payable	38		(155)
Accrued liabilities	Accrued liabilities	(286)		76		Accrued liabilities	(116)		(150)
Other, including changes in noncurrent assets and liabilities	Other, including changes in noncurrent assets and liabilities	12		(159)		Other, including changes in noncurrent assets and liabilities	(16)		23
Net cash provided (used) by operating activities	Net cash provided (used) by operating activities	2,382		2,702		Net cash provided (used) by operating activities	915		787
FINANCING ACTIVITIES:	FINANCING ACTIVITIES:					FINANCING ACTIVITIES:
Proceeds from (payments of) commercial paper – net		40		(4)

Proceeds from long-term debt	Proceeds from long-term debt	3,898		736		Proceeds from long-term debt	897		1,702
Payments of long-term debt	Payments of long-term debt	(3,836)		(904)		Payments of long-term debt	(5)		(1,518)
Proceeds from issuance of common stock	Proceeds from issuance of common stock	9		10		Proceeds from issuance of common stock	3		6
Proceeds from sale of partial interest in consolidated subsidiary (Note 2)		0		1,330

Common dividends paid	Common dividends paid	(1,456)		(1,382)		Common dividends paid	(498)		(485)
Dividends and distributions paid to noncontrolling interests	Dividends and distributions paid to noncontrolling interests	(147)		(86)		Dividends and distributions paid to noncontrolling interests	(54)		(44)
Contributions from noncontrolling interests	Contributions from noncontrolling interests	5		32		Contributions from noncontrolling interests	2		2
Payments for debt issuance costs	Payments for debt issuance costs	(20)		0		Payments for debt issuance costs	(6)		0

Other – net	Other – net	(12)		(11)		Other – net	(13)		(10)
Net cash provided (used) by financing activities	Net cash provided (used) by financing activities	(1,519)		(279)		Net cash provided (used) by financing activities	326		(347)
INVESTING ACTIVITIES:	INVESTING ACTIVITIES:					INVESTING ACTIVITIES:
Property, plant, and equipment:	Property, plant, and equipment:					Property, plant, and equipment:
Capital expenditures (1)	Capital expenditures (1)	(938)		(1,705)		Capital expenditures (1)	(260)		(306)
Dispositions – net	Dispositions – net	(30)		(32)		Dispositions – net	(1)		(3)
Contributions in aid of construction	Contributions in aid of construction	27		25		Contributions in aid of construction	19		14

Purchases of businesses, net of cash acquired (Note 2)		0		(728)
Proceeds from dispositions of equity-method investments (Note 5)		0		485

Purchases of and contributions to equity-method investments	Purchases of and contributions to equity-method investments	(150)		(361)		Purchases of and contributions to equity-method investments	(14)		(30)

Other – net	Other – net	9		(28)		Other – net	(1)		(4)
Net cash provided (used) by investing activities	Net cash provided (used) by investing activities	(1,082)		(2,344)		Net cash provided (used) by investing activities	(257)		(329)
Increase (decrease) in cash and cash equivalents	Increase (decrease) in cash and cash equivalents	(219)		79		Increase (decrease) in cash and cash equivalents	984		111

Cash and cash equivalents at beginning of year	Cash and cash equivalents at beginning of year	289		168		Cash and cash equivalents at beginning of year	142		289
Cash and cash equivalents at end of period	Cash and cash equivalents at end of period	$	70	$	247	Cash and cash equivalents at end of period	$	1,126	$	400
_____________	_____________					_____________
(1) Increases to property, plant, and equipment	(1) Increases to property, plant, and equipment	$	(912)	$	(1,707)	(1) Increases to property, plant, and equipment	$	(263)	$	(254)
Changes in related accounts payable and accrued liabilities	Changes in related accounts payable and accrued liabilities	(26)		2		Changes in related accounts payable and accrued liabilities	3		(52)
Capital expenditures	Capital expenditures	$	(938)	$	(1,705)	Capital expenditures	$	(260)	$	(306)

See accompanying notes.

1110

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, ~~2019,~~2020, in ~~Exhibit 99.1 of~~ our Annual Report on Form ~~8-K dated May 4, 2020.~~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.

Description of Business

We are a Delaware corporation whose common stock is listed and traded on the New York Stock Exchange. Our operations are located in the United States. Effective January 1, 2020, following an organizational realignment, our interstate natural gas pipeline Northwest Pipeline LLC (Northwest Pipeline), which was reported within the West reporting segment throughout 2019, is now managed within the Transmission & Gulf of Mexico reporting segment (previously identified as the Atlantic-Gulf reporting segment). As a result, beginning with the reporting of first-quarter 2020, our operationsStates and are presented within the following reportable segments: Transmission & Gulf of Mexico, Northeast G&P, and West, consistent with the manner in which our chief operating decision maker evaluates performance and allocates resources. All remaining business activities, including our recently acquired upstream operations, as well as corporate activities are included in Other. ~~Prior period segment disclosures have been recast for the new segment presentation.~~

Transmission & Gulf of Mexico is comprised of our interstate natural gas pipelines, Transcontinental Gas Pipe Line Company, LLC (Transco) and Northwest Pipeline LLC (Northwest Pipeline), as well as 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 variable interest entity, or VIE), which is a proprietary floating production system, a 50 percent equity-method investment in Gulfstream Natural Gas System, L.L.C., and a 60 percent equity-method investment in Discovery Producer Services LLC (Discovery).

Northeast G&P is comprised of our midstream gathering, processing, and fractionation businesses in the Marcellus Shale region primarily in Pennsylvania and New York, and the Utica Shale region of eastern Ohio, as well as a 65 percent interest in Ohio Valley Midstream LLC (Northeast JV) (a consolidated VIE) which operates in West Virginia, Ohio, and Pennsylvania, a 66 percent interest in Cardinal Gas Services, L.L.C. (Cardinal) (a consolidated VIE) which operates in Ohio, a 69 percent equity-method investment in Laurel Mountain Midstream, LLC (Laurel Mountain), a 50 percent equity-method investment in Blue Racer Midstream LLC (Blue Racer) (we previously effectively owned a 29 percent indirect interest in Blue Racer through our 58 percent equity-method investment in Caiman Energy II, LLC (Caiman II) until acquiring a controlling interest in November 2020), and Appalachia Midstream Services, LLC, a wholly owned subsidiary that owns equity-method investments with an approximate average 66 percent interest in multiple gas gathering systems in the Marcellus Shale region (Appalachia Midstream Investments).

~~Notes (Continued)~~

West is comprised of our gas gathering, processing, and treating operations in the Rocky Mountain region of Colorado and Wyoming, the Barnett Shale region of north-central Texas, the Eagle Ford Shale region of south Texas, the Haynesville Shale region of northwest Louisiana, and the Mid-Continent region which includes the

Notes (Continued)

Anadarko, Arkoma, and Permian basins. This segment also includes our natural gas liquid (NGL) and natural gas marketing business, storage facilities, an undivided 50 percent interest in an NGL fractionator near Conway, Kansas, a 50 percent equity-method investment in Overland Pass Pipeline Company LLC, a 50 percent equity-method investment in Rocky Mountain Midstream Holdings LLC (RMM), a 20 percent equity-method investment in Targa Train 7 LLC (Targa Train 7) (a nonconsolidated VIE), and a 15 percent interest in Brazos Permian II, LLC (Brazos Permian II) (a nonconsolidated VIE). ~~West also included our former 50 percent equity-method investment in Jackalope Gas Gathering Services, L.L.C. (Jackalope), which was sold in April 2019.~~

Basis of Presentation

Significant risks and uncertainties

We believe that the carrying value of certain of our property, plant, and equipment and other identifiable intangible assets, notably certain acquired assets accounted for as business combinations between 2012 and 2014, may be in excess of current fair value. However, the carrying value of these assets, in our judgment, continues to be recoverable. 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, ~~including effects of financial distress caused by financial and commodity market declines or unfavorable developments in ongoing bankruptcy proceedings,~~ could impact our assumptions and ultimately result in impairments of these assets. Such transactions or developments may also indicate that certain of our equity-method investments have experienced other-than-temporary declines in value, which could result in impairment.

~~Customer bankruptcy~~

In June 2020, our customer, Chesapeake Energy Corporation (Chesapeake), announced that it had voluntarily filed for relief under Chapter 11 of the U.S. Bankruptcy Code. We provide midstream services, including wellhead gathering, for the natural gas that Chesapeake and its joint interest owners produce, primarily in the Eagle Ford Shale, Haynesville Shale, and Marcellus Shale regions (through Appalachia Midstream Investments). In 2019, Chesapeake accounted for approximately 6 percent of our consolidated revenues. As of September 30, 2020, trade accounts receivable due from Chesapeake include $88 million related to services provided prior to Chesapeake’s bankruptcy filing. The remaining trade accounts receivable due from Chesapeake are current.

We have evaluated these receivables from Chesapeake and our related asset groups and investments involved in providing services to Chesapeake and determined that no expected credit losses or impairment charges are required to be recognized at this time. This evaluation considered the physical nature of our services in these basins, where we gather at the wellhead and are critical to Chesapeake’s ability to move product to market, along with an assessed low likelihood of contract rejection, noting that to date Chesapeake has not attempted to reject any of our contracts. Chesapeake also received initial limited approval to continue paying for services such as those we provide. We also considered our prior experiences with customer bankruptcies, where receivables were ultimately collectible even if the timing of collections was impacted. Future developments in Chesapeake’s ongoing bankruptcy proceedings could affect our assumptions and conclusions regarding credit losses and impairment charges.

~~Northeast Supply Enhancement~~

~~As of September 30, 2020,~~ ~~Property, plant, and equipment~~ in our Consolidated Balance Sheet includes approximately $215 million of capitalized project development costs for the Northeast Supply Enhancement project. Approvals required for the project from the New York State Department of Environmental Conservation and the New Jersey Department of Environmental Protection have been denied and we have not refiled at this time. Beginning in May 2020, we discontinued capitalization of costs related to this project.

The customer precedent agreements for the Northeast Supply Enhancement project remain in effect and the project’s Federal Energy Regulatory Commission (FERC) certificate remains active. As such, we do not believe this project is probable of abandonment at this time and consider the carrying amount to be recoverable; thus, no

~~Notes (Continued)~~

impairment charge has been recognized. It is reasonably possible that further adverse developments in the near future could change this determination, resulting in a future impairment charge of a substantial portion of the capitalized costs.

~~Accounting standards issued and adopted~~

In June 2016, the Financial Accounting Standards Board issued Accounting Standards Update (ASU) 2016-13 “Financial Instruments - Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments” (ASU 2016-13). ASU 2016-13 changed 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 are required to use a forward-looking “expected loss” model that generally will result in the earlier recognition of allowances for losses. We adopted ASU 2016-13 effective January 1, 2020, which primarily applied to our short-term trade receivables. There was no cumulative effect adjustment to retained earnings upon adoption.

The majority of our trade receivable balances are due within 30 days. We monitor the credit quality of our counterparties through review of collection trends, credit ratings, and other analyses, such as bankruptcy monitoring. Financial assets from our natural gas transmission business and gathering and transportation business are segregated into separate pools for evaluation due to different counterparty risks inherent in each business. Changes in counterparty risk factors could lead to reassessment of the composition of our financial assets as separate pools or the need for additional pools. We calculate our allowance for credit losses incorporating an aging method. In estimating our expected credit losses, we utilized historical loss rates over many years, which included periods of both high and low commodity prices. Commodity prices could have a significant impact on a portion of our gathering and processing counterparties’ financial health and ability to satisfy current liabilities. Our expected credit loss estimate considered both internal and external forward-looking commodity price expectations, as well as counterparty credit ratings, and factors impacting their near-term liquidity. In addition, our expected credit loss estimate considered potential contractual, physical, and commercial protections and outcomes in the case of a counterparty bankruptcy. The physical location and nature of our services help to mitigate collectability concerns of our gathering and processing producer customers. Our gathering lines are physically connected to the wellhead and may be located in areas with limited service provider options, making them very costly to replicate by other providers. As such, our gathering assets play a critical role in our customers’ ability to generate operating cash flows. Commodity price movements generally do not impact the majority of our natural gas transmission businesses customers’ financial condition.

Past due accounts are generally written off against the allowance for doubtful accounts only after all collection attempts have been exhausted. Excluding previously discussed trade accounts receivable due from Chesapeake related to services provided prior to Chesapeake’s bankruptcy filing, we do not have a material amount of past due receivables at September 30, 2020.

~~Note 2 – Acquisitions~~

~~UEOM~~

As of December 31, 2018, we owned a 62 percent interest in Utica East Ohio Midstream LLC (UEOM) which we accounted for as an equity-method investment. On March 18, 2019, we signed and closed the acquisition of the remaining 38 percent interest in UEOM. Total consideration paid, including post-closing adjustments, was $741 million in cash funded through credit facility borrowings and cash on hand, net of $13 million cash acquired. As a result of acquiring this additional interest, we obtained control of and consolidated UEOM.

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 12 – 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.

~~Notes (Continued)~~

~~Northeast JV~~

Concurrent with the UEOM acquisition, we executed an agreement whereby we contributed our consolidated interests in UEOM and our Ohio Valley midstream business to a newly formed partnership. In June 2019, our partner invested approximately $1.33 billion 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 $567 million, and decreased~~ ~~Capital in excess of par value~~ ~~by $426 million and~~ ~~Deferred income tax liabilities~~ ~~by $141 million in the Consolidated Balance Sheet for the year ended December 31, 2019.~~

The goodwill recognized in the UEOM acquisition of $187 million (includes a $1 million adjustment recorded in the first quarter of 2020) was impaired during the first quarter of 2020. Our partner’s $65 million share of this impairment is reflected within ~~Net income (loss) attributable to noncontrolling interests~~ ~~in the Consolidated Statement of Income (see Note 12 – Fair Value Measurements and Guarantees).~~

~~Notes (Continued)~~

Note 2 – Variable Interest Entities

Consolidated VIEs

As of March 31, 2021, we consolidate the following VIEs:

Northeast JV

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

Gulfstar One

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

Cardinal

We own a66 percent interest in Cardinal, a subsidiary that provides gathering services for the Utica Shale region and is a VIE due to certain risks shared with customers. We are the primary beneficiary because we have the power to direct the activities that most significantly impact Cardinal’s economic performance. Future expansion activity is expected to be funded with capital contributions from us and the other equity partner on a proportional basis.

Notes (Continued)

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


	March 31, 2021		December 31, 2020
	(Millions)
Assets (liabilities):
Cash and cash equivalents	$	83	$	107
Trade accounts and other receivables – net	128		148


Other current assets and deferred charges	5		7

Property, plant, and equipment – net	5,465		5,514
Intangible assets – net of accumulated amortization	2,349		2,376
Regulatory assets, deferred charges, and other	15		15
Accounts payable	(49)		(42)

Accrued liabilities	(34)		(34)




Regulatory liabilities, deferred income, and other	(287)		(289)

Nonconsolidated VIEs

Targa Train 7

We own a 20 percent interest in Targa Train 7, which provides fractionation services at Mt. Belvieu and is a VIE due primarily to our limited participating rights as the minority equity holder. At March 31, 2021, the carrying value of our investment in Targa Train 7 was $50 million. Our maximum exposure to loss is limited to the carrying value of our investment.

Brazos Permian II

We own a 15 percent interest in Brazos Permian II, which provides gathering and processing services in the Delaware basin and is a VIE due primarily to our limited participating rights as the minority equity holder. During the first quarter of 2020 we recorded an impairment of our equity-method investment in Brazos Permian II. Our maximum exposure to loss is limited to the carrying value of our investment.

Notes (Continued)

Note 3 – Revenue Recognition

Revenue by Category

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

Transco Northwest Pipeline Gulf of Mexico Midstream Northeast
Midstream West Midstream Other Eliminations Total
(Millions)
Three Months Ended September 30, 2020
Revenues from contracts with customers:
Service revenues:
Regulated interstate natural gas transportation and storage $ 600 $ 111 $ 0 $ 0 $ 0 $ 0 $ (3) $ 708
Gathering, processing, transportation, fractionation, and storage:
Monetary consideration 0 0 85 332 288 0 (17) 688
Commodity consideration 0 0 6 2 32 0 0 40
Other 3 0 3 41 20 0 (2) 65
Total service revenues 603 111 94 375 340 0 (22) 1,501
Product sales:
NGL and natural gas 21 0 26 12 394 0 (36) 417
Total revenues from contracts with customers 624 111 120 387 734 0 (58) 1,918
Other revenues (1) 2 0 3 6 0 8 (4) 15
Total revenues $ 626 $ 111 $ 123 $ 393 $ 734 $ 8 $ (62) $ 1,933
Three Months Ended September 30, 2019
Revenues from contracts with customers:
Service revenues:
Regulated interstate natural gas transportation and storage $ 601 $ 111 $ 0 $ 0 $ 0 $ 0 $ (2) $ 710
Gathering, processing, transportation, fractionation, and storage:
Monetary consideration 0 0 117 310 308 0 (19) 716
Commodity consideration 0 0 7 1 30 0 0 38
Other 0 0 8 38 12 0 (5) 53
Total service revenues 601 111 132 349 350 0 (26) 1,517
Product sales:
NGL and natural gas 41 0 34 30 391 0 (28) 468
Total revenues from contracts with customers 642 111 166 379 741 0 (54) 1,985
Other revenues (1) 3 0 2 5 0 7 (3) 14
Total revenues $ 645 $ 111 $ 168 $ 384 $ 741 $ 7 $ (57) $ 1,999

Transco

Northwest Pipeline

Gulf of Mexico Midstream

Northeast
Midstream

West Midstream

Other

Eliminations

Total

(Millions)

~~Notes (Continued)~~


		Transco		Northwest Pipeline		Gulf of Mexico Midstream		Northeast Midstream		West Midstream		Other		Eliminations		Total
		(Millions)
Nine Months Ended September 30, 2020
Three Months Ended March 31, 2021																		Three Months Ended March 31, 2021
Revenues from contracts with customers:	Revenues from contracts with customers:																	Revenues from contracts with customers:
Service revenues:	Service revenues:																	Service revenues:
Regulated interstate natural gas transportation and storage	Regulated interstate natural gas transportation and storage	$	1,796	$	336	$	0	$	0	$	0	$	0	$	(6)	$	2,126	Regulated interstate natural gas transportation and storage	$	625	$	113	$	0	$	0	$	0	$	0	$	(3)	$	735
Gathering, processing, transportation, fractionation, and storage:	Gathering, processing, transportation, fractionation, and storage:																	Gathering, processing, transportation, fractionation, and storage:
Monetary consideration	Monetary consideration	0		0		262		952		884		0		(58)		2,040		Monetary consideration	0		0		86		311		262		0		(21)		638
Commodity consideration	Commodity consideration	0		0		14		5		74		0		0		93		Commodity consideration	0		0		11		3		35		0		0		49
Other	Other	8		0		19		123		46		0		(11)		185		Other	3		0		3		41		19		0		(4)		62
Total service revenues	Total service revenues	1,804		336		295		1,080		1,004		0		(75)		4,444		Total service revenues	628		113		100		355		316		0		(28)		1,484
Product sales:
NGL and natural gas		61		0		75		42		1,056		0		(96)		1,138
Product sales																		Product sales	14		0		53		32		1,080		56		(90)		1,145
Total revenues from contracts with customers	Total revenues from contracts with customers	1,865		336		370		1,122		2,060		0		(171)		5,582		Total revenues from contracts with customers	642		113		153		387		1,396		56		(118)		2,629
Other revenues (1)	Other revenues (1)	4		0		6		16		5		25		(11)		45		Other revenues (1)	2		0		2		6		(31)		7		(3)		(17)
Total revenues	Total revenues	$	1,869	$	336	$	376	$	1,138	$	2,065	$	25	$	(182)	$	5,627	Total revenues	$	644	$	113	$	155	$	393	$	1,365	$	63	$	(121)	$	2,612

Nine Months Ended September 30, 2019
Three Months Ended March 31, 2020																		Three Months Ended March 31, 2020
Revenues from contracts with customers:	Revenues from contracts with customers:																	Revenues from contracts with customers:
Service revenues:	Service revenues:																	Service revenues:
Regulated interstate natural gas transportation and storage	Regulated interstate natural gas transportation and storage	$	1,736	$	335	$	0	$	0	$	0	$	0	$	(4)	$	2,067	Regulated interstate natural gas transportation and storage	$	604	$	115	$	0	$	0	$	0	$	0	$	(2)	$	717
Gathering, processing, transportation, fractionation, and storage:	Gathering, processing, transportation, fractionation, and storage:																	Gathering, processing, transportation, fractionation, and storage:
Monetary consideration	Monetary consideration	0		0		366		840		1,007		0		(54)		2,159		Monetary consideration	0		0		99		312		299		0		(22)		688
Commodity consideration	Commodity consideration	0		0		33		9		116		0		0		158		Commodity consideration	0		0		5		2		21		0		0		28
Other	Other	1		0		21		104		32		0		(12)		146		Other	3		0		6		41		9		0		(5)		54
Total service revenues	Total service revenues	1,737		335		420		953		1,155		0		(70)		4,530		Total service revenues	607		115		110		355		329		0		(29)		1,487
Product sales:
NGL and natural gas		88		0		140		114		1,300		0		(132)		1,510
Product sales																		Product sales	20		0		32		29		359		0		(29)		411
Total revenues from contracts with customers	Total revenues from contracts with customers	1,825		335		560		1,067		2,455		0		(202)		6,040		Total revenues from contracts with customers	627		115		142		384		688		0		(58)		1,898
Other revenues (1)	Other revenues (1)	8		0		6		15		12		22		(9)		54		Other revenues (1)	0		0		2		5		3		8		(3)		15
Total revenues	Total revenues	$	1,833	$	335	$	566	$	1,082	$	2,467	$	22	$	(211)	$	6,094	Total revenues	$	627	$	115	$	144	$	389	$	691	$	8	$	(61)	$	1,913

(1)Revenues not within the scope of Accounting Standards Codification Topic 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~~the Consolidated Statement of ~~Income,~~Operations, and amounts associated with our derivative contracts, which are reported in Product sales in ~~our~~the Consolidated Statement of ~~Income.~~Operations.

