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 June 30, ~~2021~~2022


☐			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 July ~~29, 2021~~28, 2022
Common Stock, $1.00 par value						~~1,214,958,829~~1,218,530,122

The Williams Companies, Inc.

Index


						Page
Part I. Financial Information
Item 1. Financial Statements
Consolidated Statement of ~~Operations~~Income – Three and Six Months Ended June 30, ~~2021~~2022 and ~~2020~~2021						6
Consolidated Statement of Comprehensive Income (Loss) – Three and Six Months Ended June 30, ~~2021~~ 2022 and ~~2020~~2021						7
Consolidated Balance Sheet – June 30, ~~2021~~2022 and December 31, ~~2020~~2021						8
Consolidated Statement of Changes in Equity – Three and Six Months Ended June 30, ~~2021~~2022 and ~~2020~~2021						9
Consolidated Statement of Cash Flows – Six Months Ended June 30, ~~2021~~2022 and ~~2020~~2021						11
Notes to Consolidated Financial Statements						12
Note 1 - General, Description of Business, and Basis of Presentation						12
Note 2 - Variable Interest Entities						13
Note 3 - Acquisitions						14
Note 4 - Revenue Recognition						17
Note 5 - Provision (Benefit) for Income Taxes						21
Note 6 - Earnings (Loss) Per Common Share						22
Note 7 - Employee Benefit Plans						22

Note 8 - Debt and Banking Arrangements						23

Note 9 - Fair Value Measurements and Guarantees						24
Note 10 - Derivatives						26
Note 11 - Contingent Liabilities						27
Note 12 - Segment Disclosures						31

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations						3335
Item 3. Quantitative and Qualitative Disclosures About Market Risk						4853
Item 4. Controls and Procedures						4854
Part II. Other Information						4854
Item 1. Legal Proceedings						4854
Item 1A. Risk Factors						4955

Item ~~5. Other Information~~2. Unregistered Sales of Equity Securities and Use of Proceeds						4955
Item 6. Exhibits						5156

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 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 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;~~situation, including the Russian invasion of Ukraine;

•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, ~~2020,~~2021, as filed with the SEC on February ~~24, 2021.~~28, 2022, as supplemented by disclosures in Part II, Item 1A. Risk Factors in subsequent Quarterly Reports on Form 10-Q.

Table of Contents

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 or Bbl: 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

MMbtu: One million British thermal units

Tbtu: One trillion British thermal units

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

Mdth/d: One thousand dekatherms per day

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

MMdth/d: One million dekatherms per day

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

Northeast JV: Ohio Valley Midstream LLC

Northwest Pipeline: Northwest Pipeline LLC

Transco: Transcontinental Gas Pipe Line Company, ~~LLC~~

~~Northeast JV:~~ ~~Ohio Valley Midstream~~ LLC

Partially Owned Entities: Entities in which we do not own a 100 percent ownership interest and which, as of June 30, ~~2021,~~2022, we account for as equity-method investments, including principally the following:

Aux Sable: Aux Sable Liquid Products LP

Blue Racer: Blue Racer Midstream LLC

Discovery: Discovery Producer Services LLC

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

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

Table of Contents

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 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~~Sequent Acquisition:~~NGL revenues less any applicable Btu replacement cost, plant fuel, transportation,~~ The July 1, 2021, acquisition of 100 percent of Sequent Energy Management, L.P. and ~~fractionation~~

Sequent Energy Canada, Corp.

Table of Contents

PART I – FINANCIAL INFORMATION

Item 1. Financial Statements

The Williams Companies, Inc.

Consolidated Statement of ~~Operations~~Income

(Unaudited)


											Three Months Ended June 30,				Six Months Ended June 30,
		Three Months Ended June 30,				Six Months Ended June 30,					2022		2021		2022		2021
		2021		2020		2021		2020			(Millions, except per-share amounts)
		(Millions, except per-share amounts)
Revenues:	Revenues:									Revenues:
Service revenues	Service revenues	$	1,460	$	1,446	$	2,912	$	2,920	Service revenues	$	1,606	$	1,460	$	3,143	$	2,912
Service revenues – commodity consideration	Service revenues – commodity consideration	51		25		100		53		Service revenues – commodity consideration	86		51		163		100
Product sales	Product sales	772		310		1,883		721		Product sales	1,111		786		2,215		1,933
Net gain (loss) on commodity derivatives										Net gain (loss) on commodity derivatives	(313)		(14)		(507)		(50)
Total revenues	Total revenues	2,283		1,781		4,895		3,694		Total revenues	2,490		2,283		5,014		4,895
Costs and expenses:	Costs and expenses:									Costs and expenses:
Product costs	Product costs	697		271		1,629		667		Product costs	857		697		1,660		1,629
Processing commodity expenses		18		15		39		28
Net processing commodity expenses										Net processing commodity expenses	40		18		70		39
Operating and maintenance expenses	Operating and maintenance expenses	379		320		739		657		Operating and maintenance expenses	465		379		859		739
Depreciation and amortization expenses	Depreciation and amortization expenses	463		430		901		859		Depreciation and amortization expenses	506		463		1,004		901
Selling, general, and administrative expenses	Selling, general, and administrative expenses	114		127		237		240		Selling, general, and administrative expenses	160		114		314		237

Impairment of goodwill (Note 10)		0		0		0		187

Other (income) expense – net	Other (income) expense – net	12		6		11		13		Other (income) expense – net	(10)		12		(19)		11
Total costs and expenses	Total costs and expenses	1,683		1,169		3,556		2,651		Total costs and expenses	2,018		1,683		3,888		3,556
Operating income (loss)	Operating income (loss)	600		612		1,339		1,043		Operating income (loss)	472		600		1,126		1,339
Equity earnings (losses) (Note 4)		135		108		266		130
Impairment of equity-method investments (Note 10)		0		0		0		(938)
Equity earnings (losses)										Equity earnings (losses)	163		135		299		266

Other investing income (loss) – net	Other investing income (loss) – net	2		1		4		4		Other investing income (loss) – net	2		2		3		4
Interest incurred	Interest incurred	(301)		(299)		(597)		(600)		Interest incurred	(286)		(301)		(575)		(597)
Interest capitalized	Interest capitalized	3		5		5		10		Interest capitalized	5		3		8		5
Other income (expense) – net	Other income (expense) – net	2		5		0		9		Other income (expense) – net	6		2		11		—
Income (loss) before income taxes	Income (loss) before income taxes	441		432		1,017		(342)		Income (loss) before income taxes	362		441		872		1,017
Less: Provision (benefit) for income taxes	Less: Provision (benefit) for income taxes	119		117		260		(87)		Less: Provision (benefit) for income taxes	(45)		119		73		260

Net income (loss)	Net income (loss)	322		315		757		(255)		Net income (loss)	407		322		799		757
Less: Net income (loss) attributable to noncontrolling interests	Less: Net income (loss) attributable to noncontrolling interests	18		12		27		(41)		Less: Net income (loss) attributable to noncontrolling interests	7		18		19		27
Net income (loss) attributable to The Williams Companies, Inc.	Net income (loss) attributable to The Williams Companies, Inc.	304		303		730		(214)		Net income (loss) attributable to The Williams Companies, Inc.	400		304		780		730
Less: Preferred stock dividends	Less: Preferred stock dividends	0		0		1		1		Less: Preferred stock dividends	—		—		1		1
Net income (loss) available to common stockholders	Net income (loss) available to common stockholders	$	304	$	303	$	729	$	(215)	Net income (loss) available to common stockholders	$	400	$	304	$	779	$	729

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	$	.25	$	.60	$	(.18)	Net income (loss)	$	.33	$	.25	$	.64	$	.60
Weighted-average shares (thousands)	Weighted-average shares (thousands)	1,215,250		1,213,601		1,214,950		1,213,310		Weighted-average shares (thousands)	1,218,678		1,215,250		1,217,814		1,214,950
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	$	.25	$	.60	$	(.18)	Net income (loss)	$	.33	$	.25	$	.64	$	.60
Weighted-average shares (thousands)	Weighted-average shares (thousands)	1,217,476		1,214,581		1,217,344		1,213,310		Weighted-average shares (thousands)	1,222,694		1,217,476		1,221,991		1,217,344

See accompanying notes.

Table of Contents

The Williams Companies, Inc.

Consolidated Statement of Comprehensive Income (Loss)

(Unaudited)


		Three Months Ended June 30,				Six Months Ended June 30,					Three Months Ended June 30,				Six Months Ended June 30,
		2021		2020		2021		2020			2022		2021		2022		2021
		(Millions)									(Millions)
Net income (loss)	Net income (loss)	$	322	$	315	$	757	$	(255)	Net income (loss)	$	407	$	322	$	799	$	757
Other comprehensive income (loss):	Other comprehensive income (loss):									Other comprehensive income (loss):
Cash flow hedging activities:
Net unrealized gain (loss) from derivative instruments, net of taxes of $7 and $9 in 2021 and $0 and $0 in 2020		(17)		0		(26)		0
Reclassifications into earnings of net derivative instruments (gain) loss, net of taxes of ($2) and ($2) in 2021 and $0 and $0 in 2020		4		0		6		0
Designated cash flow hedging activities:										Designated cash flow hedging activities:
Net unrealized gain (loss) from derivative instruments, net of taxes of ($1) and ($2) in 2022 and $7 and $9 in 2021										Net unrealized gain (loss) from derivative instruments, net of taxes of ($1) and ($2) in 2022 and $7 and $9 in 2021	2		(17)		5		(26)
Reclassifications into earnings of net derivative instruments (gain) loss, net of taxes of $— and $— in 2022 and ($2) and ($2) in 2021										Reclassifications into earnings of net derivative instruments (gain) loss, net of taxes of $— and $— in 2022 and ($2) and ($2) in 2021	—		4		—		6

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 $0 and $0 in 2021 and ($7) and ($3) in 2020		0		23		0		9
Amortization of actuarial (gain) loss and net actuarial loss from settlements included in net periodic benefit cost (credit), net of taxes of ($1) and ($2) in 2021 and ($3) and ($5) in 2020		3		6		6		14