1714

Notes (Continued)

Contract Assets

The following table presents a reconciliation of our contract assets:


		Three Months Ended September 30,				Nine Months Ended September 30,					Three Months Ended March 31,
		2020		2019		2020		2019				2021		2020
		(Millions)										(Millions)
Balance at beginning of period	Balance at beginning of period	$	30	$	17	$	8	$	4	Balance at beginning of period		$	12	$	8
Revenue recognized in excess of amounts invoiced	Revenue recognized in excess of amounts invoiced	36		14		105		53		Revenue recognized in excess of amounts invoiced		45		23
Minimum volume commitments invoiced	Minimum volume commitments invoiced	(24)		0		(71)		(26)		Minimum volume commitments invoiced		(32)		(13)
Balance at end of period	Balance at end of period	$	42	$	31	$	42	$	31	Balance at end of period		$	25	$	18

Contract Liabilities

The following table presents a reconciliation of our contract liabilities:


		Three Months Ended September 30,				Nine Months Ended September 30,					Three Months Ended March 31,
		2020		2019		2020		2019				2021		2020
		(Millions)										(Millions)
Balance at beginning of period	Balance at beginning of period	$	1,203	$	1,331	$	1,215	$	1,397	Balance at beginning of period		$	1,209	$	1,215
Payments received and deferred	Payments received and deferred	14		12		116		138		Payments received and deferred		13		28
Significant financing component	Significant financing component	3		3		8		10		Significant financing component		3		3
Recognized in revenue	Recognized in revenue	(50)		(77)		(169)		(276)		Recognized in revenue		(54)		(57)
Balance at end of period	Balance at end of period	$	1,170	$	1,269	$	1,170	$	1,269	Balance at end of period		$	1,171	$	1,189

Remaining Performance Obligations

Remaining performance obligations primarily include reservation charges on contracted capacity for our gas pipeline firm transportation contracts with customers, storage capacity contracts, long-term contracts containing minimum volume commitments associated with our midstream businesses, and fixed payments associated with offshore production handling. For our interstate natural gas pipeline businesses, remaining performance obligations reflect the rates for such services in our current ~~FERC~~Federal Energy Regulatory Commission (FERC) tariffs for the life of the related contracts; however, these rates may change based on future tariffs approved by the FERC and the amount and timing of these changes are not currently known.

Our remaining performance obligations exclude variable consideration, including contracts with variable consideration for which we have elected the practical expedient for consideration recognized in revenue as billed. Certain of our contracts contain evergreen and other renewal provisions for periods beyond the initial term of the contract. The remaining performance obligation amounts as of ~~September 30, 2020,~~March 31, 2021, do not consider potential future performance obligations for which the renewal has not been exercised and exclude contracts with customers for which the underlying facilities have not received FERC authorization to be placed into service. Consideration received prior to ~~September 30, 2020,~~March 31, 2021, that will be recognized in future periods is also excluded from our remaining performance obligations and is instead reflected in contract liabilities.

1815

Notes (Continued)

The following table presents the amount of the contract liabilities balance expected to be recognized as revenue when performance obligations are satisfied and the transaction price allocated to the remaining performance obligations under certain contracts as of ~~September 30, 2020.~~March 31, 2021.


		Contract Liabilities		Remaining Performance Obligations			Contract Liabilities		Remaining Performance Obligations
		(Millions)					(Millions)
2020 (remainder)		$	45	$	840
2021		72		3,315
2021 (remainder)						2021 (remainder)	$	87	$	2,610
2022	2022	69		3,145		2022	113		3,363
2023	2023	54		2,811		2023	105		3,097
2024	2024	52		2,301		2024	102		2,578
2025						2025	97		2,315

Thereafter	Thereafter	878		18,178		Thereafter	667		17,750
Total	Total	$	1,170	$	30,590	Total	$	1,171	$	31,713

Accounts Receivable

The following is a summary of our Trade accounts and other receivables – net:


		September 30, 2020		December 31, 2019			March 31, 2021		December 31, 2020
		(Millions)					(Millions)
Accounts receivable related to revenues from contracts with customers	Accounts receivable related to revenues from contracts with customers	$	868	$	890	Accounts receivable related to revenues from contracts with customers	$	1,007	$	892
Other accounts receivable	Other accounts receivable	143		106		Other accounts receivable	51		107
Total reflected in Trade accounts and other receivables – net		$	1,011	$	996
Trade accounts and other receivables – net						Trade accounts and other receivables – net	$	1,058	$	999

Note 4 – ~~Variable Interest Entities~~Investing Activities

~~Consolidated VIEs~~Impairment of Equity-Method Investments

AsImpairment of ~~September 30,~~equity-method investments for the three months ended March 31, 2020, ~~we consolidate~~includes $938 million associated with the ~~following VIEs:~~impairment of equity-method investments (see Note 10 – Fair Value Measurements and Guarantees).

~~Northeast JV~~Equity Earnings (Losses)

~~We own~~Equity earnings (losses) for the three months ended March 31, 2020, includes a ~~65 percent interest in~~$78 million loss associated with the ~~Northeast JV, a subsidiary that is a VIE due to certain~~first-quarter 2020 full impairment of goodwill recognized by our ~~voting rights being disproportionate~~investee RMM, which was allocated entirely to our ~~obligation to absorb losses and substantially all~~member interest per the terms of the Northeast JV’s activities being performed on our behalf. We are the primary beneficiary because we have the power to direct the activities that most significantly impact the Northeast JV’s economic performance. The Northeast JV provides midstream servicesmembership agreement.

Note 5 – Provision (Benefit) for ~~producers in the Marcellus Shale and Utica Shale regions. Future expansion activity is expected to be funded with capital contributions from us and the other equity partner on a proportional basis.~~

~~Gulfstar One~~

~~Cardinal~~Income Taxes

~~We own a~~The Provision (benefit) for income taxes66 percent interest in Cardinal, a subsidiary that provides gathering services for the Utica Shale region and is a VIE due to certain risks shared with customers. We are the primary beneficiary because we have the power to direct the activities that most significantly impact Cardinal’s economic performance. Future expansion activity is expected to be funded with capital contributions from us and the other equity partner on a proportional basis. includes:


	Three Months Ended March 31,
		2021		2020
		(Millions)
Current:
Federal		$	(2)	$	(28)
State		(1)		1
		(3)		(27)
Deferred:
Federal		115		(134)
State		29		(43)

		144		(177)
Provision (benefit) for income taxes		$	141	$	(204)

1916

Notes (Continued)

The ~~following table presents amounts included in our Consolidated Balance Sheet that are only~~effective income tax rates for the ~~use or obligation~~total provision (benefit) for both the three months ended March 31, 2021 and 2020 are greater than the federal statutory rate, primarily due to the effect of ~~our consolidated VIEs:~~

September 30,
2020 December 31,
2019
(Millions)
Assets (liabilities):
Cash and cash equivalents $ 62 $ 102
Trade accounts and other receivables – net 150 167
Other current assets and deferred charges 6 5
Property, plant, and equipment – net 5,562 5,745
Intangible assets – net of accumulated amortization 2,404 2,669
Regulatory assets, deferred charges, and other 12 13
Accounts payable (27) (58)
Accrued liabilities (36) (66)
Regulatory liabilities, deferred income, and other (287) (283)
state income taxes.

~~Nonconsolidated VIEs~~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.

~~Brazos Permian II~~

~~We own a 15 percent interest in Brazos Permian II, which provides gathering and processing services in~~Note 6 – Earnings (Loss) Per Common Share


	Three Months Ended March 31,
		2021		2020
		(Dollars in millions, except per-share amounts; shares in thousands)
Net income (loss) available to common stockholders		$	425	$	(518)
Basic weighted-average shares		1,214,646		1,213,019
Effect of dilutive securities:
Nonvested restricted stock units		2,565		0

Diluted weighted-average shares (1)		1,217,211		1,213,019
Earnings (loss) per common share:
Basic		$	.35	$	(.43)
Diluted		$	.35	$	(.43)

(1)For the ~~Delaware basin and is a VIE~~three months ended March 31, 2020, 1.3 million weighted-average nonvested restricted stock units have been excluded from the computation of diluted earnings (loss) per common share as their inclusion would be antidilutive due ~~primarily~~ to our limited participating rights as the minority equity holder. During the first quarter of 2020 we recorded an impairment of our equity-method investment in Brazos Permian II (see Note 12 – Fair Value Measurements and Guarantees). Our exposureloss available to ~~loss is limited to the carrying value of our investment.~~common stockholders.

~~Note 5 – Investing Activities~~

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

Three Months Ended
September 30, Nine Months Ended
September 30,
2020 2019 2020 2019
(Millions)
Gain on disposition of equity-method investments (1) $ 0 $ 0 $ 0 $ 122
Other 2 7 6 10
Other investing income (loss) – net
$ 2 $ 7 $ 6 $ 132

~~_______________~~

~~(1) In April 2019, we sold our 50 percent equity-method interest in Jackalope for $485 million in cash, resulting in a gain on the disposition of $122 million.~~

~~Impairment of Equity-Method Investments~~

~~See Note 12 – Fair Value Measurements and Guarantees for information regarding impairments of our equity-method investments.~~

~~Notes (Continued)~~

~~Impairment of RMM Goodwill~~

~~Equity earnings (losses)~~ for the nine months ended September 30, 2020, includes a $78 million loss associated with the first-quarter 2020 full impairment of goodwill recognized by our investee RMM, which was allocated entirely to our member interest per the terms of the membership agreement.

~~Note 6 – Other Accruals~~

~~Operating and maintenance expenses~~ ~~for the three and nine months ended September 30, 2019, reflect charges of $7 million and $30 million, respectively, and~~ ~~Selling, general, and administrative expenses~~ for the three and nine months ended September 30, 2019, reflect charges of $3 million and $23 million, respectively, for estimated severance and related costs, primarily associated with a voluntary separation program. The severance and related costs by segment for the three and nine months ended September 30, 2019 are as follows:

Three Months Ended
September 30, Nine Months Ended
September 30,
2019
(Millions)
Transmission & Gulf of Mexico $ 14 $ 36
Northeast G&P (3) 7
West (1) 10
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,
2020 2019 2020 2019
(Millions)
Current:
Federal $ 0 $ (10) $ (28) $ (25)
State 0 0 0 0
Foreign 0 1 0 1
0 (9) (28) (24)
Deferred:
Federal 97 73 56 225
State 14 13 (4) 43
111 86 52 268
Provision (benefit) for income taxes $ 111 $ 77 $ 24 $ 244

The effective income tax rates for the total provision (benefit) for the three and nine months ended September 30, 2020 and 2019 are greater than the federal statutory rate, primarily due to the effect of state income taxes.

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

~~Notes (Continued)~~

~~Note 8 – Earnings (Loss) Per Common Share~~

Three Months Ended
September 30, Nine Months Ended
September 30,
2020 2019 2020 2019
(Dollars in millions, except per-share
amounts; shares in thousands)
Net income (loss) available to common stockholders $ 308 $ 220 $ 93 $ 724
Basic weighted-average shares 1,213,912 1,212,270 1,213,512 1,211,938
Effect of dilutive securities:
Nonvested restricted stock units 1,423 1,790 1,241 1,809
Stock options 0 105 4 196
Diluted weighted-average shares 1,215,335 1,214,165 1,214,757 1,213,943
Earnings (loss) per common share:
Basic $ .25 $ .18 $ .08 $ .60
Diluted $ .25 $ .18 $ .08 $ .60

~~Note 9~~ – Employee Benefit Plans

Net periodic benefit cost (credit) is as follows:


		Pension Benefits										Pension Benefits
		Three Months Ended September 30,				Nine Months Ended September 30,					Three Months Ended March 31,
		2020		2019		2020		2019				2021		2020
		(Millions)										(Millions)
Components of net periodic benefit cost (credit):	Components of net periodic benefit cost (credit):									Components of net periodic benefit cost (credit):
Service cost	Service cost	$	8	$	11	$	23	$	33	Service cost		$	8	$	8
Interest cost	Interest cost	9		13		28		38		Interest cost		7		10
Expected return on plan assets	Expected return on plan assets	(13)		(15)		(40)		(46)		Expected return on plan assets		(11)		(13)

Amortization of net actuarial loss	Amortization of net actuarial loss	5		3		16		11		Amortization of net actuarial loss		4		4
Net actuarial loss from settlements	Net actuarial loss from settlements	1		1		9		1		Net actuarial loss from settlements		0		6
Net periodic benefit cost (credit)	Net periodic benefit cost (credit)	$	10	$	13	$	36	$	37	Net periodic benefit cost (credit)		$	8	$	15

Other Postretirement Benefits
Three Months Ended
September 30, Nine Months Ended
September 30,
2020 2019 2020 2019
(Millions)
Components of net periodic benefit cost (credit):
Service cost $ 1 $ 1 $ 1 $ 1
Interest cost 2 2 5 6
Expected return on plan assets (3) (3) (8) (8)
Reclassification to regulatory liability 0 0 1 1
Net periodic benefit cost (credit) $ 0 $ 0 $ (1) $ 0

Notes (Continued)


		Other Postretirement Benefits
	Three Months Ended March 31,
		2021		2020
		(Millions)
Components of net periodic benefit cost (credit):

Interest cost		$	1	$	2
Expected return on plan assets		(2)		(3)


Reclassification to regulatory liability		1		1
Net periodic benefit cost (credit)		$	0	$	0

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.~~Operations.

During the ~~nine~~three months ended ~~September 30, 2020,~~March 31, 2021, we contributed ~~$12~~$1 million to our pension plans and $4$1 million to our other postretirement benefit plans. We presently anticipate making additional contributions of

~~Notes (Continued)~~

approximately $2 million to our pension plans and approximately $1$5 million to our other postretirement benefit plans in the remainder of ~~2020.~~2021.

Note 8 – Debt and Banking Arrangements

Long-Term Debt

Issuances and retirements

On March 2, 2021, we completed a public offering of $900 million of 2.6 percent senior unsecured notes due 2031.

Commercial Paper Program

At March 31, 2021, 0 Commercial paper was outstanding under our $4 billion commercial paper program.

Credit Facilities


	March 31, 2021
	Stated Capacity		Outstanding
	(Millions)

Long-term credit facility (1)	$	4,500	$	0
Letters of credit under certain bilateral bank agreements			17

Note ~~10 – Debt and Banking Arrangements~~

~~Long-Term Debt~~

~~Issuances and retirements~~

~~On August 17, 2020, we retired $600 million of 4.125 percent senior unsecured notes that were due November 15, 2020.~~

~~On May 14, 2020, we completed a public offering of $1 billion of 3.5 percent senior unsecured notes due 2030.~~

On May 8, 2020, Transco issued $700 million of 3.25 percent senior unsecured notes due 2030 and $500 million of 3.95 percent senior unsecured notes due 2050 to investors in a private debt placement. As part of the issuance, Transco entered into a registration rights agreement with the initial purchasers of the unsecured notes. Transco 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. Transco is required to provide a shelf registration statement to cover resales of the notes under certain circumstances. If Transco 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.

~~We retired $1.5 billion of 5.25 percent senior unsecured notes that matured on March 15, 2020.~~

~~We retired $14 million of 8.75 percent senior unsecured notes that matured on January 15, 2020.~~

~~Commercial Paper Program~~

~~At September 30, 2020, $40 million of~~ ~~Commercial paper~~ ~~was outstanding under our $4 billion commercial paper program with a weighted average interest rate of 0.35 percent.~~

~~Credit Facilities~~

September 30, 2020
Stated Capacity Outstanding
(Millions)
Long-term credit facility (1) $ 4,500 $ 0
Letters of credit under certain bilateral bank agreements 15

~~Note 11~~9 – Stockholders’ Equity

Stockholder Rights Agreement

~~On March 19, 2020,~~As disclosed in our board of directors approved the adoption of a limited duration stockholder rights agreement (Rights Agreement) and declared a distribution of 1 preferred stock purchase right for each outstanding share of common stock. The Rights Agreement is intended to protect the interests of us and our stockholders by reducing the likelihood of another party gaining control of or significant influence over us without paying an

~~Notes (Continued)~~

appropriate premium considering recent volatile markets. Each preferred stock purchase right represents the right to purchase, upon certain terms and conditions, one one-thousandth (.001) of a share of Series C Participating Cumulative Preferred Stock, $1.00 par value per share. Each one-thousandth (.001) of a share of Series C Participating Cumulative Preferred Stock, if issued, would have rights similar to one share of our common stock. The distribution of preferred stock purchase rights occurred on March 30, 2020, to holders of record as of the close of business on that date. The Rights Agreement expires on March 20, 2021. Please see our CurrentAnnual Report on Form ~~8-K dated March 20, 2020, for additional details of the Rights Agreement.~~

~~On August 27, 2020,~~10-K filed February 24, 2021, a purported shareholder filed a putative class action lawsuit in the Delaware Court of Chancery challenging ~~the Rights Agreement. The plaintiff alleges that the individual members of~~ our ~~board of directors breached their fiduciary duties by adopting the Rights Agreement. The complaint seeks declaratory relief, an injunction against the~~stockholder rights agreement ~~and an award of attorneys’ fees and costs, which are not expected to be material.~~(Rights Agreement). On ~~September 3, 2020, a purported shareholder filed a separate putative class action lawsuit in~~February 26, 2021, the Delaware Court of Chancery ~~asserting identical claims to~~issued a decision which declared the ~~August 27, 2020 lawsuit. The court consolidated~~Rights Agreement unenforceable and permanently enjoined the ~~lawsuits, and trial is scheduled to begin January 11,~~continued operation of the Rights Agreement, which otherwise would have expired on March 20, 2021.