Amortization of actuarial (gain) loss and net actuarial loss from settlements included in net periodic benefit cost (credit), net of taxes of $— and ($1) in 2022 and ($1) and ($2) in 2021										Amortization of actuarial (gain) loss and net actuarial loss from settlements included in net periodic benefit cost (credit), net of taxes of $— and ($1) in 2022 and ($1) and ($2) in 2021	3		3		5		6
Other comprehensive income (loss)	Other comprehensive income (loss)	(10)		29		(14)		23		Other comprehensive income (loss)	5		(10)		10		(14)
Comprehensive income (loss)	Comprehensive income (loss)	312		344		743		(232)		Comprehensive income (loss)	412		312		809		743
Less: Comprehensive income (loss) attributable to noncontrolling interests	Less: Comprehensive income (loss) attributable to noncontrolling interests	18		12		27		(41)		Less: Comprehensive income (loss) attributable to noncontrolling interests	7		18		19		27
Comprehensive income (loss) attributable to The Williams Companies, Inc.	Comprehensive income (loss) attributable to The Williams Companies, Inc.	$	294	$	332	$	716	$	(191)	Comprehensive income (loss) attributable to The Williams Companies, Inc.	$	405	$	294	$	790	$	716

See accompanying notes.

Table of Contents

The Williams Companies, Inc.

Consolidated Balance Sheet

(Unaudited)


		June 30, 2021		December 31, 2020			June 30, 2022		December 31, 2021
		(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	$	1,201	$	142	Cash and cash equivalents	$	133	$	1,680
Trade accounts and other receivables	Trade accounts and other receivables	1,000		1,000		Trade accounts and other receivables	2,799		1,986
Allowance for doubtful accounts	Allowance for doubtful accounts	(1)		(1)		Allowance for doubtful accounts	(15)		(8)
Trade accounts and other receivables – net	Trade accounts and other receivables – net	999		999		Trade accounts and other receivables – net	2,784		1,978
Inventories	Inventories	194		136		Inventories	371		379

Derivative assets						Derivative assets	280		301
Other current assets and deferred charges	Other current assets and deferred charges	231		152		Other current assets and deferred charges	219		211
Total current assets	Total current assets	2,625		1,429		Total current assets	3,787		4,549
Investments	Investments	5,124		5,159		Investments	5,116		5,127
Property, plant, and equipment	Property, plant, and equipment	43,543		42,489		Property, plant, and equipment	45,195		44,184
Accumulated depreciation and amortization	Accumulated depreciation and amortization	(14,244)		(13,560)		Accumulated depreciation and amortization	(15,535)		(14,926)
Property, plant, and equipment – net	Property, plant, and equipment – net	29,299		28,929		Property, plant, and equipment – net	29,660		29,258
Intangible assets – net of accumulated amortization	Intangible assets – net of accumulated amortization	7,277		7,444		Intangible assets – net of accumulated amortization	7,633		7,402
Regulatory assets, deferred charges, and other	Regulatory assets, deferred charges, and other	1,182		1,204		Regulatory assets, deferred charges, and other	1,359		1,276
Total assets	Total assets	$	45,507	$	44,165	Total assets	$	47,555	$	47,612
LIABILITIES AND EQUITY	LIABILITIES AND EQUITY					LIABILITIES AND EQUITY
Current liabilities:	Current liabilities:					Current liabilities:
Accounts payable	Accounts payable	$	611	$	482	Accounts payable	$	2,496	$	1,746

Accrued liabilities	Accrued liabilities	1,005		944		Accrued liabilities	1,427		1,201

Commercial paper						Commercial paper	1,039		—
Long-term debt due within one year	Long-term debt due within one year	2,143		893		Long-term debt due within one year	876		2,025
Total current liabilities	Total current liabilities	3,759		2,319		Total current liabilities	5,838		4,972
Long-term debt	Long-term debt	21,091		21,451		Long-term debt	20,800		21,650
Deferred income tax liabilities	Deferred income tax liabilities	2,179		1,923		Deferred income tax liabilities	2,547		2,453
Regulatory liabilities, deferred income, and other	Regulatory liabilities, deferred income, and other	4,213		3,889		Regulatory liabilities, deferred income, and other	4,534		4,436
Contingent liabilities (Note 11)		0		0
Contingent liabilities and commitments (Note 11)						Contingent liabilities and commitments (Note 11)	0		0
Equity:	Equity:					Equity:
Stockholders’ equity:	Stockholders’ equity:					Stockholders’ equity:
Preferred stock		35		35
Common stock ($1 par value; 1,470 million shares authorized at June 30, 2021 and December 31, 2020; 1,249 million shares issued at June 30, 2021 and 1,248 million shares issued at December 31, 2020)		1,249		1,248
Preferred stock ($1 par value; 30 million shares authorized at June 30, 2022 and December 31, 2021; 35,000 shares issued at June 30, 2022 and December 31, 2021)						Preferred stock ($1 par value; 30 million shares authorized at June 30, 2022 and December 31, 2021; 35,000 shares issued at June 30, 2022 and December 31, 2021)	35		35
Common stock ($1 par value; 1,470 million shares authorized at June 30, 2022 and December 31, 2021; 1,253 million shares issued at June 30, 2022 and 1,250 million shares issued at December 31, 2021)						Common stock ($1 par value; 1,470 million shares authorized at June 30, 2022 and December 31, 2021; 1,253 million shares issued at June 30, 2022 and 1,250 million shares issued at December 31, 2021)	1,253		1,250
Capital in excess of par value	Capital in excess of par value	24,401		24,371		Capital in excess of par value	24,500		24,449
Retained deficit	Retained deficit	(13,022)		(12,748)		Retained deficit	(13,498)		(13,237)
Accumulated other comprehensive income (loss)	Accumulated other comprehensive income (loss)	(110)		(96)		Accumulated other comprehensive income (loss)	(23)		(33)
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	11,512		11,769		Total stockholders’ equity	11,226		11,423
Noncontrolling interests in consolidated subsidiaries	Noncontrolling interests in consolidated subsidiaries	2,753		2,814		Noncontrolling interests in consolidated subsidiaries	2,610		2,678
Total equity	Total equity	14,265		14,583		Total equity	13,836		14,101
Total liabilities and equity	Total liabilities and equity	$	45,507	$	44,165	Total liabilities and equity	$	47,555	$	47,612