Notes (Continued)

AOCI

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


		Cash Flow Hedges		Foreign Currency Translation		Pension and Other Postretirement Benefits		Total			Cash Flow Hedges		Foreign Currency Translation		Pension and Other Postretirement Benefits		Total
		(Millions)									(Millions)
Balance at December 31, 2019		$	(2)	$	(1)	$	(196)	$	(199)
Balance at December 31, 2020										Balance at December 31, 2020	$	(3)	$	(1)	$	(92)	$	(96)

Other comprehensive income (loss) before reclassifications	Other comprehensive income (loss) before reclassifications	0		0		20		20		Other comprehensive income (loss) before reclassifications	(9)		0		0		(9)
Amounts reclassified from accumulated other comprehensive income (loss)	Amounts reclassified from accumulated other comprehensive income (loss)	0		0		19		19		Amounts reclassified from accumulated other comprehensive income (loss)	2		0		3		5
Other comprehensive income (loss)	Other comprehensive income (loss)	0		0		39		39		Other comprehensive income (loss)	(7)		0		3		(4)

Balance at September 30, 2020		$	(2)	$	(1)	$	(157)	$	(160)
Balance at March 31, 2021										Balance at March 31, 2021	$	(10)	$	(1)	$	(89)	$	(100)

Reclassifications out of AOCI are presented in the following table by component for the ~~nine~~three months ended ~~September 30, 2020:~~March 31, 2021:

Component

Reclassifications

Classification

(Millions)

Cash flow hedges:

Energy commodity contracts

Product sales

Pension and other postretirement benefits:

Amortization of actuarial (gain) loss and net actuarial loss from settlements included in net periodic benefit cost (credit)

254

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

Income tax benefit

~~(6)~~(1)

Provision (benefit) for income taxes

Reclassifications during the period

195

2419

Notes (Continued)

Note 10 – Fair Value Measurements and Guarantees

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


					Fair Value Measurements Using
	Carrying Amount		Fair Value		Quoted Prices In Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
	(Millions)
Assets (liabilities) at March 31, 2021:
Measured on a recurring basis:
ARO Trust investments	$	243	$	243	$	243	$	0	$	0




Additional disclosures:

Long-term debt, including current portion	(23,234)		(26,798)		0		(26,798)		0
Guarantees	(40)		(26)		0		(10)		(16)

Assets (liabilities) at December 31, 2020:
Measured on a recurring basis:
ARO Trust investments	$	235	$	235	$	235	$	0	$	0



Additional disclosures:
Long-term debt, including current portion	(22,344)		(27,043)		0		(27,043)		0
Guarantees	(40)		(27)		0		(11)		(16)

Fair Value Methods

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

Assets 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 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.

Additional fair value disclosures

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

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.

Notes (Continued)

To estimate the fair value of the WilTel guarantee, an estimated default rate is applied to the sum of the future contractual lease payments using an income approach. The estimated default rate is determined by obtaining the average cumulative issuer-weighted corporate default rate based on the credit rating of WilTel’s current owner and the term of the underlying obligation. The default rate is published by Moody’s Investors Service. The carrying value of the WilTel guarantee is reported in Accrued liabilities in the Consolidated Balance Sheet. The maximum potential undiscounted exposure is approximately $26 millionat March 31, 2021. Our exposure declines systematically through the remaining term of WilTel’s obligation.

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

We are required by our revolving credit agreement to indemnify lenders for certain taxes required to be withheld from payments due to the lenders and for certain tax payments made by the lenders. The maximum potential amount of future payments under these indemnifications is based on the related borrowings and such future payments cannot currently be determined. These indemnifications generally continue indefinitely unless limited by the underlying tax regulations and have 0 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

During the first quarter of 2020, we observed a significant decline in the publicly traded price of our common stock (NYSE: WMB), which declined 40 percent during the quarter, including a 26 percent decline in the month of March. These changes were generally attributed to macroeconomic and geopolitical conditions, including significant declines in crude oil prices driven by both surplus supply and a decrease in demand caused by the coronavirus (COVID-19) pandemic. As a result of these conditions, we performed an interim assessment of the goodwill associated with our Northeast G&P reporting unit as of March 31, 2020.

The assessment considered the total fair value of the businesses within the Northeast G&P reporting unit, which was determined using income and market approaches. We utilized internally developed industry weighted-average discount rates and estimates of valuation multiples of comparable publicly traded gathering and processing companies. In assessing the fair value as of the March 31, 2020 measurement date, we were required to consider recent publicly available indications of value, which included lower observed publicly traded EBITDA (earnings before interest, taxes, depreciation, and amortization) market multiples as compared with recent history and significantly higher industry weighted-average discount rates. The fair value of the reporting unit was further reconciled to our estimated total enterprise value as of March 31, 2020, which considered observable valuation multiples of comparable publicly traded companies applied to each distinct business including the Northeast G&P reporting unit. This assessment indicated that the estimated fair value of the Northeast G&P reporting unit was below its carrying value, including goodwill. As a result of this Level 3 measurement, we recognized a full impairment charge of $187 million as of March 31, 2020, in Impairment of goodwill in the Consolidated Statement of Operations. Our partner’s $65 million share of this impairment is reflected within Net income (loss) attributable to noncontrolling interests in the Consolidated Statement of Operations.

Notes (Continued)

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


					Impairments
					Three Months Ended March 31,
	Segment	Date of Measurement	Fair Value		2021		2020
			(Millions)





Impairment of equity-method investments:
RMM (1)	West	March 31, 2020	$	557			$	243
Brazos Permian II (1)	West	March 31, 2020	0				193
Caiman II (2)	Northeast G&P	March 31, 2020	191				229
Appalachia Midstream Investments (2)	Northeast G&P	March 31, 2020	2,700				127
Aux Sable (2)	Northeast G&P	March 31, 2020	7				39
Laurel Mountain (2)	Northeast G&P	March 31, 2020	236				10
Discovery (2)	Transmission & Gulf of Mexico	March 31, 2020	367				97





Impairment of equity-method investments					$	0	$	938

_______________

(1)Following the previously described declining market conditions during the first quarter of 2020, we evaluated these investments for other-than-temporary impairment. The fair value was measured using an income approach. Both investees operate in primarily oil-driven basins where significant expected reductions in producer activities led to reduced estimates of expected future cash flows. Our fair value estimates also reflected discount rates of approximately 17 percent for these investments. We also considered any debt held at the investee level, and its impact to fair value. The industry weighted-average discount rates utilized were significantly influenced by the market declines previously discussed.

(2)Following the previously described declining market conditions during the first quarter of 2020, we evaluated these investments for other-than-temporary impairment. The impairments within our Northeast G&P segment are primarily associated with operations in wet-gas areas where producer drilling activities are influenced by NGL prices which historically trend with crude oil prices. The fair values of our investments in Caiman II and Aux Sable Liquid Products LP (Aux Sable) were estimated using a market approach, reflecting valuation multiples ranging from 5.0x to 6.2x EBITDA (weighted-average 6.0x). The fair values of the other investments, including gathering systems that are part of Appalachia Midstream Investments, were estimated using an income approach, with discount rates ranging from 9.7 percent to 13.5 percent (weighted-average 12.6 percent). We also considered any debt held at the investee level, and its impact to fair value. The assumed valuation multiples and industry weighted-average discount rates utilized were both significantly influenced by the market declines previously discussed.

Note ~~12 – Fair Value Measurements and Guarantees~~

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

Fair Value Measurements Using
Carrying
Amount Fair
Value Quoted
Prices In
Active
Markets for
Identical
Assets
(Level 1) Significant
Other
Observable
Inputs
(Level 2) Significant
Unobservable
Inputs
(Level 3)
(Millions)
Assets (liabilities) at September 30, 2020:
Measured on a recurring basis:
ARO Trust investments $ 220 $ 220 $ 220 $ 0 $ 0
Additional disclosures:
Long-term debt, including current portion (22,343) (26,000) 0 (26,000) 0
Guarantees (41) (27) 0 (11) (16)
Assets (liabilities) at December 31, 2019:
Measured on a recurring basis:
ARO Trust investments $ 201 $ 201 $ 201 $ 0 $ 0
Additional disclosures:
Long-term debt, including current portion (22,288) (25,319) 0 (25,319) 0
Guarantees (41) (27) 0 (11) (16)

~~Fair Value Methods~~

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

~~Assets and liabilities measured at fair value on a recurring basis~~

~~ARO Trust investments~~: Transco deposits a portion of its collected rates, pursuant to its rate case settlement, into an external trust (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 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.~~

~~Additional fair value disclosures~~

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

~~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.

~~Notes (Continued)~~

To estimate the fair value of the WilTel guarantee, an estimated default rate is applied to the sum of the future contractual lease payments using an income approach. The estimated default rate is determined by obtaining the average cumulative issuer-weighted corporate default rate based on the credit rating of WilTel’s current owner and the term of the underlying obligation. The default rate is published by Moody’s Investors Service. The carrying value of the WilTel guarantee is reported in ~~Accrued liabilities~~ ~~in the Consolidated Balance Sheet. The maximum potential undiscounted exposure is approximately $27 millionat September 30, 2020. 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.~~

~~Nonrecurring fair value measurements~~

During the first quarter of 2020, we observed a significant decline in the publicly traded price of our common stock (NYSE: WMB), which declined 40 percent during the quarter, including a 26 percent decline in the month of March. These changes were generally attributed to macroeconomic and geopolitical conditions, including significant declines in crude oil prices driven by both surplus supply and a decrease in demand caused by the novel coronavirus (COVID-19) pandemic. As a result of these conditions, we performed an interim assessment of the goodwill associated with our Northeast G&P reporting unit as of March 31, 2020. This goodwill resulted from the March 2019 acquisition of UEOM (see Note 2 – Acquisitions).

The assessment considered the total fair value of the businesses within the Northeast G&P reporting unit, which was determined using income and market approaches. We utilized internally developed industry weighted-average discount rates and estimates of valuation multiples of comparable publicly traded gathering and processing companies. In assessing the fair value as of the March 31, 2020 measurement date, we were required to consider recent publicly available indications of value, which included lower observed publicly traded EBITDA (earnings before interest, taxes, depreciation, and amortization) market multiples as compared with recent history and significantly higher industry weighted-average discount rates. The fair value of the reporting unit was further reconciled to our estimated total enterprise value as of March 31, 2020, which considered observable valuation multiples of comparable publicly traded companies applied to each distinct business including the Northeast G&P reporting unit. This assessment indicated that the estimated fair value of the Northeast G&P reporting unit was below its carrying value, including goodwill. As a result of this Level 3 measurement, we recognized a full impairment charge of $187 million as of March 31, 2020, in ~~Impairment of goodwill~~ ~~in the Consolidated Statement of Income. Our partner’s $65 million share of this impairment is reflected within~~ ~~Net income (loss) attributable to noncontrolling interests~~ ~~in the Consolidated Statement of Income (see Note 2 – Acquisitions).~~

~~Notes (Continued)~~

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, except as specifically noted.

Impairments
Nine Months Ended
September 30,
Segment Date of Measurement Fair Value 2020 2019
(Millions)
Impairment of certain assets:
Certain gathering assets (1) West June 30, 2019 $ 40 $ 59
Certain idle gathering assets (2) West March 31, 2019 0 12
Other impairments and write-downs 5
Impairment of certain assets $ 76
Impairment of equity-method investments:
RMM (3) West March 31, 2020 $ 557 $ 243
Brazos Permian II (3) West March 31, 2020 0 193
Caiman II (4) Northeast G&P March 31, 2020 191 229
Appalachia Midstream Investments (4) Northeast G&P March 31, 2020 2,700 127
Aux Sable (4) Northeast G&P March 31, 2020 7 39
Laurel Mountain (4) Northeast G&P March 31, 2020 236 10
Discovery (4) Transmission & Gulf of Mexico March 31, 2020 367 97
Laurel Mountain (5) Northeast G&P September 30, 2019 242 $ 79
Appalachia Midstream Investments (6) Northeast G&P September 30, 2019 102 17
Pennant (7) Northeast G&P August 31, 2019 11 17
UEOM (8) Northeast G&P March 17, 2019 1,210 74
Other 0 (1)
Impairment of equity-method investments $ 938 $ 186

~~_______________~~

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

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

~~(3)~~Following the previously described declining market conditions during the first quarter of 2020, we evaluated these investments for other-than-temporary impairment. The fair value was measured using an income approach. Both investees operate in primarily oil-driven basins where significant expected reductions in producer activities led to reduced estimates of expected future cash flows. Our fair value estimates also reflected discount rates of approximately 17 percent for these investments. We also considered any debt held at the investee level, and its impact to fair value. The industry weighted-average discount rates utilized were significantly influenced by the recent market declines previously discussed.

~~Notes (Continued)~~

~~(4)~~Following the previously described declining market conditions during the first quarter of 2020, we evaluated these investments for other-than-temporary impairment. The impairments within our Northeast G&P segment are primarily associated with operations in wet-gas areas where producer drilling activities are influenced by NGL prices which historically trend with crude oil prices. The fair values of our investments in Caiman II and Aux Sable Liquid Products LP (Aux Sable) were estimated using a market approach, reflecting valuation multiples ranging from 5.0x to 6.2x EBITDA (weighted-average 6.0x). The fair values of the other investments, including gathering systems that are part of Appalachia Midstream Investments, were estimated using an income approach, with discount rates ranging from 9.7 percent to 13.5 percent (weighted-average 12.6 percent). We also considered any debt held at the investee level, and its impact to fair value. The assumed valuation multiples and industry weighted-average discount rates utilized were both significantly influenced by the recent market declines previously discussed.

~~(5)~~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.

~~(6)~~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.

~~(7)~~The estimated fair value of Pennant Midstream, LLC (Pennant) was determined by a market approach based on recent observable third-party transactions. These inputs resulted in a fair value measurement within Level 2 of the fair value hierarchy.

~~(8)~~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 closing of the acquisition in March 2019 (see Note 2 – Acquisitions). These inputs resulted in a fair value measurement within Level 2 of the fair value hierarchy.

~~Note 13~~11 – Contingent Liabilities

Reporting of Natural Gas-Related Information to Trade Publications

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

Notes (Continued)

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 been~~ remanded to its originally filed court, the Kansas federal district court where we re-urged our motion for summary judgment. The district court denied the motion but granted our request to seek permission for an immediate appeal to the appellate court. Oral argument occurred before the appellate court on January 19, 2021, and we await the appellate court’s ruling.

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

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

~~Notes (Continued)~~

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. Trial iswas scheduled to begin June 14, ~~2021.~~2021, but the court struck the setting and has not reset it.

Because of the uncertainty around the remaining unresolved issues, we cannot reasonably estimate a range of potential exposure at this time. However, it is reasonably possible that the ultimate resolution of these actions and our related indemnification obligation could result in a potential loss that may be material to our results of operations. In connection with this indemnification, we have an accrued liability balance associated with this matter and, as a result, have exposure to future developments.

Alaska Refinery Contamination Litigation

We are involved in litigation arising from our ownership and operation of the North Pole Refinery in North Pole, Alaska, from 1980 until 2004, through our wholly owned subsidiaries Williams Alaska Petroleum Inc. (WAPI) and MAPCO Inc. We sold the refinery to Flint Hills Resources Alaska, LLC (FHRA), a subsidiary of Koch Industries, Inc., in 2004. The litigation involves three cases, with filing dates ranging from 2010 to 2014. The actions primarily arise from sulfolane contamination allegedly emanating from the refinery. A putative class action lawsuit was filed by James West in 2010 naming us, WAPI, and FHRA as defendants. We and FHRA filed claims against each other seeking, among other things, contractual indemnification alleging that the other party caused the sulfolane contamination. In 2011, we and FHRA settled the claim with James West. Certain claims by FHRA against us were resolved by the Alaska Supreme Court in our favor. FHRA’s claims against us for contractual indemnification and statutory claims for damages related to off-site sulfolane were remanded to the Alaska Superior Court. The State of Alaska filed its action in March 2014, seeking damages. The City of North Pole (North Pole) filed its lawsuit in November 2014, seeking past and future damages, as well as punitive damages. Both we and WAPI asserted counterclaims against the State of Alaska and North Pole, and cross-claims against FHRA. FHRA has also filed cross-claims against us.

The underlying factual basis and claims in the cases are similar and may duplicate exposure. As such, in February 2017, the three cases were consolidated into one action in state court containing the remaining claims from the James West case and those of the State of Alaska and North Pole. The State of Alaska later announced the discovery of additional contaminants per- and polyfluoralkyl (PFOS and PFOA) offsite of the refinery, and the court permitted the State of Alaska to amend its complaint to add a claim for offsite PFOS/PFOA contamination. The court subsequently remanded the offsite PFOS/PFOA claims to the Alaska Department of Environmental Conservation for investigation and stayed the claims pending their potential resolution at the administrative agency. Several trial dates encompassing all three cases have been scheduled and stricken. In the summer of 2019, the court

Notes (Continued)

deconsolidated the cases for purposes of trial. A bench trial on all claims except North Pole’s claims began in October 2019.

In January 2020, the Alaska Superior Court issued its Memorandum of Decision finding in favor of the State of Alaska and FHRA, with the total incurred and potential future damages estimated to be $86 million. The court found that FHRA is not entitled to contractual indemnification from us because FHRA contributed to the sulfolane contamination. On March 23, 2020, the court entered final judgment in the case. Filing deadlines were stayed until May 1, 2020. However, on April 21, 2020, we filed a Notice of Appeal. We also filed post-judgment motions including a Motion for New Trial and a Motion to Alter or Amend the Judgment. These post-trial motions ~~have now been~~were resolved with the court’s denial of the last motion on June 11, 2020. Our Statement of Points on Appeal was filed on July 13, 2020. On June 22, 2020, the court stayed the North Pole’s case pending resolution of the appeal in the State of Alaska and FHRA case. On December 23, 2020, we filed our opening brief on appeal. We have recorded an accrued liability in the amount of our estimate of the probable loss. It is reasonably possible that we may not be successful on appeal and could ultimately pay up to the amount of judgment.

~~Notes (Continued)~~

Royalty Matters

Certain of our customers, including Chesapeake Energy Corporation (Chesapeake), have been named in various lawsuits alleging underpayment of royalties and claiming, among other things, violations of anti-trust laws and the Racketeer Influenced and Corrupt Organizations Act. We have also been named as a defendant in certain of these cases filed in Pennsylvania based on allegations that we improperly participated with Chesapeake in causing the alleged royalty underpayments. We believe that the claims asserted are subject to indemnity obligations owed to us by Chesapeake. Chesapeake has reached a ~~tentative~~ settlement to resolve substantially all Pennsylvania royalty cases pending, which settlement ~~would apply~~applies to both Chesapeake and us. The settlement ~~as reported would~~does not require any contribution from ~~us. On June 28, 2020, Chesapeake filed for Chapter 11 bankruptcy protection in the United States Bankruptcy Court for the Southern District of Texas.~~us and is awaiting court approval.