See accompanying notes.

Table of Contents

The Williams Companies, Inc.

Consolidated Statement of Changes in Equity

(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 – March 31, 2021		$	35	$	1,249	$	24,384	$	(12,825)	$	(100)	$	(1,041)	$	11,702	$	2,771	$	14,473
Balance – March 31, 2022																				Balance – March 31, 2022	$	35	$	1,252	$	24,476	$	(13,378)	$	(28)	$	(1,041)	$	11,316	$	2,655	$	13,971
Net income (loss)	Net income (loss)	0		0		0		304		0		0		304		18		322		Net income (loss)	—		—		—		400		—		—		400		7		407
Other comprehensive income (loss)	Other comprehensive income (loss)	0		0		0		0		(10)		0		(10)		0		(10)		Other comprehensive income (loss)	—		—		—		—		5		—		5		—		5
Cash dividends – common stock ($0.41 per share)		0		0		0		(498)		0		0		(498)		0		(498)
Cash dividends – common stock ($0.425 per share)																				Cash dividends – common stock ($0.425 per share)	—		—		—		(517)		—		—		(517)		—		(517)
Dividends and distributions to noncontrolling interests	Dividends and distributions to noncontrolling interests	0		0		0		0		0		0		0		(41)		(41)		Dividends and distributions to noncontrolling interests	—		—		—		—		—		—		—		(58)		(58)
Stock-based compensation and related common stock issuances, net of tax	Stock-based compensation and related common stock issuances, net of tax	0		0		20		0		0		0		20		0		20		Stock-based compensation and related common stock issuances, net of tax	—		1		24		—		—		—		25		—		25

Contributions from noncontrolling interests	Contributions from noncontrolling interests	0		0		0		0		0		0		0		4		4		Contributions from noncontrolling interests	—		—		—		—		—		—		—		5		5
Other	Other	0		0		(3)		(3)		0		0		(6)		1		(5)		Other	—		—		—		(3)		—		—		(3)		1		(2)
Net increase (decrease) in equity	Net increase (decrease) in equity	0		0		17		(197)		(10)		0		(190)		(18)		(208)		Net increase (decrease) in equity	—		1		24		(120)		5		—		(90)		(45)		(135)
Balance – June 30, 2021		$	35	$	1,249	$	24,401	$	(13,022)	$	(110)	$	(1,041)	$	11,512	$	2,753	$	14,265
Balance – June 30, 2022																				Balance – June 30, 2022	$	35	$	1,253	$	24,500	$	(13,498)	$	(23)	$	(1,041)	$	11,226	$	2,610	$	13,836


Balance – March 31, 2020		$	35	$	1,248	$	24,330	$	(12,013)	$	(205)	$	(1,041)	$	12,354	$	2,905	$	15,259
Balance – March 31, 2021																				Balance – March 31, 2021	$	35	$	1,249	$	24,384	$	(12,825)	$	(100)	$	(1,041)	$	11,702	$	2,771	$	14,473
Net income (loss)	Net income (loss)	0		0		0		303		0		0		303		12		315		Net income (loss)	—		—		—		304		—		—		304		18		322
Other comprehensive income (loss)	Other comprehensive income (loss)	0		0		0		0		29		0		29		0		29		Other comprehensive income (loss)	—		—		—		—		(10)		—		(10)		—		(10)

Cash dividends – common stock ($0.40 per share)		0		0		0		(486)		0		0		(486)		0		(486)
Cash dividends – common stock ($0.41 per share)																				Cash dividends – common stock ($0.41 per share)	—		—		—		(498)		—		—		(498)		—		(498)
Dividends and distributions to noncontrolling interests	Dividends and distributions to noncontrolling interests	0		0		0		0		0		0		0		(54)		(54)		Dividends and distributions to noncontrolling interests	—		—		—		—		—		—		—		(41)		(41)
Stock-based compensation and related common stock issuances, net of tax	Stock-based compensation and related common stock issuances, net of tax	0		0		13		0		0		0		13		0		13		Stock-based compensation and related common stock issuances, net of tax	—		—		20		—		—		—		20		—		20

Contributions from noncontrolling interests	Contributions from noncontrolling interests	0		0		0		0		0		0		0		2		2		Contributions from noncontrolling interests	—		—		—		—		—		—		—		4		4