Litigation Against Energy Transfer and Related Parties

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

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

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

Notes (Continued)

Court of Chancery’s ruling. On March 30, 2017, we filed a motion for reargument with the Supreme Court of Delaware, which was denied on April 5, 2017.

On September 16, 2016, we filed an amended complaint with the Court of Chancery seeking damages for breaches of the ETE Merger Agreement by defendants. On September 23, 2016, Energy Transfer filed a second amended and supplemental affirmative defenses and verified counterclaim with the Court of Chancery seeking, among other things, payment of the $1.48 billion termination fee due to our alleged breaches of the ETE Merger Agreement. On December 1, 2017, the court granted our motion to dismiss certain of Energy Transfer’s counterclaims, including its claim seeking payment of the $1.48 billion termination fee. On December 8, 2017, Energy Transfer filed a motion for reargument, which the Court of Chancery denied on April 16, 2018. The Court of Chancery ~~had~~originally scheduled trial for May 20 through May 24, 2019; the court struck ~~this~~that setting and reset ~~the~~ trial ~~for June 8 through June 11, and June 15,~~to occur in 2020. ~~Due~~All 2020 trial settings were struck due to ~~COVID-19, the court struck the June 2020 setting and re-scheduled the trial for August 31 through September 4, 2020; this setting was also struck as a result of~~ COVID-19. Trial has been reset for ~~December 14~~May 10 through ~~December 18, 2020.~~

~~Notes (Continued)~~

~~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 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. Trial is currently reset for November 4, 2020. 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.

~~Other~~

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, and on December 31, 2019, we filed a formal stipulation and agreement with the FERC setting forth such terms of settlement. On March 24, 2020, the FERC issued an order approving the uncontested rate case settlement, which became effective on June 1, 2020. Rate refunds related to the increased rates collected prior to the effective date of the settlement were paid on July 1, 2020.May 17, 2021.

Environmental Matters

We are a participant in certain environmental activities in various stages including assessment studies, cleanup operations, and/or remedial processes at certain sites, some of which we currently do not own. We are monitoring these sites in a coordinated effort with other potentially responsible parties, the U.S. Environmental Protection Agency (EPA), or other governmental authorities. We are jointly and severally liable along with unrelated third parties in some of these activities and solely responsible in others. Certain of our subsidiaries have been identified as potentially responsible parties at various Superfund and state waste disposal sites. In addition, these subsidiaries have incurred, or are alleged to have incurred, various other hazardous materials removal or remediation obligations under environmental laws. As of ~~September 30, 2020,~~March 31, 2021, we have accrued liabilities totaling ~~$34~~$33 million for these matters, as discussed below. Estimates of the most likely costs of cleanup are generally based on completed assessment studies, preliminary results of studies, or our experience with other similar cleanup operations. At ~~September 30, 2020,~~March 31, 2021, certain assessment studies were still in process for which the ultimate outcome may yield different estimates of most likely costs. Therefore, the actual costs incurred will depend on the final amount, type, and extent of contamination discovered at these sites, the final cleanup standards mandated by the EPA or other governmental authorities, and other factors.

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

~~Notes (Continued)~~

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, 2020,~~March 31, 2021, we have accrued liabilities of $4 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, 2020,~~March 31, 2021, we have accrued liabilities totaling $8 million for these costs.

Notes (Continued)

Former operations

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

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

•Former petroleum products and natural gas pipelines;

•Former petroleum refining facilities;

•Former exploration and production and mining operations;

•Former electricity and natural gas marketing and trading operations.

At ~~September 30, 2020,~~March 31, 2021, we have accrued environmental liabilities of ~~$22~~$21 million related to these matters.

Other Divestiture Indemnifications

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

At ~~September 30, 2020,~~March 31, 2021, other than as previously disclosed, we are not aware of any material claims against us involving the above-described indemnities; thus, we do not expect any of the indemnities provided pursuant to the sales agreements to have a material impact on our future financial position. Any claim for indemnity brought against us in the future may have a material adverse effect on our results of operations in the period in which the claim is made.

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

Summary

We have disclosed our estimated range of reasonably possible losses for certain matters above, as well as all significant matters for which we are unable to reasonably estimate a range of possible loss. We estimate that for all other matters for which we are able to reasonably estimate a range of loss, our aggregate reasonably possible losses

~~Notes (Continued)~~

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 12 – Segment Disclosures

Our reportable segments are Transmission & Gulf of Mexico, Northeast G&P, and West. All remaining business activities are included in Other. (See Note 1 – General, Description of Business, and Basis of Presentation.)

Performance Measurement

We evaluate segment operating performance based upon Modified EBITDA. 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

Notes (Continued)

primarily represent the sale of NGLs from our natural gas processing plants and transportation services provided to our marketing business.

We define Modified EBITDA as follows:

•Net income (loss) before:

◦Provision (benefit) for income taxes;

◦Interest incurred, net of interest capitalized;

◦Equity earnings (losses);

◦Impairment of equity-method investments;

◦Other investing income (loss) – net;

◦Impairment of goodwill;

◦Depreciation and amortization expenses;

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

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

Notes (Continued)

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


	Transmission & Gulf of Mexico		Northeast G&P		West		Other		Eliminations		Total
	(Millions)


























Three Months Ended March 31, 2021
Segment revenues:
Service revenues
External	$	822	$	347	$	279	$	4	$	—	$	1,452
Internal	12		11		5		3		(31)		—
Total service revenues	834		358		284		7		(31)		1,452
Total service revenues – commodity consideration	11		3		35		0		0		49
Product sales
External	40		4		1,018		49		—		1,111
Internal	27		28		28		7		(90)		—
Total product sales	67		32		1,046		56		(90)		1,111
Total revenues	$	912	$	393	$	1,365	$	63	$	(121)	$	2,612

Three Months Ended March 31, 2020
Segment revenues:
Service revenues
External	$	814	$	344	$	311	$	5	$	—	$	1,474
Internal	15		14		0		3		(32)		—
Total service revenues	829		358		311		8		(32)		1,474
Total service revenues – commodity consideration	5		2		21		0		0		28
Product sales
External	41		23		347		0		—		411
Internal	11		6		12		0		(29)		—
Total product sales	52		29		359		0		(29)		411
Total revenues	$	886	$	389	$	691	$	8	$	(61)	$	1,913

March 31, 2021
Total assets (1)	$	19,395	$	14,464	$	10,533	$	2,225	$	(1,355)	$	45,262
December 31, 2020
Total assets	$	19,110	$	14,569	$	10,558	$	927	$	(999)	$	44,165

______________

(1) The increase at our Other segment is primarily due to increased cash balance and the February 2021 acquisition of oil and gas properties, primarily comprised of approximately 2,000 operated wells, in the Wamsutter basin in Wyoming from a supermajor oil and gas company for approximately $79 million, a portion of which was paid in the prior year. We are working to identify an operating partner to optimize development of the properties and enhance the value of our connected midstream infrastructure. Our oil and gas exploration and production activities are accounted for under the successful efforts method. We recorded $290 million of property, plant, and equipment and $207 million of ARO related to this transaction.

Notes (Continued)

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


	Three Months Ended March 31,
		2021		2020
		(Millions)
Modified EBITDA by segment:
Transmission & Gulf of Mexico		$	660	$	662
Northeast G&P		402		369
West		315		215
Other		33		7
		1,410		1,253
Accretion expense associated with asset retirement obligations for nonregulated operations		(10)		(10)
Depreciation and amortization expenses		(438)		(429)
Impairment of goodwill		0		(187)
Equity earnings (losses)		131		22
Impairment of equity-method investments		0		(938)
Other investing income (loss) – net		2		3
Proportional Modified EBITDA of equity-method investments		(225)		(192)
Interest expense		(294)		(296)
(Provision) benefit for income taxes		(141)		204

Net income (loss)		$	435	$	(570)

~~Note 14 – Segment Disclosures~~Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

General

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

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

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

Consistent with the manner in which our chief operating decision maker evaluates performance and allocates resources, our operations are conducted, managed, and presented within the following reportable ~~segments are~~segments: Transmission & Gulf of Mexico, Northeast G&P, and West. All remaining business activities, including our recently acquired upstream operations, as well as corporate activities are included in Other. ~~(See~~Our reportable segments are comprised of the following businesses:

•Transmission & Gulf of Mexico is comprised of our interstate natural gas pipelines, Transco and Northwest Pipeline, as well as 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 VIE), which is a proprietary floating production system, a 50 percent equity-method investment in Gulfstream, and a 60 percent equity-method investment in Discovery.

•Northeast G&P is comprised of our midstream gathering, processing, and fractionation businesses in the Marcellus Shale region primarily in Pennsylvania and New York, and the Utica Shale region of eastern Ohio, as well as a 65 percent interest in our Northeast JV (a consolidated VIE) which operates in West Virginia, Ohio, and Pennsylvania, a 66 percent interest in Cardinal (a consolidated VIE) which operates in Ohio, a 69 percent equity-method investment in Laurel Mountain, a 50 percent equity-method investment in Blue Racer (we previously effectively owned a 29 percent indirect interest in Blue Racer through our 58 percent equity-method investment in Caiman II until acquiring a controlling interest in November 2020), and Appalachia Midstream Investments, a wholly owned subsidiary that owns equity-method investments with an approximate average 66 percent interest in multiple gas gathering systems in the Marcellus Shale region.

•West is comprised of our gas gathering, processing, and treating operations in the Rocky Mountain region of Colorado and Wyoming, the Barnett Shale region of north-central Texas, the Eagle Ford Shale region of south Texas, the Haynesville Shale region of northwest Louisiana, and the Mid-Continent region which includes the Anadarko, Arkoma, and Permian basins. This segment also includes our NGL and natural gas marketing business, storage facilities, an undivided 50 percent interest in an NGL fractionator near Conway, Kansas, a 50 percent equity-method investment in OPPL, a 50 percent equity-method investment in RMM, a 20 percent equity-method investment in Targa Train 7, and a 15 percent interest in Brazos Permian II.

Management’s Discussion and Analysis (Continued)

Dividends

In March 2021, we paid a regular quarterly dividend of $0.41 per share.

Overview of Three Months Ended March 31, 2021

Net income (loss) attributable to The Williams Companies, Inc., for the three months ended March 31, 2021, increased $943 millioncompared to the three months ended March 31, 2020, reflecting:

•The absence of $938 million of Impairment of equity-method investments in the first quarter of 2020;

•The absence of $187 million of Impairment of goodwill in 2020, of which $65 million was attributable to noncontrolling interests;

•A $128 million favorable change in our commodity margins primarily due to increases in net realized sales prices and volumes. Our commodity margins are comprised of the net sum of Service revenues – commodity consideration, Product sales, Product costs, and Processing commodity expenses; however, Product sales at our Other segment reflect sales related to our recently acquired upstream operations and are excluded from our commodity margins;

•A $109 million increase in equity earnings, primarily due to the absence of our $78 million share of an impairment of goodwill recorded by an equity-method investee in 2020;

•A $49 million increase in Product sales at our Other segment reflecting sales related to our recently acquired upstream operations.

These favorable changes were partially offset by:

•A $345 million unfavorable change in provision for income taxes, driven by higher pre-tax earnings;

•$23 million of higher Operating and maintenance expenses primarily due to the inclusion of our recently acquired upstream operations at our Other segment and higher employee-related expenses;

•$22 million of lower Service revenues primarily due to lower volumes and rates.

The following discussion and analysis of results 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 Report on Form 10-K dated February 24, 2021.

Recent Developments

Expansion Project Update

Transmission & Gulf of Mexico

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 placed 230 Mdth/d of capacity under the project into service in the fourth quarter of 2020, and the project was fully in service on January 1, 2021. In total, the project increased capacity by 296 Mdth/d.

COVID-19

The outbreak of COVID-19 has severely impacted global economic activity and caused significant volatility and negative pressure in financial markets. We continue to monitor the COVID-19 pandemic and have taken steps intended to protect the safety of our customers, employees, and communities, and to support the continued delivery

Management’s Discussion and Analysis (Continued)

of safe and reliable service to our customers and the communities we serve. Our financial condition, results of operations, and liquidity have not been materially impacted by direct effects of COVID-19.

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 2021 includes a continued focus on earnings and cash flow growth, while continuing to improve leverage metrics and control operating costs.

In 2021, our operating results are expected to benefit from growth in our Northeast G&P gathering and processing volumes. We also anticipate increases from recently completed Transco expansion projects and higher Gulf of Mexico results primarily due to lower planned hurricane impacts. Our results also benefited from the overall net favorable impact of unusually high natural gas prices in the first quarter, including contributions from certain of our recently acquired upstream properties. These increases will be partially offset by a decrease in West results, including a reduction in NGL transportation volumes on OPPL and certain fee reductions in the Haynesville area in exchange for upstream value in natural gas properties. We also expect a modest increase in expenses, including higher operating taxes.

Our growth capital and investment expenditures in 2021 are expected to be in a range from $1.0 billion to $1.2 billion. Growth capital spending in 2021 primarily includes Transco expansions, all of which are fully contracted with firm transportation agreements, and projects supporting the Northeast G&P business and opportunities in the Haynesville area. In addition to growth capital and investment expenditures, we also remain committed to projects that maintain our assets for safe and reliable operations, as well as projects that meet legal, regulatory, and/or contractual commitments.

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

•Continued negative impacts of COVID-19 driving a global recession, which could result in further downturns in financial markets and commodity prices, as well as impact demand for natural gas and related products;

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

•Counterparty credit and performance risk, including unexpected developments in customer bankruptcy proceedings;

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

•Unexpected changes in customer drilling and 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 downturns, including increased interest rates;

•Physical damages to facilities, including damage to offshore facilities by weather-related events;

•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, 2020, as filed with the SEC on February 24, 2021.

Management’s Discussion and Analysis (Continued)

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

Expansion Projects

Our ongoing major expansion projects include the following:

Transmission & Gulf of Mexico

Leidy South

In July 2020, we received approval from the FERC for 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 placed 125 Mdth/d of capacity under the project into service in the fourth quarter of 2020, and we plan to place the remainder of the project into service as early as the fourth quarter of 2021. The project is expected to increase capacity by 582 Mdth/d.

Regional Energy Access

In March 2021, we filed an application with the FERC for the project to expand Transco’s existing natural gas transmission system to provide incremental firm transportation capacity from receipt points in northeastern Pennsylvania to multiple delivery points in Pennsylvania, New Jersey, and Maryland. We plan to place the project into service as early as the fourth quarter of 2023, assuming timely receipt of all necessary regulatory approvals. The project is expected to increase capacity by 829 Mdth/d.

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 months ended March 31, 2021, compared to the three months ended March 31, 2020. The results of operations by segment are discussed in further detail following this consolidated overview discussion.


	Three Months Ended March 31,
		2021		2020		$ Change*	% Change*
	(Millions)
Revenues:
Service revenues		$	1,452	$	1,474	-22	-1	%
Service revenues – commodity consideration		49		28		+21	+75	%
Product sales		1,111		411		+700	+170	%
Total revenues		2,612		1,913
Costs and expenses:
Product costs		932		396		-536	-135	%
Processing commodity expenses		21		13		-8	-62	%
Operating and maintenance expenses		360		337		-23	-7	%
Depreciation and amortization expenses		438		429		-9	-2	%
Selling, general, and administrative expenses		123		113		-10	-9	%

Impairment of goodwill		—		187		+187	+100	%
Other (income) expense – net		(1)		7		+8	NM
Total costs and expenses		1,873		1,482
Operating income (loss)		739		431
Equity earnings (losses)		131		22		+109	NM
Impairment of equity-method investments		—		(938)		+938	+100	%
Other investing income (loss) – net		2		3		-1	-33	%
Interest expense		(294)		(296)		+2	+1	%
Other income (expense) – net		(2)		4		-6	NM
Income (loss) before income taxes		576		(774)
Less: Provision (benefit) for income taxes		141		(204)		-345	NM


Net income (loss)		435		(570)
Less: Net income (loss) attributable to noncontrolling interests		9		(53)		-62	NM
Net income (loss) attributable to The Williams Companies, Inc.		$	426	$	(517)

* + = 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.

Three months ended March 31, 2021 vs. three months ended March 31, 2020

Service revenues decreased primarily due to lower volumes driven by production declines and lower gathering and processing rates, both in our West segment, as well as producer operational issues at certain offshore Gulf of Mexico operations. This decrease was partially offset by higher MVC revenue in our West segment and higher transportation fee revenues associated with expansion projects placed in service at Transco in 2020.

Service revenues – commodity consideration increased primarily due to higher NGL prices. 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 during the month processed and therefore are offset within Product costs below.

Management’s Discussion and Analysis (Continued)

Product sales increased primarily due to higher net realized prices and higher volumes associated with our marketing activities, and the inclusion of our recently acquired upstream operations (see Note 112 – ~~General, Description~~Segment Disclosures of ~~Business,~~Notes to Consolidated Financial Statements). This increase also includes higher prices related to our equity NGL sales activities. Marketing sales are partially offset within Product costs.

Product costs increased primarily due to higher prices and ~~Basis~~higher volumes for our marketing activities, as well as higher NGL prices associated with volumes acquired related to our equity NGL production activities.

The net sum of ~~Presentation.)~~Service revenues – commodity consideration, Product sales, Product costs and Processing commodity expenses comprise our commodity margins. However, Product sales at our Other segment reflect sales related to our oil and gas producing properties and are excluded from our commodity margins.

~~Performance Measurement~~Operating and maintenance expenses increased primarily due to the inclusion of our recently acquired upstream operations and higher employee-related expenses.

Selling, general, and administrative expenses increased primarily due to higher employee-related expenses.

Impairment of goodwill reflects the 2020 charge at the Northeast reporting unit (see Note 10 – Fair Value Measurements and Guarantees of Notes to Consolidated Financial Statements).

Equity earnings (losses) changed favorably primarily due to the absence of the 2020 impairment of goodwill at RMM and due to an increase at Appalachia Midstream Investments, partially offset by a decrease at OPPL.

The change in Impairment of equity-method investments reflects the absence of 2020 impairments to various equity-method investments (see Note 10 – Fair Value Measurements and Guarantees of Notes to Consolidated Financial Statements).

Provision (benefit) for income taxes changed unfavorably primarily due to higher pre-tax income. See Note 5 – 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 change in Net income (loss) attributable to noncontrolling interests is primarily due to the absence of our partner’s share of the 2020 goodwill impairment at the Northeast reporting unit.