Other	Other	0		0		0		(1)		0		0		(1)		3		2		Other	—		—		(3)		(3)		—		—		(6)		1		(5)
Net increase (decrease) in equity	Net increase (decrease) in equity	0		0		13		(184)		29		0		(142)		(37)		(179)		Net increase (decrease) in equity	—		—		17		(197)		(10)		—		(190)		(18)		(208)
Balance – June 30, 2020		$	35	$	1,248	$	24,343	$	(12,197)	$	(176)	$	(1,041)	$	12,212	$	2,868	$	15,080
Balance – June 30, 2021																				Balance – June 30, 2021	$	35	$	1,249	$	24,401	$	(13,022)	$	(110)	$	(1,041)	$	11,512	$	2,753	$	14,265

*Accumulated Other Comprehensive Income (Loss)

See accompanying notes.

Table of Contents

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, 2020		$	35	$	1,248	$	24,371	$	(12,748)	$	(96)	$	(1,041)	$	11,769	$	2,814	$	14,583
Balance – December 31, 2021																				Balance – December 31, 2021	$	35	$	1,250	$	24,449	$	(13,237)	$	(33)	$	(1,041)	$	11,423	$	2,678	$	14,101
Net income (loss)	Net income (loss)	0		0		0		730		0		0		730		27		757		Net income (loss)	—		—		—		780		—		—		780		19		799
Other comprehensive income (loss)	Other comprehensive income (loss)	0		0		0		0		(14)		0		(14)		0		(14)		Other comprehensive income (loss)	—		—		—		—		10		—		10		—		10
Cash dividends – common stock ($0.82 per share)		0		0		0		(996)		0		0		(996)		0		(996)
Cash dividends – common stock ($0.85 per share)																				Cash dividends – common stock ($0.85 per share)	—		—		—		(1,035)		—		—		(1,035)		—		(1,035)
Dividends and distributions to noncontrolling interests	Dividends and distributions to noncontrolling interests	0		0		0		0		0		0		0		(95)		(95)		Dividends and distributions to noncontrolling interests	—		—		—		—		—		—		—		(95)		(95)
Stock-based compensation and related common stock issuances, net of tax	Stock-based compensation and related common stock issuances, net of tax	0		1		30		0		0		0		31		0		31		Stock-based compensation and related common stock issuances, net of tax	—		3		51		—		—		—		54		—		54

Contributions from noncontrolling interests	Contributions from noncontrolling interests	0		0		0		0		0		0		0		6		6		Contributions from noncontrolling interests	—		—		—		—		—		—		—		8		8
Other	Other	0		0		0		(8)		0		0		(8)		1		(7)		Other	—		—		—		(6)		—		—		(6)		—		(6)
Net increase (decrease) in equity	Net increase (decrease) in equity	0		1		30		(274)		(14)		0		(257)		(61)		(318)		Net increase (decrease) in equity	—		3		51		(261)		10		—		(197)		(68)		(265)
Balance – June 30, 2021		$	35	$	1,249	$	24,401	$	(13,022)	$	(110)	$	(1,041)	$	11,512	$	2,753	$	14,265
Balance – June 30, 2022																				Balance – June 30, 2022	$	35	$	1,253	$	24,500	$	(13,498)	$	(23)	$	(1,041)	$	11,226	$	2,610	$	13,836


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		(214)		0		0		(214)		(41)		(255)		Net income (loss)	—		—		—		730		—		—		730		27		757
Other comprehensive income (loss)	Other comprehensive income (loss)	0		0		0		0		23		0		23		0		23		Other comprehensive income (loss)	—		—		—		—		(14)		—		(14)		—		(14)

Cash dividends – common stock ($0.80 per share)		0		0		0		(971)		0		0		(971)		0		(971)
Cash dividends – common stock ($0.82 per share)																				Cash dividends – common stock ($0.82 per share)	—		—		—		(996)		—		—		(996)		—		(996)
Dividends and distributions to noncontrolling interests	Dividends and distributions to noncontrolling interests	0		0		0		0		0		0		0		(98)		(98)		Dividends and distributions to noncontrolling interests	—		—		—		—		—		—		—		(95)		(95)
Stock-based compensation and related common stock issuances, net of tax	Stock-based compensation and related common stock issuances, net of tax	0		1		20		0		0		0		21		0		21		Stock-based compensation and related common stock issuances, net of tax	—		1		30		—		—		—		31		—		31

Contributions from noncontrolling interests	Contributions from noncontrolling interests	0		0		0		0		0		0		0		4		4		Contributions from noncontrolling interests	—		—		—		—		—		—		—		6		6

Other	Other	0		0		0		(10)		0		0		(10)		2		(8)		Other	—		—		—		(8)		—		—		(8)		1		(7)
Net increase (decrease) in equity	Net increase (decrease) in equity	0		1		20		(1,195)		23		0		(1,151)		(133)		(1,284)		Net increase (decrease) in equity	—		1		30		(274)		(14)		—		(257)		(61)		(318)
Balance – June 30, 2020		$	35	$	1,248	$	24,343	$	(12,197)	$	(176)	$	(1,041)	$	12,212	$	2,868	$	15,080
Balance – June 30, 2021																				Balance – June 30, 2021	$	35	$	1,249	$	24,401	$	(13,022)	$	(110)	$	(1,041)	$	11,512	$	2,753	$	14,265

*Accumulated Other Comprehensive Income (Loss)

See accompanying notes.