Period-Over-Period Operating Results - Segments

We evaluate segment operating performance based upon Modified EBITDA. ~~This measure represents the basis~~Note 12 – Segment Disclosures 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 plantsNotes to ~~our marketing business.~~

~~We define~~ ~~Modified EBITDA~~ ~~as follows:~~

•~~Net income (loss) before:~~

◦~~Provision (benefit) for income taxes;~~

◦~~Interest incurred, net of interest capitalized;~~

◦~~Equity earnings (losses);~~

◦~~Impairment of equity-method investments;~~

◦~~Other investing income (loss) – net;~~

◦~~Impairment of goodwill;~~

◦~~Depreciation and amortization expenses;~~

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

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

~~Notes (Continued)~~

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

Transmission & Gulf of Mexico Northeast G&P West Other Eliminations Total
(Millions)
Three Months Ended September 30, 2020
Segment revenues:
Service revenues
External $ 797 $ 366 $ 311 $ 5 $ — $ 1,479
Internal 10 13 0 3 (26) —
Total service revenues 807 379 311 8 (26) 1,479
Total service revenues – commodity consideration 6 2 32 0 0 40
Product sales
External 34 2 378 0 — 414
Internal 12 10 13 0 (35) —
Total product sales 46 12 391 0 (35) 414
Total revenues $ 859 $ 393 $ 734 $ 8 $ (61) $ 1,933
Three Months Ended September 30, 2019
Segment revenues:
Service revenues
External $ 829 $ 340 $ 322 $ 4 $ — $ 1,495
Internal 13 13 0 3 (29) —
Total service revenues 842 353 322 7 (29) 1,495
Total service revenues – commodity consideration 7 1 30 0 0 38
Product sales
External 66 22 378 0 — 466
Internal 10 8 11 0 (29) —
Total product sales 76 30 389 0 (29) 466
Total revenues $ 925 $ 384 $ 741 $ 7 $ (58) $ 1,999
Nine Months Ended September 30, 2020
Segment revenues:
Service revenues
External $ 2,394 $ 1,052 $ 938 $ 15 $ — $ 4,399
Internal 37 39 0 10 (86) —
Total service revenues 2,431 1,091 938 25 (86) 4,399
Total service revenues – commodity consideration 14 5 74 0 0 93
Product sales
External 104 17 1,014 0 — 1,135
Internal 30 25 39 0 (94) —
Total product sales 134 42 1,053 0 (94) 1,135
Total revenues $ 2,579 $ 1,138 $ 2,065 $ 25 $ (180) $ 5,627

~~Notes (Continued)~~

Transmission & Gulf of Mexico Northeast G&P West Other Eliminations Total
(Millions)
Nine Months Ended September 30, 2019
Segment revenues:
Service revenues
External $ 2,437 $ 925 $ 1,049 $ 13 $ — $ 4,424
Internal 36 34 0 9 (79) —
Total service revenues 2,473 959 1,049 22 (79) 4,424
Total service revenues – commodity consideration 33 9 116 0 0 158
Product sales
External 169 87 1,256 0 — 1,512
Internal 57 27 46 0 (130) —
Total product sales 226 114 1,302 0 (130) 1,512
Total revenues $ 2,732 $ 1,082 $ 2,467 $ 22 $ (209) $ 6,094
September 30, 2020
Total assets $ 19,246 $ 14,526 $ 10,745 $ 756 $ (953) $ 44,320
December 31, 2019
Total assets $ 18,796 $ 15,399 $ 11,265 $ 1,151 $ (571) $ 46,040

~~The following table reflects the reconciliation of~~ ~~Modified EBITDA~~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 ~~reported~~a substitute for a measure of performance prepared in ~~the Consolidated Statement of Income.~~

Three Months Ended
September 30, Nine Months Ended
September 30,
2020 2019 2020 2019
(Millions)
Modified EBITDA by segment:
Transmission & Gulf of Mexico $ 616 $ 665 $ 1,893 $ 1,891
Northeast G&P 387 345 1,126 947
West 247 245 715 713
Other (7) (2) 8 1
1,243 1,253 3,742 3,552
Accretion expense associated with asset retirement obligations for nonregulated operations (10) (8) (27) (25)
Depreciation and amortization expenses (426) (435) (1,285) (1,275)
Impairment of goodwill 0 0 (187) 0
Equity earnings (losses) 106 93 236 260
Impairment of equity-method investments 0 (114) (938) (186)
Other investing income (loss) – net 2 7 6 132
Proportional Modified EBITDA of equity-method investments (189) (181) (573) (546)
Interest expense (292) (296) (882) (888)
(Provision) benefit for income taxes (111) (77) (24) (244)
Net income (loss) $ 323 $ 242 $ 68 $ 780

accordance with GAAP.

Management’s Discussion and Analysis (Continued)

Transmission & Gulf of Mexico


	Three Months Ended March 31,
		2021		2020
		(Millions)
Service revenues		$	834	$	829
Service revenues – commodity consideration		11		5
Product sales		67		52
Segment revenues		912		886

Product costs		(66)		(52)
Processing commodity expenses		(4)		(2)
Other segment costs and expenses		(229)		(214)

Proportional Modified EBITDA of equity-method investments		47		44
Transmission & Gulf of Mexico Modified EBITDA		$	660	$	662

Commodity margins		$	8	$	3

Three months ended March 31, 2021 vs. three months ended March 31, 2020

Transmission & Gulf of Mexico Modified EBITDA decreased primarily due to unfavorable changes to Other segment costs and expenses, partially offset by higher Commodity margins and Service revenues.

Service revenues increased primarily due to:

•A $17 million increase in Transco’s natural gas transportation revenues primarily associated with expansion projects placed in service in 2020, partially offset by one less billing day;

•A $10 million increase associated with Norphlet; partially offset by

•An $18 million decrease due to lower volumes primarily from certain Gulf of Mexico operations due to producer operational issues.

The increase in Product sales includes a $12 million increase in commodity marketing sales primarily due to higher NGL prices. 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 higher employee-related costs.

Management’s Discussion and Analysis (Continued)

Northeast G&P


	Three Months Ended March 31,
		2021		2020
		(Millions)
Service revenues		$	358	$	358
Service revenues – commodity consideration		3		2
Product sales		32		29
Segment revenues		393		389

Product costs		(32)		(29)
Processing commodity expenses		—		(1)
Other segment costs and expenses		(112)		(110)

Proportional Modified EBITDA of equity-method investments		153		120
Northeast G&P Modified EBITDA		$	402	$	369

Commodity margins		$	3	$	1

Three months ended March 31, 2021 vs. three months ended March 31, 2020

Northeast G&P Modified EBITDA increased primarily due to increased Proportional Modified EBITDA of equity-method investments.

Product sales increased slightly primarily due to higher sales prices of NGLs associated with our marketing activities, which were substantially offset by lower sales volumes. Marketing sales are offset by similar changes in marketing purchases, reflected above as Product costs, and therefore have little impact to Modified EBITDA.

Proportional Modified EBITDA of equity-method investments increased at Appalachia Midstream Investments primarily driven by higher volumes. Additionally, there was an increase at Blue Racer/Caiman II due to the favorable impact of increased ownership, partially offset by lower volumes.

West


	Three Months Ended March 31,
		2021		2020
		(Millions)
Service revenues		$	284	$	311
Service revenues – commodity consideration		35		21
Product sales		1,046		359
Segment revenues		1,365		691

Product costs		(936)		(368)
Processing commodity expenses		(17)		(10)
Other segment costs and expenses		(122)		(126)

Proportional Modified EBITDA of equity-method investments		25		28
West Modified EBITDA		$	315	$	215

Commodity margins		$	128	$	2

Management’s Discussion and Analysis (Continued)

Three months ended March 31, 2021 vs. three months ended March 31, 2020

West Modified EBITDA increased primarily due to higher Commodity margins, partially offset by lower Service revenues.

Service revenues decreased primarily due to:

•A $26 million decrease associated with lower gathering and processing rates, primarily in the Haynesville Shale region due to a customer contract change and in the Piceance region driven primarily by unfavorable commodity pricing;

•An $11 million decrease associated with lower volumes, primarily due to production declines in the Haynesville Shale region. The impact of lower gathering volumes in the Eagle Ford Shale region was substantially offset by the recognition of higher MVC revenue;

•A $10 million decrease related to lower deferred revenue amortization primarily in the Barnett Shale region; partially offset by

•A $10 million increase associated with higher MVC revenue, primarily in the Wamsutter region due to timing of recognition;

•A $10 million increase in revenues associated primarily with reimbursable compressor power and fuel purchases due to higher prices related to the impact of severe winter weather, which are offset by similar changes in Other segment costs and expenses.

The net sum of Service revenues – commodity consideration, Product sales, Product costs, and Processing commodity expenses comprise our commodity margins, which we further segregate into product margins associated with our marketing and equity NGLs margins. Marketing margins increased by $122 million primarily due to favorable changes in net realized commodity prices, including the impact of severe winter weather in the first quarter of 2021. Product margins from our equity NGLs increased $4 million, primarily due to higher net realized sales prices.

Other segment costs and expenses decreased primarily due to lower operating expenses including costs related to fewer leased compressors. These decreases are partially offset by higher reimbursable compressor power and fuel purchases which are offset in Service revenues.

Proportional Modified EBITDA of equity-method investments decreased primarily due to lower volumes at OPPL, partially offset by improvements at other equity-method investees.

Other


	Three Months Ended March 31,
		2021		2020
		(Millions)
Other Modified EBITDA		$	33	$	7

Three months ended March 31, 2021 vs. three months ended March 31, 2020

Other Modified EBITDA increased primarily due to our recently acquired upstream operations, including the favorable commodity price impact of severe winter weather in the first quarter of 2021. See Note 12 – Segment Disclosures of Notes to Consolidated Financial Statements.

Management’s Discussion and Analysis (Continued)

Management’s Discussion and Analysis of Financial Condition and Liquidity

Outlook

As previously discussed in Company Outlook, our growth capital and investment expenditures in 2021 are currently expected to be in a range from $1.0 billion to $1.2 billion. Growth capital spending in 2021 primarily includes Transco expansions, all of which are fully contracted with firm transportation agreements, and projects supporting the Northeast G&P business and opportunities in the Haynesville area. In addition to growth capital and investment expenditures, we also remain committed to projects that maintain our assets for safe and reliable operations, as well as projects that meet legal, regulatory, and/or contractual commitments. We intend to fund substantially all of our planned 2021 capital spending with cash available after paying dividends. We retain the flexibility to adjust planned levels of growth capital and investment expenditures in response to changes in economic conditions or business opportunities.

During the first quarter of 2021, we issued $900 million of new long-term debt to fund the repayment of long-term debt maturing in 2021 and for general corporate purposes. As of March 31, 2021, we have approximately $2.1 billion of long-term debt due within one year. Our potential sources of liquidity available to address these maturities include cash on hand, proceeds from refinancing at attractive long-term rates or from our credit facility, as well as proceeds from asset monetizations.

Liquidity

Based on our forecasted levels of cash flow from operations and other sources of liquidity, we expect to have sufficient liquidity to manage our businesses in 2021. Our potential material internal and external sources and uses of liquidity are as follows:


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

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

As of March 31, 2021, we have approximately $21.1 billion of long-term debt due after one year. Our potential sources of liquidity available to address these maturities include cash generated from operations, proceeds from refinancing at attractive long-term rates or from our credit facility, as well as proceeds from asset monetizations.

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

Management’s Discussion and Analysis (Continued)

As of March 31, 2021, we had a working capital deficit of $1.038 billion, including cash and cash equivalents and long-term debt due within one year. Our available liquidity is as follows:


Available Liquidity	March 31, 2021
	(Millions)
Cash and cash equivalents	$	1,126
Capacity available under our $4.5 billion credit facility, less amounts outstanding under our $4 billion commercial paper program (1)	4,500
	$	5,626

(1)In managing our available liquidity, we do not expect a maximum outstanding amount in excess of the capacity of our credit facility inclusive of any outstanding amounts under our commercial paper program. We had no commercial paper outstanding as of March 31, 2021. Through March 31, 2021, there was no amount outstanding under our commercial paper program and credit facility during 2021. At March 31, 2021, we were in compliance with the financial covenants associated with our credit facility.

Dividends

We increased our regular quarterly cash dividend to common stockholders by approximately 2.5 percent from the $0.40 per share paid in each quarter of 2020, to $0.41 per share paid in March 2021.

Registrations

In February 2021, we filed a shelf registration statement as a well-known seasoned issuer.

Distributions from Equity-Method Investees

The organizational documents of entities in which we have an equity-method investment generally require periodic distributions of their available cash to their members. In each case, available cash is reduced, in part, by reserves appropriate for operating their respective businesses.

Credit Ratings

The interest rates at which we are able to borrow money are impacted by our credit ratings. The current ratings are as follows:

Rating Agency

Outlook

Senior Unsecured
Debt Rating

S&P Global Ratings

Stable

BBB

Moody’s Investors Service

Positive

Baa3

Fitch Ratings

Stable

BBB

These credit ratings are included for informational purposes and are not recommendations to buy, sell, or hold our securities, and each rating should be evaluated independently of any other rating. No assurance can be given that the credit rating agencies will continue to assign us investment-grade ratings even if we meet or exceed their current criteria for investment-grade ratios. A downgrade of our credit ratings might increase our future cost of borrowing and would require us to provide additional collateral to third parties, negatively impacting our available liquidity.

Management’s Discussion and Analysis (Continued)

Sources (Uses) of Cash

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


	Cash Flow	Three Months Ended March 31,
	Category	2021		2020
		(Millions)
Sources of cash and cash equivalents:
Operating activities – net	Operating	$	915	$	787
Proceeds from long-term debt (see Note 8)	Financing	897		2
Proceeds from credit-facility borrowings	Financing	—		1,700

Uses of cash and cash equivalents:
Common dividends paid	Financing	(498)		(485)
Capital expenditures	Investing	(260)		(306)
Dividends and distributions paid to noncontrolling interests	Financing	(54)		(44)
Purchases of and contributions to equity-method investments	Investing	(14)		(30)
Payments of long-term debt	Financing	(5)		(1,518)

Other sources / (uses) – net	Financing and Investing	3		5
Increase (decrease) in cash and cash equivalents		$	984	$	111

Operating activities

The factors that determine operating activities are largely the same as those that affect Net income (loss), with the exception of noncash items such as Depreciation and amortization, Provision (benefit) for deferred income taxes, Equity (earnings) losses, Impairment of goodwill, and Impairment of equity-method investments. Our Net cash provided (used) by operating activities for the three months ended March 31, 2021, increased from the same period in 2020 primarily due to higher operating income (excluding noncash items as previously discussed) in 2021.

~~Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations~~

~~General~~

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

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

Effective January 1, 2020, following an organizational realignment, our interstate natural gas pipeline Northwest Pipeline, which was reported within the West reporting segment throughout 2019, is now managed within the Transmission & Gulf of Mexico reporting segment (previously identified as the Atlantic-Gulf reporting segment). Consistent with the manner in which our chief operating decision maker evaluates performance and allocates resources, our operations are conducted, managed, and presented within the following reportable segments: Transmission & Gulf of Mexico, Northeast G&P, and West. All remaining business activities as well as corporate activities are included in Other. Our reportable segments are comprised of the following businesses:

•Transmission & Gulf of Mexico is comprised of our interstate natural gas pipelines, Transco and Northwest Pipeline, as well as 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 variable interest entity), which is a proprietary floating production system, a 50 percent equity-method investment in Gulfstream, and a 60 percent equity-method investment in Discovery.

•Northeast G&P is comprised of our midstream gathering, processing, and fractionation businesses in the Marcellus Shale region primarily in Pennsylvania and New York, and the Utica Shale region of eastern Ohio, as well as a 65 percent interest in our Northeast JV (a consolidated variable interest entity) which operates in West Virginia, Ohio, and Pennsylvania, a 66 percent interest in Cardinal (a consolidated variable interest entity) which operates in Ohio, a 69 percent equity-method investment in Laurel Mountain, a 58 percent equity-method investment in Caiman II, and Appalachia Midstream Investments, a wholly owned subsidiary that owns equity-method investments with an approximate average 66 percent interest in multiple gas gathering systems in the Marcellus Shale.

•West is comprised of our gas gathering, processing, and treating operations in the Rocky Mountain region of Colorado and Wyoming, the Barnett Shale region of north-central Texas, the Eagle Ford Shale region of south Texas, the Haynesville Shale region of northwest Louisiana, and the Mid-Continent region which includes the Anadarko, Arkoma, and Permian basins. This segment also includes our NGL and natural gas marketing business, storage facilities, an undivided 50 percent interest in an NGL fractionator near Conway, Kansas, a 50 percent equity-method investment in OPPL, a 50 percent equity-method investment in RMM, and a 15 percent interest in Brazos Permian II. West also included our former 50 percent equity-method investment in Jackalope, which was sold in April 2019.

•~~Other includes minor business activities that are not operating segments, as well as corporate operations.~~

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

~~Dividends~~

~~In September 2020, we paid a regular quarterly dividend of $0.40 per share.~~

~~Overview of Nine Months Ended September 30, 2020~~

~~Net income (loss) attributable to The Williams Companies, Inc., for the nine months ended September 30, 2020, decreased $631 millioncompared to the nine months ended September 30, 2019, reflecting:~~

•~~$752 million increase in~~ ~~Impairment of equity-method investments~~ ~~driven by $938 million of impairments in the first quarter of 2020;~~

•~~$187 million of~~ ~~Impairment of goodwill~~ ~~in 2020;~~

•~~$122 million decrease due to the absence of a 2019 gain on the sale of our interest in Jackalope;~~

•~~A $33 million unfavorable change in~~ ~~Other income (expense) – net;~~

•A $25 million decrease in service revenues reflecting decreases in deferred revenue recognition at Gulfstar One and in the Barnett, as well as the expiration of the MVC agreement in the Barnett Shale region in 2019, partially offset by revenue growth from our Northeast JV and Transco expansion projects;

•A $24 million decrease in equity earnings, primarily due to our $78 million share of an impairment of goodwill recorded by an equity-method investee in 2020, partially offset by increased contributions from our Northeast G&P investments.

~~These unfavorable changes were partially offset by:~~

•~~A $220 million favorable change in provision for income taxes;~~

•~~$98 million of lower~~ ~~Operating and maintenance expenses~~;

•~~An $81 million favorable change in~~ ~~Net income (loss) attributable to noncontrolling interests~~ ~~primarily due to the noncontrolling interests’ share of the first-quarter 2020 goodwill impairment charge;~~

•~~$76 million increase due to the absence of 2019~~ ~~Impairment of certain assets~~;

•~~$56 million of lower~~ ~~Selling, general, and administrative expenses.~~

~~The following discussion and analysis of~~results of operations and financial condition and liquidity should be read in conjunction with the consolidated financial statements and notes thereto of this Form 10‑Q and our annual consolidated financial statements and notes thereto in Exhibit 99.1 of our Form 8-K dated May 4, 2020.

~~Recent Developments~~

~~Expansion Project Update~~

~~Transmission & Gulf of Mexico~~

~~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 an interconnection with the Sabal Trail pipeline in east central Alabama. The project is being constructed in phases, and all of the project expansion capacity is dedicated to Sabal Trail pursuant to a capacity lease agreement. Phase I was completed in 2017 and it increased capacity by 818 Mdth/d. We placed Phase II into service on May 1, 2020. Together, the first two phases of the project increased capacity by 1,025 Mdth/d.

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

~~COVID-19~~

The outbreak of COVID-19 has severely impacted global economic activity and caused significant volatility and negative pressure in financial markets. We are monitoring the COVID-19 pandemic and have taken steps intended to protect the safety of our customers, employees, and communities, and to support the continued delivery of safe and reliable service to our customers and the communities we serve. We are continuing to monitor developments with respect to the outbreak and note the following:

•~~Our financial condition, results of operations, and liquidity have not been materially impacted by direct effects of COVID-19.~~

•We believe we have the ability to access the debt market, if necessary, as evidenced by the successful completion of debt offerings during second-quarter 2020, and continue to have significant levels of unused capacity on our revolving credit facility.

•We continue to monitor and adapt our remote working arrangements and limit business-related travel. Implementation of these measures has not required material expenditures or significantly impacted our ability to operate our business.

•~~Our remote working arrangements have not significantly impacted our internal controls over financial reporting and disclosure controls and procedures.~~

~~Customer Bankruptcies~~

In June 2020, our customer Chesapeake announced that it had voluntarily filed for relief under Chapter 11 of the U.S. Bankruptcy Code. We provide midstream services, including wellhead gathering, for the natural gas that Chesapeake and its joint interest owners produce, primarily in the Eagle Ford Shale, Haynesville Shale, and Marcellus Shale regions (through Appalachia Midstream Investments). In 2019, Chesapeake accounted for approximately 6 percent of our consolidated revenues. As of September 30, 2020, trade accounts receivable due from Chesapeake include $88 million related to services provided prior to Chesapeake’s bankruptcy filing. The remaining trade accounts receivable due from Chesapeake are current.

We have certain other customers of our consolidated operations and investees, which are less significant to our consolidated results of operations, that have also filed for bankruptcy protection. To date, based on considerations such as our review of those bankruptcy filings, our assessment of the likelihood of contract rejection, and/or ongoing collections of amounts invoiced, we have not recognized any significant credit losses or impairment charges related to these customers. We continue to monitor these ongoing customer bankruptcy proceedings as it is reasonably possible that future developments could affect our assumptions and conclusions.

~~Crude Oil Price Decline~~

During the first several months of 2020, crude oil prices decreased as a result of surplus supply and weakened demand caused by the COVID-19 pandemic. In addition, in early March, Saudi Arabia announced that it would cut export prices and increase production, contributing to a sharp decline in crude oil prices. The significant decline in crude oil prices also impacted NGL prices. While our businesses do not have direct exposure to crude oil prices, the

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

~~combined impacts of the crude oil price decline on our industry and the financial market declines driven by COVID-19 have impacted us as follows:~~

•The publicly traded price for our common stock (NYSE: WMB) declined significantly in the first quarter of 2020. As a result, our board of directors approved a limited duration shareholder rights agreement. (See Note 11 – Stockholders’ Equity of Notes to the Consolidated Financial Statements.)

•Driven by the decline in our market capitalization and the underlying decrease in fair value of our Northeast G&P reporting unit, we recognized a $187 million impairment of goodwill during the first quarter of 2020. (See Note 12 – Fair Value Measurements and Guarantees of Notes to the Consolidated Financial Statements.)

•The same economic conditions impacted the fair value of certain of our equity-method investments, resulting in $938 million of other-than-temporary impairments of these investments in the first quarter of 2020. (See Note 12 – Fair Value Measurements and Guarantees of Notes to the Consolidated Financial Statements.)

~~Considering the decline in crude oil prices, we note the following about our businesses:~~

•~~Our interstate natural gas transmission businesses are fully contracted under long-term firm reservation contracts with high credit quality customers and are not exposed to crude oil prices.~~

•We believe counterparty credit concerns in our gathering and processing business are significantly mitigated by the physical nature of our services, where we gather at the wellhead and are therefore critical to a producer’s ability to move product to market.

•Our on-shore natural gas gathering and processing businesses are substantially focused on gas-directed drilling basins rather than oil, with a broad diversity of basins and customers served. Further, a decline in oil drilling would be expected to result in less associated natural gas production, which could drive more demand for natural gas produced from gas-directed basins we serve.

•~~Our deepwater transportation business is supported mostly by major oil producers with a long-cycle perspective.~~

~~NGL Margins~~

Per-unit non-ethane margins were approximately 35 percent lower in the first nine months of 2020 compared to the same period in 2019 primarily due to a 30 percent decrease in per-unit non-ethane sales prices, partially offset by 31 percent lower per-unit natural gas feedstock prices.

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

~~The potential impact of commodity prices on our business for the remainder of 2020 is further discussed in the following Company Outlook.~~

~~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 were not subject to refund. In March 2019, the FERC accepted our motion to place the rates that

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

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 resolve all issues in the rate case without the need for a hearing, and on December 31, 2019, we filed a formal stipulation and agreement with the FERC setting forth such terms of settlement. On March 24, 2020, the FERC issued an order approving the uncontested rate case settlement, which became effective on June 1, 2020. Rate refunds related to increased rates collected prior to the effective date of the settlement were paid on July 1, 2020.

~~Company Outlook~~

Our business plan for 2020 includes a continued focus on earnings and cash flow growth, while continuing to improve leverage metrics and control operating costs. Many of our producer customers have been impacted by extremely low energy commodity prices, which resulted in a decrease in drilling activity and the temporary shut-in of certain existing production. We are responding by reducing the pace of our capital growth spending in our gathering and processing business and remaining committed to operating cost discipline.

In the current environment, the credit profiles of certain of our producer customers are increasingly challenged, including some that have filed for bankruptcy protection. But as previously discussed, the physical nature of services we provide supports the success of these customers. In many cases, we have long-term acreage dedications with strong historical contractual conveyances that create real estate interests in unproduced gas. In exchange for such dedication of production, we invest capital to build gathering lines uniquely to serve a producer’s wells. Therefore, our gathering lines are physically connected to the customer’s wellheads and pads, conditioning and connecting the production to available markets. There may not be other gathering lines nearby. The construction of gathering systems is capital intensive and it would be very costly for others to replicate, especially considering the depletion to date of the associated reserves. As a result, we play a critical role in getting a customer’s production from the wellhead to a marketable condition and location. This tends to reduce collectability risk as our services enable producers to generate operating cash flows.

In 2020, our operating results are expected to include higher Northeast G&P results associated with higher gathering and processing volumes and the benefit of lower expenses associated with our organizational realignment completed earlier this year as well as other cost-savings initiatives. We also anticipate increases from Transco’s and Northwest Pipeline’s recent expansion projects placed in-service and Transco’s rate settlement, as well as a full year contribution from the Norphlet project in the Eastern Gulf region. These increases will be partially offset by lower deferred revenue amortization related to the West’s Barnett Shale region and Gulfstar One in the Eastern Gulf region. We also expect lower fee revenues in the West, as well as reduced results from the Gulf of Mexico due to loss of production and an increase in repair expenses as a result of several named windstorms.

Our growth capital and investment expenditures in 2020 are expected to be in a range from $1.0 billion to $1.2 billion. Growth capital spending in 2020 primarily includes Transco expansions, all of which are fully contracted with firm transportation agreements, and our Bluestem NGL pipeline project in the Mid-Continent region. In addition to growth capital and investment expenditures, we also remain committed to projects that maintain our assets for safe and reliable operations, as well as projects that meet legal, regulatory, and/or contractual commitments.

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

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

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

•~~Counterparty credit and performance risk, including unexpected developments in ongoing customer bankruptcy proceedings;~~

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

•~~Unexpected changes in customer drilling and 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;~~

•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, 2019, as filed with the SEC on February 24, 2020, as supplemented by the disclosures in Part II, Item 1A. in our Quarterly Report on Form 10-Q for the quarter ended March 31, 2020.

~~Expansion Projects~~

~~Our ongoing major expansion projects include the following:~~

~~Transmission & Gulf of Mexico~~

~~Northeast Supply Enhancement~~

In May 2019, we received approval from the FERC to expand Transco’s existing natural gas transmission system to provide incremental firm transportation capacity from Station 195 in Pennsylvania to the Rockaway Delivery Lateral transfer point in New York. However, approvals required for the project from the New York State Department of Environmental Conservation and the New Jersey Department of Environmental Protection were denied in May 2020. We have not refiled our applications for those approvals. The project would increase capacity by 400 Mdth/d. See further discussion in Critical Accounting Estimates.

~~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 up to 230 Mdth/d of capacity under the project into service in the fourth quarter of 2020, and the remainder of the project capacity into service in the first quarter of 2021. In total, the project is expected to increase capacity by 296 Mdth/d.

~~Leidy South~~

In July 2020, we received approval from the FERC for 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 up to 125 Mdth/d of capacity under the project into service in the fourth quarter of 2020, and we plan to place the remainder of the project into service as early as the fourth quarter of

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

~~2021, assuming timely receipt of all necessary regulatory approvals. The project is expected to increase capacity by 582 Mdth/d.~~

~~West~~

~~Project Bluestem~~

We are expanding our presence in the Mid-Continent region through building a 188-mile NGL pipeline from our fractionator near Conway, Kansas, to an interconnection with a third-party NGL pipeline system in Oklahoma, providing us with firm access to Mt. Belvieu pricing. As part of the project, the third-party is constructing a 110-mile pipeline extension of its existing NGL pipeline system that will have an initial capacity of 120 Mbbls/d. The pipeline and extension projects are expected to be in operation by the end of the fourth quarter of 2020. Further, during the first quarter of 2019, we exercised an option to purchase a 20 percent equity interest in a Mt. Belvieu fractionation train developed by the third party, which was placed into service in the first quarter of 2020.

~~Critical Accounting Estimates~~

~~Equity-Method Investments~~

~~We monitor our equity-method investments for any indications that the carrying value may have experienced an other-than-temporary decline in value.~~

In the first quarter of 2020, we observed a significant decline in the publicly traded price of our common stock (NYSE: WMB) as well as other industry peers and increases in equity yields within the midstream and overall energy industry, which served to increase our estimates of discount rates and weighted-average cost of capital. These changes were attributed to the swift, world-wide economic declines associated with actions to address the spread of COVID-19, coupled with the energy industry impact of significantly reduced energy commodity prices, which were further impacted by crude oil price declines associated with geopolitical actions during the quarter. These significant macroeconomic changes served as indications that the carrying amount of certain of our equity-method investments may have experienced an other-than temporary decline in fair value, determined in accordance with Accounting Standards Codification (ASC) Topic 323, “Investments - Equity Method and Joint Ventures.”

~~As a result, we estimated the fair value of these equity-method investments in accordance with ASC Topic 820, “Fair Value Measurement,” as of the March 31, 2020, measurement date~~. In assessing the fair value, we were required to consider recent publicly available indications of value, which included lower observed publicly traded EBITDA market multiples as compared with recent history, and significantly higher industry weighted-average discount rates. As a result, we determined that there were other-than-temporary declines in the fair value of certain of our equity-method investments, resulting in recognized impairments during the first quarter of 2020 totaling $938 million. (See Note 12 – Fair Value Measurements and Guarantees of Notes to Consolidated Financial Statements.) This included impairments of certain of our equity-method investments in our Northeast G&P segment totaling $405 million, primarily associated with operations in wet-gas areas where producer drilling activities are influenced by NGL prices, which historically trend with crude oil prices. This total was primarily comprised of impairments of our investment in Caiman II and predominantly wet-gas gathering systems that are part of Appalachia Midstream Investments. We also recognized an impairment of $97 million related to Discovery within the Transmission & Gulf of Mexico segment. We estimated the fair value of these investments as of the March 31, 2020, measurement date utilizing income and market approaches, which were impacted by assumptions reflecting the significant recent market declines previously discussed, such as higher discount rates, ranging from 9.7 percent to 13.5 percent, and lower EBITDA multiples ranging from 5.0x to 6.2x. We also considered any debt held at the investee level, and its impact to fair value. We estimate that a one percentage point increase or decrease in the discount rates used would increase these recognized impairments by approximately $197 million or decrease the level of these recognized impairments by approximately $121 million and a 0.5x increase or decrease in the EBITDA multiples assumed would decrease or increase the level of impairments recognized by approximately $48 million.

During the first quarter of 2020 we also recognized $436 million of impairments within our West segment related to our investments in RMM and Brazos Permian II, measured using an income approach. Both investees

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

operate in primarily crude oil-driven basins where our gathering volumes are driven by crude oil drilling. Our expectation of continued lower crude oil prices and related expectation of significant reductions in current and future producer activities in these areas led to reduced estimates of expected future cash flows. Our fair value estimates also reflected increases in the discount rates to approximately 17 percent for these investments. We also considered any debt held at the investee level, and its impact to fair value. We estimate that a one percentage point increase in the discount rate would increase these recognized impairments by approximately $32 million, while a one percentage point decrease would decrease these impairments by approximately $43 million.

Judgments and assumptions are inherent in our estimates of future cash flows, discount rates, and market measures utilized. The use of alternate judgments and assumptions could result in a different calculation of fair value, which could ultimately result in the recognition of a different impairment charge in the consolidated financial statements, potentially including impairments for investments that were evaluated but for which no impairments were recognized.

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

As a result of the previously described significant macroeconomic changes during the first quarter of 2020, we also evaluated certain of our property, plant, and equipment and other identifiable intangible assets for indicators of impairment as of March 31, 2020. In our assessments, we considered the impact of the then current market conditions on certain of our assets and did not identify any indicators that the carrying amounts of those assets may not be recoverable. The use of alternate judgments or changes in future conditions could result in a different conclusion regarding the occurrence and measurement of impairments affecting the consolidated financial statements.

~~As of September 30, 2020,~~ ~~Property, plant, and equipment~~ in our Consolidated Balance Sheet includes approximately $215 million of capitalized project development costs for the Northeast Supply Enhancement project. As previously discussed, approvals required for the project from the New York State Department of Environmental Conservation and the New Jersey Department of Environmental Protection have been denied and we have not refiled at this time. Beginning in May 2020, we discontinued capitalization of costs related to this project.

The customer precedent agreements for the Northeast Supply Enhancement project remain in effect and the project’s FERC certificate remains active. As such, we do not believe this project is probable of abandonment at this time and consider the carrying amount to be recoverable; thus, no impairment charge has been recognized. It is reasonably possible that further adverse developments in the near future could change this determination, resulting in a future impairment charge of a substantial portion of the capitalized costs.

~~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, 2020, compared to the three and nine months ended September 30, 2019. 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,
2020 2019 $ Change* % Change* 2020 2019 $ Change* % Change*
(Millions) (Millions)
Revenues:
Service revenues $ 1,479 $ 1,495 -16 -1 % $ 4,399 $ 4,424 -25 -1 %
Service revenues – commodity consideration 40 38 +2 +5 % 93 158 -65 -41 %
Product sales 414 466 -52 -11 % 1,135 1,512 -377 -25 %
Total revenues 1,933 1,999 5,627 6,094
Costs and expenses:
Product costs 380 434 +54 +12 % 1,047 1,442 +395 +27 %
Processing commodity expenses 21 19 -2 -11 % 49 83 +34 +41 %
Operating and maintenance expenses 336 364 +28 +8 % 993 1,091 +98 +9 %
Depreciation and amortization expenses 426 435 +9 +2 % 1,285 1,275 -10 -1 %
Selling, general, and administrative expenses 114 130 +16 +12 % 354 410 +56 +14 %
Impairment of certain assets — — — — % — 76 +76 +100 %
Impairment of goodwill — — — — % 187 — -187 NM
Other (income) expense – net 15 (11) -26 NM 28 30 +2 +7 %
Total costs and expenses 1,292 1,371 3,943 4,407
Operating income (loss) 641 628 1,684 1,687
Equity earnings (losses) 106 93 +13 +14 % 236 260 -24 -9 %
Impairment of equity-method investments — (114) +114 +100 % (938) (186) -752 NM
Other investing income (loss) – net 2 7 -5 -71 % 6 132 -126 -95 %
Interest expense (292) (296) +4 +1 % (882) (888) +6 +1 %
Other income (expense) – net (23) 1 -24 NM (14) 19 -33 NM
Income (loss) before income taxes 434 319 92 1,024
Provision (benefit) for income taxes 111 77 -34 -44 % 24 244 +220 +90 %
Net income (loss) 323 242 68 780
Less: Net income (loss) attributable to noncontrolling interests 14 21 +7 +33 % (27) 54 +81 NM
Net income (loss) attributable to The Williams Companies, Inc. $ 309 $ 221 $ 95 $ 726

* + = 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, 2020 vs. three months ended September 30, 2019~~

~~Service revenues~~ decreased primarily due to lower deferred revenue amortization associated with the end of the exclusive use period at Gulfstar One, lower volumes in our West segment, and temporary shut-ins at certain offshore Gulf of Mexico operations. This decrease was partially offset by an increase in the Eagle Ford Shale region primarily due to higher MVC revenue, higher Northeast JV revenues driven by higher volumes, as well as higher transportation fee revenues at Transco associated with expansion projects placed in service in 2019 and 2020.

~~Product sales~~ decreased primarily due to lower volumes associated with our marketing activities. This decrease also includes lower system management gas sales. Marketing revenues and system management gas sales are substantially offset in ~~Product costs~~.

~~Product costs~~ ~~decreased primarily due to lower volumes for marketing activities and lower system management gas costs.~~

~~Operating and maintenance expenses~~ decreased primarily due to lower employee-related expenses, including the absence of 2019 severance and related costs and the favorable impact of a change in an employee benefit policy (see Note 6 – Other Accruals of Notes to Consolidated Financial Statements), and lower maintenance and operating costs primarily due to timing and scope of activities.

~~Selling, general, and administrative expenses~~ ~~decreased primarily due to lower employee-related expenses and lower external legal costs.~~

~~The unfavorable change in~~ ~~Other (income) expense – net~~ ~~within~~ ~~Operating income (loss)~~ includes net unfavorable changes in charges and credits to regulatory assets and liabilities related to the absence of a third-quarter 2019 adjustment associated with Transco’s rate case settlement and the absence of a 2019 customer settlement.

~~The favorable change in~~ ~~Operating income (loss)~~ includes the impact of an increase in the Eagle Ford Shale region primarily due to higher MVC revenue, higher Northeast JV volumes, lower employee-related expenses, and the favorable impact from Transco’s expansion projects. The favorable change was partially offset by lower deferred revenue amortization associated with the end of the exclusive use period at Gulfstar One and lower volumes in our West segment.

~~Equity earnings (losses)~~ changed favorably primarily due to increases at Appalachia Midstream Investments and Caiman II driven by higher volumes, partially offset by a decrease at Laurel Mountain driven by our share of an impairment of certain assets.

~~The change in~~ ~~Impairment of equity-method investments~~ is due to the absence of 2019 impairments to our equity-method investments, including Laurel Mountain (see Note 12 – Fair Value Measurements and Guarantees of Notes to Consolidated Financial Statements).

~~The unfavorable change in~~ ~~Other income (expense) – net~~ ~~below~~ ~~Operating income (loss)~~ includes lower allowance for equity funds used during construction (equity AFUDC) as well as the write-off of a regulatory asset related to a cancelled project, partially offset by the absence of 2019 charges for loss contingencies associated with former operations.

~~Provision (benefit) for income taxes~~ changed unfavorably primarily due to higher pre-tax income. See Note 7 – Provision (Benefit) for Income Taxes of Notes to Consolidated Financial Statements for a discussion of the effective tax rate compared to the federal statutory rate for both periods.

~~Nine months ended September 30, 2020 vs. nine months ended September 30, 2019~~

~~Service revenues~~ decreased primarily due to lower deferred revenue amortization at Gulfstar One, the expiration of an MVC agreement in the Barnett Shale region, lower volumes and rates in our West segment, and temporary shut-ins at certain Gulf of Mexico operations. This decrease was partially offset by higher Northeast G&P revenues driven by higher volumes and the March 2019 consolidation of UEOM, higher MVC revenue in the Eagle Ford

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

~~Shale region, as well as higher transportation fee revenues at Transco, associated with expansion projects placed in service in 2019 and 2020, and increased volumes in the Eastern Gulf region.~~

~~Service revenues – commodity consideration~~ decreased primarily due to lower commodity prices, as well as lower equity NGL processing volumes due to less producer drilling activity. 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 sales~~ decreased primarily due to lower NGL and natural gas prices associated with our marketing and equity NGL sales activities, as well as lower volumes associated with our equity NGL sales activities, partially offset by higher marketing volumes. This decrease also includes lower system management gas sales. Marketing revenues and system management gas sales are substantially offset in ~~Product costs~~.