Table of Contents

The Williams Companies, Inc.

Consolidated Statement of Cash Flows

(Unaudited)


		Six Months Ended June 30,					Six Months Ended June 30,
		2021		2020			2022		2021
		(Millions)					(Millions)
OPERATING ACTIVITIES:	OPERATING ACTIVITIES:					OPERATING ACTIVITIES:
Net income (loss)	Net income (loss)	$	757	$	(255)	Net income (loss)	$	799	$	757
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	901		859		Depreciation and amortization	1,004		901
Provision (benefit) for deferred income taxes	Provision (benefit) for deferred income taxes	262		(59)		Provision (benefit) for deferred income taxes	90		262
Equity (earnings) losses	Equity (earnings) losses	(266)		(130)		Equity (earnings) losses	(299)		(266)
Distributions from unconsolidated affiliates	Distributions from unconsolidated affiliates	345		323		Distributions from unconsolidated affiliates	414		345

Impairment of goodwill (Note 10)		0		187
Impairment of equity-method investments (Note 10)		0		938

Net unrealized (gain) loss from derivative instruments						Net unrealized (gain) loss from derivative instruments	364		8
Amortization of stock-based awards	Amortization of stock-based awards	39		24		Amortization of stock-based awards	36		39

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	(50)		85		Accounts receivable	(797)		(50)
Inventories	Inventories	(58)		(9)		Inventories	1		(58)

Other current assets and deferred charges	Other current assets and deferred charges	(56)		(13)		Other current assets and deferred charges	(15)		(56)
Accounts payable	Accounts payable	94		236		Accounts payable	690		94
Accrued liabilities	Accrued liabilities	14		(236)		Accrued liabilities	(24)		14
Changes in current and noncurrent derivative assets and liabilities						Changes in current and noncurrent derivative assets and liabilities	49		(31)
Other, including changes in noncurrent assets and liabilities	Other, including changes in noncurrent assets and liabilities	(10)		(20)		Other, including changes in noncurrent assets and liabilities	(132)		13
Net cash provided (used) by operating activities	Net cash provided (used) by operating activities	1,972		1,930		Net cash provided (used) by operating activities	2,180		1,972
FINANCING ACTIVITIES:	FINANCING ACTIVITIES:					FINANCING ACTIVITIES:

Proceeds from (payments of) commercial paper – net						Proceeds from (payments of) commercial paper – net	1,037		—
Proceeds from long-term debt	Proceeds from long-term debt	898		3,896		Proceeds from long-term debt	5		898
Payments of long-term debt	Payments of long-term debt	(11)		(3,226)		Payments of long-term debt	(2,012)		(11)
Proceeds from issuance of common stock	Proceeds from issuance of common stock	3		6		Proceeds from issuance of common stock	48		3

Common dividends paid	Common dividends paid	(996)		(971)		Common dividends paid	(1,035)		(996)
Dividends and distributions paid to noncontrolling interests	Dividends and distributions paid to noncontrolling interests	(95)		(98)		Dividends and distributions paid to noncontrolling interests	(95)		(95)
Contributions from noncontrolling interests	Contributions from noncontrolling interests	6		4		Contributions from noncontrolling interests	8		6
Payments for debt issuance costs	Payments for debt issuance costs	(6)		(17)		Payments for debt issuance costs	—		(6)

Other – net	Other – net	(12)		(10)		Other – net	(31)		(12)
Net cash provided (used) by financing activities	Net cash provided (used) by financing activities	(213)		(416)		Net cash provided (used) by financing activities	(2,075)		(213)
INVESTING ACTIVITIES:	INVESTING ACTIVITIES:					INVESTING ACTIVITIES:
Property, plant, and equipment:	Property, plant, and equipment:					Property, plant, and equipment:
Capital expenditures (1)	Capital expenditures (1)	(685)		(613)		Capital expenditures (1)	(606)		(685)
Dispositions – net	Dispositions – net	(5)		(16)		Dispositions – net	(11)		(5)
Contributions in aid of construction	Contributions in aid of construction	36		19		Contributions in aid of construction	6		36

Purchases of businesses, net of cash acquired (Note 3)						Purchases of businesses, net of cash acquired (Note 3)	(933)		—

Proceeds from dispositions of equity-method investments		1		0
Purchases of and contributions to equity-method investments	Purchases of and contributions to equity-method investments	(44)		(66)		Purchases of and contributions to equity-method investments	(100)		(44)

Other – net	Other – net	(3)		6		Other – net	(8)		(2)
Net cash provided (used) by investing activities	Net cash provided (used) by investing activities	(700)		(670)		Net cash provided (used) by investing activities	(1,652)		(700)
Increase (decrease) in cash and cash equivalents	Increase (decrease) in cash and cash equivalents	1,059		844		Increase (decrease) in cash and cash equivalents	(1,547)		1,059

Cash and cash equivalents at beginning of year	Cash and cash equivalents at beginning of year	142		289		Cash and cash equivalents at beginning of year	1,680		142
Cash and cash equivalents at end of period	Cash and cash equivalents at end of period	$	1,201	$	1,133	Cash and cash equivalents at end of period	$	133	$	1,201
_____________	_____________					_____________
(1) Increases to property, plant, and equipment	(1) Increases to property, plant, and equipment	$	(693)	$	(581)	(1) Increases to property, plant, and equipment	$	(642)	$	(693)
Changes in related accounts payable and accrued liabilities	Changes in related accounts payable and accrued liabilities	8		(32)		Changes in related accounts payable and accrued liabilities	36		8
Capital expenditures	Capital expenditures	$	(685)	$	(613)	Capital expenditures	$	(606)	$	(685)

See accompanying notes.