~~Product costs~~ decreased primarily due to lower NGL and natural gas prices associated with our marketing and equity NGL production activities. This decrease also includes lower volumes acquired as commodity consideration for NGL processing services and lower system management gas costs, partially offset by higher volumes for marketing activities.

~~Processing commodity expenses~~ ~~decreased primarily due to lower natural gas purchases associated with equity NGL production primarily due to lower natural gas prices and lower volumes.~~

~~Operating and maintenance expenses~~ decreased due to lower employee-related expenses, including the absence of 2019 severance and related costs and the associated reduced costs in 2020 (see Note 6 – Other Accruals of Notes to Consolidated Financial Statements) as well as the favorable impact of a change in an employee benefit policy, and lower maintenance and operating primarily due to timing and scope of activities. This decrease was partially offset by higher expenses related to the consolidation of UEOM in March 2019.

~~Depreciation and amortization expenses~~ increased primarily due to new assets placed in service and the March 2019 consolidation of UEOM, partially offset by lower expense related to assets that became fully depreciated in the fourth quarter of 2019.

~~Selling, general, and administrative expenses~~ decreased primarily due to lower employee-related expenses, including the absence of 2019 severance and related costs and the associated reduced costs in 2020 (see Note 6 – Other Accruals of Notes to Consolidated Financial Statements), as well as the absence of transaction costs associated with our 2019 acquisition of UEOM and the formation of the Northeast JV.

~~The favorable change in~~ ~~Impairment of certain assets~~ includes the absence of 2019 impairments of certain Eagle Ford Shale gathering assets and certain idle gathering assets (see Note 12 – Fair Value Measurements and Guarantees of Notes to Consolidated Financial Statements).

~~Impairment of goodwill~~ ~~reflects the goodwill impairment charge at Northeast JV in 2020 (see Note 12 – Fair Value Measurements and Guarantees of Notes to Consolidated Financial Statements).~~

~~The favorable change in~~ ~~Other (income) expense – net~~ ~~within~~ ~~Operating income (loss)~~ includes net favorable changes to charges and credits associated with a regulatory asset related to Transco's asset retirement obligations and the absence of a 2019 unfavorable regulatory asset adjustment at Other, offset by the absence of a 2019 customer settlement.

~~The unfavorable change in~~ ~~Operating income (loss)~~ includes the 2020 impairment of goodwill at Northeast G&P, lower deferred revenue amortization at Gulfstar One, the expiration of an MVC agreement in the Barnett Shale region, and unfavorable commodity margins primarily reflecting lower NGL sales prices. The unfavorable change was partially offset by higher Northeast JV volumes, the absence of the 2019 impairment of certain assets, lower employee-related expenses, the favorable impacts of the consolidation of UEOM, and the favorable impact from Transco’s expansion projects.

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

~~Equity earnings (losses)~~ changed unfavorably primarily due to our share of the 2020 impairment of goodwill at RMM (see Note 5 – Investing Activities of Notes to Consolidated Financial Statements) and a decrease at OPPL. This decrease was partially offset by increases at Appalachia Midstream Investments and Caiman II driven by higher volumes.

~~Impairment of equity-method investments~~ includes impairments of various equity-method investments in 2020, partially offset by the absence of impairments of equity method investments in 2019 (see Note 12 – Fair Value Measurements and Guarantees of Notes to Consolidated Financial Statements).

~~The unfavorable change in~~ ~~Other investing income (loss) – net~~ ~~is primarily due to the absence of a 2019 gain on the sale of our equity-method investment in Jackalope (see Note 5 – Investing Activities of Notes to Consolidated Financial Statements).~~

~~The unfavorable change in~~ ~~Other income (expense) – net~~ ~~below~~ ~~Operating income (loss)~~ includes lower equity AFUDC, the write-off of a regulatory asset related to a cancelled project, and a 2020 pension plan settlement charge, partially offset by the absence of 2019 charges for loss contingencies associated with former operations.

~~Provision (benefit) for income taxes~~ changed favorably primarily due to lower pre-tax income. See Note 7 – Provision (Benefit) for Income Taxes of Notes to Consolidated Financial Statements for a discussion of the effective tax rate compared to the federal statutory rate for both periods.

~~The favorable change in~~ ~~Net income (loss) attributable to noncontrolling interests~~ is primarily due to the noncontrolling interests’ share of the first-quarter 2020 goodwill impairment charge at Northeast JV, and lower Gulfstar One results, partially offset by the impact from the formation of the Northeast JV in June 2019.

~~Period-Over-Period Operating Results - Segments~~

~~We evaluate segment operating performance based upon~~ ~~Modified EBITDA. Note 14 – 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.~~

~~Transmission & Gulf of Mexico~~

Three Months Ended
September 30, Nine Months Ended
September 30,
2020 2019 2020 2019
(Millions)
Service revenues $ 807 $ 842 $ 2,431 $ 2,473
Service revenues – commodity consideration
6 7 14 33
Product sales 46 76 134 226
Segment revenues 859 925 2,579 2,732
Product costs (47) (75) (136) (226)
Processing commodity expenses (1) (2) (4) (12)
Other segment costs and expenses (233) (227) (670) (733)
Proportional Modified EBITDA of equity-method investments 38 44 124 130
Transmission & Gulf of Mexico Modified EBITDA $ 616 $ 665 $ 1,893 $ 1,891
Commodity margins $ 4 $ 6 $ 8 $ 21

~~Three months ended September 30, 2020 vs. three months ended September 30, 2019~~

~~Transmission & Gulf of Mexico Modified EBITDA~~ ~~decreased primarily due to lower~~ ~~Service revenues~~.

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

~~Service revenues~~ ~~decreased primarily due to:~~

•~~A $32 million decrease due to lower deferred revenue amortization associated with the end of the exclusive use period at Gulfstar One for the Tubular Bells field;~~

•~~A $12 million decrease due to temporary named windstorm related shut-ins;~~

•~~An $11 million decrease due to the absence of a third-quarter 2019 adjustment related to Transco’s general rate case settlement;~~

•~~A $14 million increase at Gulfstar One associated with higher volumes in the Tubular Bells field due to a new well and higher production;~~

•~~A $13 million increase in Transco’s natural gas transportation revenues associated with Transco’s expansion projects placed in service in 2019 and 2020.~~

~~The net sum of~~ ~~Service revenues~~ – ~~commodity consideration, Product sales, Product costs,~~ ~~and~~ ~~Processing commodity expenses~~ ~~comprise our commodity margins. The decrease in~~ ~~Product sales~~ ~~includes $23 million of lower system management gas sales and a $6 million decrease in commodity marketing sales. System management and 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 lower equity AFUDC and the absence of a third-quarter 2019 net favorable adjustment to charges and credits associated with regulatory assets and liabilities primarily driven by the terms of settlement in Transco’s general rate case, partially offset by lower employee-related expenses, including the absence of third-quarter 2019 severance and related costs (see Note 6 – Other Accruals of Notes to Consolidated Financial Statements).

~~Nine months ended September 30, 2020 vs. nine months ended September 30, 2019~~

~~Transmission & Gulf of Mexico Modified EBITDA~~ ~~increased primarily due to favorable changes to~~ ~~Other segment costs and expenses, partially offset by lower~~ ~~Service revenues~~ ~~and~~ ~~Commodity margins~~.

~~Service revenues~~ ~~decreased primarily due to:~~

•~~A $92 million decrease due to lower deferred revenue amortization associated with the end of the exclusive use period at Gulfstar One for the Tubular Bells field;~~

•~~A $34 million decrease due to temporary shut-ins primarily at Perdido and Gulfstar One related to named windstorms, pricing, and scheduled maintenance;~~

•~~A $40 million increase in Transco’s natural gas transportation revenues associated with Transco’s expansion projects placed in service in 2019 and 2020;~~

•~~A $30 million increase at Gulfstar One associated with higher volumes in the Tubular Bells field due to a new well and higher production;~~

•~~A $17 million increase associated with volumes from Norphlet placed in service in June 2019.~~

~~The net sum of~~ ~~Service revenues~~ – ~~commodity consideration, Product sales, Product costs,~~ ~~and~~ ~~Processing commodity expenses~~ ~~comprise our commodity margins. Our commodity margins associated with our equity NGLs decreased $10 million primarily driven by unfavorable NGL sales prices and volumes. Additionally, the decrease in~~ ~~Product sales~~ includes a $42 million decrease in commodity marketing sales primarily due to lower NGL prices and $31 million lower system management gas sales. Marketing revenues and system management gas sales are substantially offset in ~~Product costs~~ ~~and therefore have little impact to~~ ~~Modified EBITDA.~~

~~Other segment costs and expenses~~ ~~decreased primarily due to lower employee-related expenses, including the absence of 2019 severance and related costs and the associated reduced costs in 2020, the absence of a 2019 charge~~

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

for reversal of costs capitalized in previous periods, and net favorable changes to charges and credits associated with a regulatory asset related to Transco’s asset retirement obligations. Additionally, expenses decreased due to lower maintenance costs primarily due to a decrease in contracted services related to general maintenance and other testing at Transco, partially offset by lower equity AFUDC and higher operating taxes.

~~Northeast G&P~~

Three Months Ended
September 30, Nine Months Ended
September 30,
2020 2019 2020 2019
(Millions)
Service revenues $ 379 $ 353 $ 1,091 $ 959
Service revenues – commodity consideration
2 1 5 9
Product sales 12 30 42 114
Segment revenues 393 384 1,138 1,082
Product costs (12) (29) (41) (114)
Processing commodity expenses (1) (1) (3) (6)
Other segment costs and expenses (114) (117) (335) (348)
Proportional Modified EBITDA of equity-method investments 121 108 367 333
Northeast G&P Modified EBITDA $ 387 $ 345 $ 1,126 $ 947
Commodity margins $ 1 $ 1 $ 3 $ 3

~~Three months ended September 30, 2020 vs. three months ended September 30, 2019~~

~~Northeast G&P Modified EBITDA~~ ~~increased primarily due to higher~~ ~~Service revenues~~ ~~and increased~~ ~~Proportional Modified EBITDA of equity-method investments~~.

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

•~~A $13 million increase at the Northeast JV related to higher processing, fractionation, transportation, and gathering revenues primarily associated with higher volumes;~~

•~~A $7 million increase associated with higher gathering volumes in the Utica Shale region.~~

~~Product sales~~ ~~decreased primarily due to lower non-ethane volumes within our marketing activities. The changes in marketing revenues are offset by similar changes in marketing purchases, reflected above as~~ ~~Product costs,~~ ~~and therefore have little impact to Modified EBITDA.~~

~~Other segment costs and expenses~~ ~~decreased primarily due to lower maintenance and operating expenses, as well as lower external legal costs. These decreases were partially offset by the absence of a 2019 customer settlement.~~

~~Proportional Modified EBITDA of equity-method investments~~ increased at Appalachia Midstream Investments and Caiman II primarily due to higher volumes, partially offset by a decrease at Laurel Mountain due to $11 million for our share of an impairment of certain assets that were subsequently sold.

~~Nine months ended September 30, 2020 vs. nine months ended September 30, 2019~~

~~Northeast G&P Modified EBITDA~~ ~~increased primarily due to higher~~ ~~Service revenues~~ ~~and increased~~ ~~Proportional Modified EBITDA of equity-method investments, in addition to the favorable impact of acquiring the additional interest in UEOM, which is a consolidated entity after the remaining ownership interest was purchased in March 2019, and lower~~ ~~Other segment costs and expenses~~.

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

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

•A $96 million increase at the Northeast JV, including $64 million higher processing, fractionation, transportation, and gathering revenues primarily due to higher volumes and a $32 million increase associated with the consolidation of UEOM, as previously discussed;

•~~An $18 million increase in gathering revenues associated with higher volumes in the Utica Shale region;~~

•~~A $13 million increase in revenues associated with reimbursable electricity expenses, which is offset by similar changes in electricity charges, reflected in~~ ~~Other segment costs and expenses.~~

~~Product sales~~ decreased primarily due to lower NGL prices and lower non-ethane volumes within our marketing activities. The changes in marketing revenues are offset by similar changes in marketing purchases, reflected above as ~~Product costs, and therefore have little impact to Modified EBITDA.~~

~~Other segment costs and expenses~~ ~~decreased due to lower maintenance and repair expenses and operating expenses primarily due to the timing and scope of activities. Additionally,~~ ~~Other segment costs and expenses~~ decreased due to lower employee-related expenses, including the absence of second-quarter 2019 severance and related costs (see Note 6 – Other Accruals of Notes to Consolidated Financial Statements) and the associated reduced costs in 2020, and the absence of transaction costs associated with our 2019 acquisition of UEOM and the formation of the Northeast JV. These decreases were partially offset by higher reimbursable electricity expenses, increased expenses associated with the consolidation of UEOM, and the absence of a 2019 customer settlement.

~~Proportional Modified EBITDA of equity-method investments~~ increased at Appalachia Midstream Investments driven by higher volumes and at Caiman II driven by higher volumes and a gain on early debt retirement. These increases were partially offset by a $16 million decrease as a result of the consolidation of UEOM, as previously discussed, as well as a decrease at Laurel Mountain due to $11 million for our share of an impairment of certain assets that subsequently sold.

~~West~~

Three Months Ended
September 30, Nine Months Ended
September 30,
2020 2019 2020 2019
(Millions)
Service revenues $ 311 $ 322 $ 938 $ 1,049
Service revenues – commodity consideration
32 30 74 116
Product sales 391 389 1,053 1,302
Segment revenues 734 741 2,065 2,467
Product costs (377) (382) (1,026) (1,294)
Processing commodity expenses (18) (13) (41) (63)
Other segment costs and expenses (122) (130) (365) (404)
Impairment of certain assets — — — (76)
Proportional Modified EBITDA of equity-method investments 30 29 82 83
West Modified EBITDA $ 247 $ 245 $ 715 $ 713
Commodity margins $ 28 $ 24 $ 60 $ 61

~~Three months ended September 30, 2020 vs. three months ended September 30, 2019~~

~~West Modified EBITDA~~ ~~increased primarily due to lower~~ ~~Other segment costs and expenses~~ ~~and higher~~ ~~Commodity margins, partially offset by lower~~ ~~Service revenues~~.

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

~~Service revenues~~ ~~decreased primarily due to:~~

•~~A $29 million decrease associated with lower volumes, excluding the Eagle Ford Shale region;~~

•~~$14 million associated with various other decreases;~~

•~~A $21 million increase in the Eagle Ford Shale region due to higher MVC revenue and higher rates, partially offset by lower volumes primarily due to decreased producer activity;~~

•~~An $11 million increase associated with a temporary volume deficiency fee from a customer.~~

~~The net sum of~~ ~~Service revenues~~ – ~~commodity consideration, Product sales, Product costs,~~ ~~and~~ ~~Processing commodity expenses~~ comprise our commodity margins, which we further segregate into product margins associated with our equity NGLs and marketing margins. Marketing margins increased by $9 million primarily due to favorable changes in net commodity prices. Additionally, product margins from our equity NGLs decreased $5 million.

~~Other segment costs and expenses~~ decreased primarily due to lower operating costs primarily due to fewer leased compressors, lower maintenance costs primarily due to timing and scope of activities, and lower employee-related expenses in 2020.

~~Proportional Modified EBITDA of equity-method investments~~ ~~increased primarily due to higher volumes at RMM and Brazos Permian II, partially offset by lower volumes at OPPL.~~

~~Nine months ended September 30, 2020 vs. nine months ended September 30, 2019~~

~~West Modified EBITDA~~ ~~increased primarily due to the absence of~~ ~~Impairment of certain assets~~ ~~and lower~~ ~~Other segment costs and expenses, partially offset by lower~~ ~~Service revenues~~.

~~Service revenues~~ ~~decreased primarily due to:~~

•A $72 million decrease driven by lower deferred revenue amortization and MVC deficiency fee revenues associated with the second-quarter 2019 expiration of the MVC agreement in the Barnett Shale region;

•~~A $65 million decrease associated with lower volumes, excluding the Eagle Ford Shale region;~~

•A $41 million decrease associated with lower rates, excluding the Eagle Ford Shale region, driven by lower commodity pricing in the Barnett Shale region and the expiration of a cost-of-service period on a contract in the Mid-Continent region;

•~~An $11 million decrease associated with lower fractionation fees driven by lower volumes;~~

•~~An $11 million decrease driven by the absence of a favorable 2019 cost-of-service agreement adjustment in the Mid-Continent region;~~

•A $72 million increase in the Eagle Ford Shale region due to higher MVC revenue and higher rates, partially offset by lower volumes primarily due to decreased producer activity, including shut-ins on certain gathering systems;

•~~A $20 million increase associated with a temporary volume deficiency fee from a customer.~~

~~The net sum of~~ ~~Service revenues~~ – ~~commodity consideration, Product sales, Product costs,~~ ~~and~~ ~~Processing commodity expenses~~ comprise our commodity margins, which we further segregate into product margins associated with our equity NGLs and marketing margins. Product margins from our equity NGLs decreased $22 million primarily due to:

•~~A $30 million decrease associated with lower sales prices primarily due to 30 percent lower average net realized per-unit non-ethane sales prices;~~

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

•~~A $13 million decrease associated with 14 percent lower non-ethane sales volumes primarily due to less producer drilling activity;~~

•~~A $21 million increase related to a decline in natural gas purchases associated with equity NGL production due to lower natural gas prices and lower equity non-ethane production volumes.~~

~~Additionally, marketing margins increased by $21 million primarily due to favorable changes in net commodity prices. The decrease in~~ ~~Product sales~~ ~~includes a $194 million decrease in marketing sales, which is due to lower sales prices, partially offset by higher marketing sales volumes. These decreases are substantially offset in~~ ~~Product costs.~~

~~Other segment costs and expenses~~ decreased primarily due to lower employee-related expenses driven by the absence of second-quarter 2019 severance and related costs and the associated reduced costs in 2020 (see Note 6 – Other Accruals of Notes to Consolidated Financial Statements), as well as lower operating costs due to fewer leased compressors and lower maintenance costs primarily due to timing and scope of activities.

~~Impairment of certain assets~~ decreased primarily due to the absence of a $59 million impairment of certain Eagle Ford Shale gathering assets and a $12 million impairment of certain idle gathering assets in 2019 (see Note 12 – Fair Value Measurements and Guarantees of Notes to the Consolidated Financial Statements).

~~Proportional Modified EBITDA of equity-method investments~~ decreased primarily due to lower volumes at OPPL and the absence of the Jackalope equity-method investment sold in April 2019, partially offset by growth at the RMM and the Brazos Permian II equity-method investments.

~~Other~~

Three Months Ended September 30, Nine Months Ended September 30,
2020 2019 2020 2019
(Millions)
Other Modified EBITDA $ (7) $ (2) $ 8 $ 1

~~Three months ended September 30, 2020 vs. three months ended September 30, 2019~~

~~Other Modified EBITDA~~ ~~includes:~~

•~~A third-quarter 2020 charge of $8 million for the write-off of a regulatory asset associated with a cancelled project;~~

•~~The absence of a third-quarter 2019 $9 million accrual for loss contingencies associated with former operations.~~

~~Nine months ended September 30, 2020 vs. nine months ended September 30, 2019~~

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

•The absence of a first-quarter 2019 $12 million unfavorable adjustment to a regulatory asset associated with an increase in Transco’s estimated deferred state income tax rate following the merger transaction wherein we acquired all of the outstanding common units held by others of our former publicly traded master limited partnership;

•~~The absence of a third-quarter 2019 $9 million accrual for loss contingencies;~~

•~~A third-quarter 2020 charge of $8 million for the write-off of a regulatory asset.~~

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

~~Management’s Discussion and Analysis of Financial Condition and Liquidity~~

~~Outlook~~

As previously discussed in Company Outlook, our growth capital and investment expenditures in 2020 are currently expected to be in a range from $1.0 billion to $1.2 billion. Growth capital spending in 2020 primarily includes Transco expansions, all of which are fully contracted with firm transportation agreements, and our Bluestem NGL pipeline project in the Mid-Continent region. In addition to growth capital and investment expenditures, we also remain committed to projects that maintain our assets for safe and reliable operations, as well as projects that meet legal, regulatory, and/or contractual commitments. We intend to fund substantially all of our planned 2020 capital spending with cash available after paying dividends. We retain the flexibility to adjust planned levels of growth capital and investment expenditures in response to changes in economic conditions or business opportunities.

During the first half of 2020, we retired approximately $1.5 billion of long-term debt and issued approximately $2.2 billion of new long-term debt. In August 2020, we early retired our $600 million of 4.125 percent senior unsecured notes that were scheduled to mature in November 2020. In July 2020, we paid $284 million for rate refunds related to Transco’s increased rates collected since the new rates became effective in March 2019. (See Note 13 – Contingent Liabilities of Notes to Consolidated Financial Statements.)

~~Liquidity~~

Based on our forecasted levels of cash flow from operations and other sources of liquidity, we expect to have sufficient liquidity to manage our businesses in 2020. Our potential material internal and external sources and uses of liquidity are as follows:


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

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

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

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

~~As of September 30, 2020, we had a working capital deficit of $458 million, including cash and cash equivalents and long-term debt due within one year. Our available liquidity is as follows:~~


~~Available Liquidity~~	~~September 30, 2020~~
	~~(Millions)~~
~~Cash and cash equivalents~~	$	70
~~Capacity available under our $4.5 billion credit facility, less amounts outstanding under our $4 billion commercial paper program (1)~~	~~4,460~~
	$	~~4,530~~

~~(1)~~In managing our available liquidity, we do not expect a maximum outstanding amount in excess of the capacity of our credit facility inclusive of any outstanding amounts under our commercial paper program. We had $40 million of ~~Commercial paper~~ outstanding as of September 30, 2020. Through September 30, 2020, the highest amount outstanding under our commercial paper program and credit facility during 2020 was $1.7 billion. At September 30, 2020, we were in compliance with the financial covenants associated with our credit facility. Borrowing capacity available under our credit facility as of October 29, 2020 was $4.5 billion.

~~Dividends~~

We increased our regular quarterly cash dividend to common stockholders by approximately 5 percent from the previous quarterly cash dividends of $0.38 per share paid in each quarter of 2019, to $0.40 per share for the quarterly cash dividends paid in March, June, and September 2020.

~~Registrations~~

In February 2018, we filed a shelf registration statement as a well-known seasoned issuer. In August 2018, we filed a prospectus supplement for the offer and sale from time to time of shares of our common stock having an aggregate offering price of up to $1 billion. These sales are to be made over a period of time and from time to time in transactions at then-current prices. Such sales are to be made pursuant to an equity distribution agreement between us and certain entities who may act as sales agents or purchase for their own accounts as principals at a price agreed upon at the time of the sale.

~~Distributions from Equity-Method Investees~~

The organizational documents of entities in which we have an equity-method investment generally require distribution of their available cash to their members on a quarterly basis. In each case, available cash is reduced, in part, by reserves appropriate for operating their respective businesses.

~~Credit Ratings~~

~~The interest rates at which we are able to borrow money are impacted by our credit ratings. The current ratings are as follows:~~

~~Rating Agency~~

~~Outlook~~

Senior Unsecured
Debt Rating

~~S&P Global Ratings~~

~~Stable~~

~~BBB~~

~~Moody’s Investors Service~~

~~Stable~~

~~Baa3~~

~~Fitch Ratings~~

~~Stable~~

~~BBB-~~

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

~~Sources (Uses) of Cash~~

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

Cash Flow Nine Months Ended
September 30,
Category 2020 2019
(Millions)
Sources of cash and cash equivalents:
Operating activities – net Operating $ 2,382 $ 2,702
Proceeds from long-term debt Financing 2,198 36
Proceeds from credit-facility borrowings Financing 1,700 700
Proceeds from commercial paper – net Financing 40 —
Proceeds from sale of partial interest in consolidated subsidiary (see Note 2) Financing — 1,330
Proceeds from dispositions of equity-method investments (see Note 5) Investing — 485
Uses of cash and cash equivalents:
Payments of long-term debt Financing (2,136) (44)
Payments on credit-facility borrowings Financing (1,700) (860)
Common dividends paid Financing (1,456) (1,382)
Capital expenditures Investing (938) (1,705)
Purchases of and contributions to equity-method investments Investing (150) (361)
Dividends and distributions paid to noncontrolling interests Financing (147) (86)
Purchases of businesses, net of cash acquired (see Note 2) Investing — (728)
Payments of commercial paper – net Financing — (4)
Other sources / (uses) – net Financing and Investing (12) (4)
Increase (decrease) in cash and cash equivalents $ (219) $ 79

~~Operating activities~~

~~The factors that determine operating activities are largely the same as those that affect~~ ~~Net income (loss), with the exception of noncash items such as~~ ~~Depreciation and amortization, Provision (benefit) for deferred income taxes~~, ~~Equity (earnings) losses~~, ~~Gain on disposition of equity-method investments~~, ~~Impairment of goodwill~~, ~~Impairment of equity-method investments, and~~ ~~Impairment of certain assets. Our~~ ~~Net cash provided (used) by operating activities~~ for the nine months ended September 30, 2020, decreased from the same period in 2019 primarily due to the net unfavorable changes in net operating working capital in 2020, including the payment of Transco’s rate refunds in 2020 and the absence of an income tax refund that was received in 2019, partially offset by higher operating income (excluding noncash items as previously discussed) in 2020.

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

We have various other guarantees and commitments that are disclosed in Note 4 – Variable Interest Entities, Note 12 – Fair Value Measurements and Guarantees, and Note 13 – Contingent Liabilities of Notes to Consolidated Financial Statements. We do not believe these guarantees and commitments or the possible fulfillment of them will prevent us from meeting our liquidity needs.

Item 3. Quantitative and Qualitative Disclosures About Market Risk

Interest Rate Risk

Our current interest rate risk exposure is related primarily to our debt portfolio and has not materially changed during the first ~~nine~~three months of ~~2020.~~2021.

Item 4. Controls and Procedures

Our management, including our Chief Executive Officer and Chief Financial Officer, does not expect that our disclosure controls and procedures (as defined in Rules 13a - 15(e) and 15d - 15(e) of the Securities Exchange Act of 1934, as amended) (Disclosure Controls) or our internal control over financial reporting (Internal Controls) will prevent all errors and all fraud. A control system, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. Further, the design of a control system must reflect the fact that there are resource constraints, and the benefits of controls must be considered relative to their costs. Because of the inherent limitations in all control systems, no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, within the company have been detected. These inherent limitations include the realities that judgments in decision-making can be faulty, and that breakdowns can occur because of simple error or mistake. Additionally, controls can be circumvented by the individual acts of some persons, by collusion of two or more people, or by management override of the control. The design of any system of controls also is based in part upon certain assumptions about the likelihood of future events, and there can be no assurance that any design will succeed in achieving its stated goals under all potential future conditions. Because of the inherent limitations in a cost-effective control system, misstatements due to error or fraud may occur and not be detected. We monitor our Disclosure Controls and Internal Controls and make modifications as necessary; our intent in this regard is that the Disclosure Controls and Internal Controls will be modified as systems change and conditions warrant.

Evaluation of Disclosure Controls and Procedures

An evaluation of the effectiveness of the design and operation of our Disclosure Controls was performed as of the end of the period covered by this report. This evaluation was performed under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer. Based upon that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that these Disclosure Controls are effective at a reasonable assurance level.

Changes in Internal Control Over Financial Reporting

There have been no changes during the ~~third~~first quarter of ~~2020~~2021 that have materially affected, or are reasonably likely to materially affect, our Internal Control over Financial Reporting.

PART II. OTHER INFORMATION

Item 1. Legal Proceedings

Environmental

Certain reportable legal proceedings involving governmental authorities under federal, state, and local laws regulating the discharge of materials into the environment are described below. While it is not possible for us to predict the final outcome of the proceedings that are still pending, we do not anticipate a material effect on our consolidated financial position if we receive an unfavorable outcome in any one or more of such proceedings.

On June 13, 2013, an explosion and fire occurred at our formerly owned Geismar olefins plant and rendered the facility temporarily inoperable (Geismar Incident). On October 21, 2013, the EPA, Region 6, 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~~ Our threshold for disclosing material environmental legal proceedings involving 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. We have worked with the agency to resolve these matters and in the second half of 2019, entered into a Stipulation of Settlement, which includes a penalty of $750,000 that will be due within thirty days of the court’s entry of the settlement. The court set a fairness hearing on the settlement for December 11, 2019. Prior to the scheduled hearing, the court continued the hearing without setting a new date.

On May 5, 2017, we entered into a Consent Order with the Georgia Department of Natural Resources, Environmental Protection Division (GADNR) pertaining to alleged violations of the Georgia Water Quality Control Act and associated rules arising from a permit issued by GADNR for construction of Transco’s Dalton expansion project. Pursuant to the Consent Order, we paid a fine of $168,750 and agreed to a Corrective Action Plan. On March 26, 2020, the GADNR issued a closure letter to Transco approving the final Corrective Action Plan implementation and acknowledging that all conditions of the Consent Order have been achieved.governmental authority where potential monetary sanctions are involved is $1 million.

On January 19, 2016, we received a Notice of Noncompliance with certain Leak Detection and Repair (LDAR) regulations under the Clean Air Act at our Moundsville Fractionator Facility from the EPA, Region 3. Subsequently,

the EPA alleged similar violations of certain LDAR regulations at our Oak Grove Gas Plant. On March 19, 2018, we received a Notice of Violation of certain LDAR regulations at our former Ignacio Gas Plant from the EPA, Region 8, following an on-site inspection of the facility. On March 20, 2018, we also received a Notice of Violation of certain LDAR regulations at our Parachute Creek Gas Plant from the EPA, Region 8. All such notices were subsequently referred to a common attorney at the Department of Justice (DOJ). We are exploring global resolution of the claims at these facilities, as well as alleged violations at certain other facilities, with the DOJ. Global resolution would include both payment of a civil penalty and an injunctive relief component. We continue to work with the DOJ and the other agencies to resolve these claims, whether individually or globally, and negotiations are ongoing.

On September 2, 2020, we entered into a Consent Assessment of Civil Penalty with the Commonwealth of Pennsylvania, Department of Environmental Protection resolving permit violations observed by the Department and County Conservation Districts during the construction of our Atlantic Sunrise Project. The violations were largely attributable to the severe rain events we experienced during construction of the project. Pursuant to the Consent Assessment, we paid $736,294 as a civil penalty and contributed $100,000 to fund a community environmental project.

Other environmental matters called for by this Item are described under the caption “Environmental Matters” in Note 1311 – Contingent Liabilities of Notes to Consolidated Financial Statements included under Part I, Item 1. Financial Statements of this report, which information is incorporated by reference into this Item.

Other litigation

The additional information called for by this Item is provided in Note 119 – Stockholders’ Equity and Note 1311 – Contingent Liabilities of Notes to Consolidated Financial Statements included under Part I, Item 1. Financial Statements of this report, which information is incorporated by reference into this Item.

Item 1A. Risk Factors

Part I, Item 1A. Risk Factors in our Annual Report on Form 10-K for the year ended December 31, ~~2019,~~2020, includes risk factors that could materially affect our business, financial condition, or future results. Those Risk Factors have not materially ~~changed, except as they were supplemented or modified~~changed.

Item 5. Other Information

On April 28, 2021, we and Williams Field Services Group, LLC, an indirect wholly owned subsidiary of ours (Williams FSG), entered into an Equity Purchase Agreement (the Purchase Agreement) with Southern Company Gas Investments, Inc. (SECC Seller), Sequent Holdings, LLC, (SEM LP Seller), Sequent, LLC (SEM GP Seller and, together with SECC Seller and SEM LP Seller, the Sellers) and Southern Company Gas (Seller Parent), pursuant to ~~Part II, Item 1A.~~which the Sellers have agreed to sell, and Williams FSG has agreed to buy, (i) a ninety-nine percent limited partnership interest in ~~our Quarterly Report on Form 10-Q~~Sequent Energy Management, L.P. (SEM), (ii) a one percent general partner interest in SEM, and (iii) all of the outstanding shares of common stock of Sequent Energy Canada Corp. (SECC and together with SEM, the Companies). The Companies provide natural gas marketing and logistics services. The purchase price is $50 million plus working capital acquired. The Base Purchase Price as defined in the Purchase Agreement, which includes a $60 million target for acquired working capital, is $110 million, subject to adjustment for actual working capital relative to the ~~quarter ended March 31, 2020.~~target as well as certain other customary adjustments.

The Purchase Agreement contains customary (i) representations and warranties, (ii) covenants, including with respect to actions taken prior to the closing, cooperation with respect to regulatory issues, and access to information, and (iii) indemnification provisions. Williams FSG will obtain a customary buyer’s representation and warranty insurance policy. The Purchase Agreement is subject to customary closing conditions, including the expiration or termination of the applicable waiting period under the Hart-Scott-Rodino Antitrust Improvements Act of 1976.

We have agreed to guarantee the obligations of Williams FSG under the Purchase Agreement. At closing, we will also issue a payment performance guarantee to Seller Parent equal to Seller Parent’s outstanding guarantee obligation with respect to the Companies’ payment performance from the period after the transaction closes until Seller Parent is released from those obligations. We anticipate issuing replacement guarantees directly to the Companies’ counterparties to obtain such release of Seller Parent. The total amount of such obligations varies based on changes in natural gas prices, market conditions, and the number of active contracts and transactions of the Companies with counterparties. We anticipate combined volumes from the Companies’ business and our existing natural gas marketing business will exceed 8 Bcf/d, which we believe would be in the top five of North American natural gas marketers.

The Purchase Agreement contains certain termination rights, including by mutual written consent of the parties or if, subject to certain conditions, the closing has not occurred on or before August 26, 2021. We expect closing to occur during the third quarter of 2021.

5744

Item 6. Exhibits


Exhibit No.		Description

2.1	—	Agreement and Plan of Merger dated as of May 16, 2018, by and among The Williams Companies, Inc., SCMS LLC, Williams Partners L.P., and WPZ GP LLC (filed on May 17, 2018 as Exhibit 2.1 to The Williams Companies, Inc.’s current report on Form 8-K (File No. 001-04174) and incorporated herein by reference).
2.2	—	Amendment No 1. to Agreement and Plan of Merger dated as of May 1, 2016, by and among The Williams Companies, Inc., Energy Transfer Corp LP, Energy Transfer Corp GP, LLC, Energy Transfer Equity, L.P., LE GP, LLC,, and Energy Transfer Equity GP, LLC (filed on May 3, 2016 as Exhibit 2.1 to The Williams Companies, Inc.’s current report on Form 8-K (File No. 001-04174) and incorporated herein by reference).
2.3	—	Agreement and Plan of Merger dated as of September 28, 2015, by and among The Williams Companies, Inc., Energy Transfer Corp LP, Energy Transfer Corp GP, LLC, Energy Transfer Equity, L.P., LE GP, LLC,, and Energy Transfer Equity GP, LLC (filed on October 1, 2015 as Exhibit 2.1 to The Williams Companies, Inc.’s current report on Form 8-K (File No. 001-04174) and incorporated herein by reference).
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.’s 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).
3.5	—	Certificate of Designations of Series C Participating Preferred Stock of The Williams Companies, Inc. (filed on March 20, 2020 as Exhibit 3.1 to The Williams Companies, Inc.’s current report on Form 8‑K (File No. 001-04174) and incorporated herein by reference).
4.1	—	Fourth Supplemental Indenture, dated as of March 2, 2021, between The Williams Companies, Inc. and The Bank of New York Mellon Trust Company, N.A., as trustee (filed on March 2, 2021 as Exhibit 4.1 to The Williams Companies, Inc.’s current report on Form 8‑K (File No. 001-04174) and incorporated herein by reference).
10.1§*	—	Form of 2021 Performance-Based Restricted Stock Unit Agreement among The Williams Companies, Inc. and certain employees and officers.
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.

Exhibit
No.

Description

101.DEF*

—

XBRL Taxonomy Extension Definition Linkbase.

101.LAB*

—

XBRL Taxonomy Extension Label Linkbase.

101.PRE*

—

XBRL Taxonomy Extension Presentation Linkbase.

Exhibit
No.

~~Description~~

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).

* Filed herewith.

** Furnished herewith.

§ Management contract or compensatory plan or arrangement.

5946

SIGNATURE

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.


			THE WILLIAMS COMPANIES, INC.
			(Registrant)

			/s/ John D. Porter
			John D. Porter
			Vice President, Controller, and Chief Accounting Officer (Duly Authorized Officer and Principal Accounting Officer)

~~November 2, 2020~~May 3, 2021


	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, 2020	$	35	$	1,248	$	24,343	$	(12,197)	$	(176)	$	(1,041)	$	12,212	$	2,868	$	15,080
Net income (loss)	0		0		0		309		0		0		309		14		323
Other comprehensive income (loss)	0		0		0		0		16		0		16		0		16
Cash dividends – common stock ($0.40 per share)	0		0		0		(485)		0		0		(485)		0		(485)
Dividends and distributions to noncontrolling interests	0		0		0		0		0		0		0		(49)		(49)
Stock-based compensation and related common stock issuances, net of tax	0		0		16		0		0		0		16		0		16


Contributions from noncontrolling interests	0		0		0		0		0		0		0		1		1
Other	0		0		0		(3)		0		0		(3)		(1)		(4)
Net increase (decrease) in equity	0		0		16		(179)		16		0		(147)		(35)		(182)
Balance – September 30, 2020	$	35	$	1,248	$	24,359	$	(12,376)	$	(160)	$	(1,041)	$	12,065	$	2,833	$	14,898


Balance – June 30, 2019	$	35	$	1,246	$	24,296	$	(10,423)	$	(265)	$	(1,041)	$	13,848	$	3,233	$	17,081
Net income (loss)	0		0		0		221		0		0		221		21		242
Other comprehensive income (loss)	0		0		0		0		(1)		0		(1)		0		(1)


Cash dividends – common stock ($0.38 per share)	0		0		0		(461)		0		0		(461)		0		(461)
Dividends and distributions to noncontrolling interests	0		0		0		0		0		0		0		(18)		(18)
Stock-based compensation and related common stock issuances, net of tax	0		1		16		0		0		0		17		0		17


Changes in ownership of consolidated subsidiaries, net (Note 2)	0		0		(1)		0		0		0		(1)		2		1


Other	0		0		(1)		(1)		0		0		(2)		0		(2)
Net increase (decrease) in equity	0		1		14		(241)		(1)		0		(227)		5		(222)
Balance – September 30, 2019	$	35	$	1,247	$	24,310	$	(10,664)	$	(266)	$	(1,041)	$	13,621	$	3,238	$	16,859


	Three Months Ended September 30,				Nine Months Ended September 30,
	2020		2019		2020		2019
	(Millions)
Other Modified EBITDA	$	(7)	$	(2)	$	8	$	1