Table of Contents

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~~our consolidated financial statements and notes thereto for the year ended December 31, ~~2020,~~2021, in Exhibit 99.1 of our ~~Annual Report on~~ Form ~~10-K.~~8-K dated May 2, 2022. 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~~our 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~~States. Effective January 1, 2022, following an organizational realignment, our natural gas liquids (NGLs) and natural gas marketing services, previously reported within the West segment, along with the former Sequent segment, are now all managed within the Gas & NGL Marketing Services segment. As a result, beginning with the reporting of first-quarter 2022, our operations are presented within the following reportable segments: Transmission & Gulf of Mexico, Northeast G&P, West, and ~~West,~~Gas & NGL Marketing Services, 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. Additionally, beginning in 2022 and concurrent with the integration of our legacy gas marketing operations and the marketing operations acquired in the Sequent Acquisition (see Note 3 – Acquisitions), all natural gas marketing revenues from Gas & NGL Marketing Services are presented net of the related costs of those activities in our Consolidated Statement of Income, as subsequent to the integration the entire natural gas marketing portfolio is considered held for trading purposes which requires net 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. (Gulfstream), 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 of Caiman II in November 2020), and Appalachia


Notes (Continued)			Table of Contents

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).

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 east Texas and northwest Louisiana, and the Mid-Continent region which includes the

~~Notes (Continued)~~

Anadarko and Permian basins. This segment also includes our ~~natural gas liquid (NGL) and natural gas marketing business,~~NGL 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 (OPPL), 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).

Gas & NGL Marketing Services is comprised of our NGL and natural gas marketing and trading operations, which includes risk management and the storage and transportation of natural gas on strategically positioned assets, including our Transco system.

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, 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.

Note 2 – Variable Interest Entities

Consolidated VIEs

As of June 30, ~~2021,~~2022, 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.


Notes (Continued)			Table of Contents

Cardinal

We own a 66 percent interest in Cardinal, a subsidiary that provides gathering services for the Utica Shale region and is a VIE due to certain risks shared with customers. We are the primary beneficiary because we have the power to direct the activities that most significantly impact Cardinal’s economic performance. ~~Future~~In accordance with the contract, future expansion activity is ~~expected~~required 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~~our Consolidated Balance Sheet that are only for the use or obligation of our consolidated VIEs:


		June 30, 2021		December 31, 2020			June 30, 2022		December 31, 2021
		(Millions)					(Millions)
Assets (liabilities):	Assets (liabilities):					Assets (liabilities):
Cash and cash equivalents	Cash and cash equivalents	$	81	$	107	Cash and cash equivalents	$	72	$	78
Trade accounts and other receivables – net	Trade accounts and other receivables – net	151		148		Trade accounts and other receivables – net	124		132

Inventories						Inventories	3		3

Other current assets and deferred charges	Other current assets and deferred charges	9		7		Other current assets and deferred charges	2		7

Property, plant, and equipment – net	Property, plant, and equipment – net	5,406		5,514		Property, plant, and equipment – net	5,189		5,295
Intangible assets – net of accumulated amortization	Intangible assets – net of accumulated amortization	2,322		2,376		Intangible assets – net of accumulated amortization	2,213		2,267
Regulatory assets, deferred charges, and other	Regulatory assets, deferred charges, and other	15		15		Regulatory assets, deferred charges, and other	27		20
Accounts payable	Accounts payable	(55)		(42)		Accounts payable	(72)		(61)

Accrued liabilities	Accrued liabilities	(39)		(34)		Accrued liabilities	(35)		(29)

Regulatory liabilities, deferred income, and other	Regulatory liabilities, deferred income, and other	(286)		(289)		Regulatory liabilities, deferred income, and other	(285)		(287)

Nonconsolidated VIEs

Targa Train 7

We own a 20 percent interest in Targa Train 7, which provides fractionation services at ~~Mt.~~Mont Belvieu, Texas, and is a VIE due primarily to our limited participating rights as the minority equity holder. At June 30, ~~2021,~~2022, the carrying value of our investment in Targa Train 7 was ~~$49~~$46 million. Our maximum exposure to loss is limited to the carrying value of our investment.

~~Brazos Permian II~~

~~We own a 15~~Note 3 – Acquisitions

Trace Acquisition

On April 29, 2022, we closed on the acquisition of 100 percent ~~interest in Brazos Permian II,~~of Gemini Arklatex, LLC through which ~~provides~~we acquired the Haynesville Shale region gas gathering and ~~processing services~~related assets of Trace Midstream (Trace Acquisition) for $972 million of cash funded with cash on hand and proceeds from issuance of commercial paper, subject to post-closing adjustments. The purpose of the Trace Acquisition was to expand our footprint into the east Texas area of the Haynesville Shale region, increasing in-basin scale in one of the largest growth basins in the ~~Delaware basin and is a VIE due primarily to our limited participating rights as the minority equity holder.~~ country.

During the ~~first quarter~~period from the acquisition date of ~~2020 we recorded an impairment~~April 29, 2022 to June 30, 2022, the operations acquired in the Trace Acquisition contributed Revenues of ~~our equity-method investment in Brazos Permian II. Our maximum exposure to loss is limited~~$37 million and Modified EBITDA of $20 million.

Costs related to the ~~carrying value~~Trace Acquisition of $8 million are reported within our ~~investment.~~West segment and included in Selling, general, and administrative expenses in our Consolidated Statement of Income.

The Trace Acquisition 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. The valuation techniques used consisted of the income approach (excess earnings method) for valuation of intangible assets and depreciated replacement costs for property, plant, and equipment.


Notes (Continued)			Table of Contents

The following table presents the preliminary allocation of the acquisition date fair value of the major classes of the assets acquired, which are presented in the West segment, and liabilities assumed at April 29, 2022. The fair value of accounts receivable acquired equals contractual amounts receivable. The allocation is considered preliminary because the valuation work has not been completed due to the ongoing review of the valuation results and validation of significant inputs and assumptions. Preliminary fair value measurements were made for certain acquired assets and liabilities, primarily intangible assets and property, plant, and equipment; however, adjustments to those measurements may be made in subsequent periods, up to one year from the acquisition date, as new information related to facts and circumstances as of the acquisition date may be identified.


	(Millions)
Cash and cash equivalents	$	39
Trade accounts and other receivables – net	18
Property, plant, and equipment – net	437
Intangible assets – net of accumulated amortization	483
Other noncurrent assets	20
Total assets acquired	$	997

Accounts payable	$	12
Accrued liabilities	5
Other noncurrent liabilities	8
Total liabilities assumed	$	25

Net assets acquired	$	972

Intangible assets recognized in the Trace Acquisition are related to contractual customer relationships from gas gathering agreements with our customers. The basis for determining the value of these intangible assets is estimated future net cash flows to be derived from acquired contractual customer relationships discounted using a risk-adjusted discount rate. These intangible assets are being amortized on a straight-line basis over an initial period of 20 years which represents the term over which the contractual customer relationships are expected to contribute to our cash flows. Approximately 2 percent of the expected future revenues from these contractual customer relationships are impacted by our ability and intent to renew or renegotiate existing customer contracts. We expense costs incurred to renew or extend the terms of our gas gathering contracts with customers. Based on the estimated future revenues during the current contract periods (as estimated at the time of the acquisition), the weighted-average period prior to the next renewal or extension of the existing contractual customer relationships is approximately 19 years.

Sequent Acquisition

On July 1, 2021, we closed on the acquisition of 100 percent of Sequent Energy Management, L.P. and Sequent Energy Canada, Corp (Sequent Acquisition). Total consideration for this acquisition was $159 million, which included $109 million related to working capital. The purpose of the Sequent Acquisition was to expand our natural gas marketing activities as well as optimize our pipeline and storage capabilities with expansions into new markets to reach incremental gas-fired power generation, liquified natural gas exports, and future renewable natural gas and other emerging opportunities.

During the period from the acquisition date of July 1, 2021 to December 31, 2021, results for the operations acquired in the Sequent Acquisition included net product sales of $(43) million (including $80 million of purchases from affiliates), net loss on commodity derivatives of $43 million, and unfavorable Modified EBITDA (as defined in Note 12 – Segment Disclosures) of $112 million. Both the Revenues and Modified EBITDA amounts reflect a net unrealized loss on commodity derivatives of $109 million for the period.

Costs related to the Sequent Acquisition for the period from the acquisition date of July 1, 2021 to December 31, 2021 of $5 million were included in Selling, general, and administrative expenses in our Consolidated Statement of Income for the year ended December 31, 2021.


Notes (Continued)			Table of Contents

The Sequent Acquisition 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.

The following table presents the allocation of the acquisition date fair value of the major classes of the assets acquired, which are presented in the Gas & NGL Marketing Services segment, and liabilities assumed at July 1, 2021. The fair value of accounts receivable acquired equals contractual amounts receivable. The fair value of the intangible assets were measured using an income approach. The inventory acquired relates to natural gas in underground storage. The fair value of this inventory was based on the market price of the underlying commodity at the acquisition date. See Note 9 – Fair Value Measurements and Guarantees for the valuation techniques used to measure fair value of derivative assets and liabilities.


	(Millions)
Cash and cash equivalents	$	8
Trade accounts and other receivables – net	498
Inventories	121
Other current assets and deferred charges	4
Commodity derivatives included in Other current assets and deferred charges	57
Property, plant, and equipment – net	5
Intangible assets – net of accumulated amortization	306
Other noncurrent assets	3
Commodity derivatives included in other noncurrent assets	49
Total assets acquired	$	1,051

Accounts payable	$	514
Accrued liabilities	46
Commodity derivatives included in Accrued liabilities	116
Other noncurrent liabilities	1
Commodity derivatives included in other noncurrent liabilities	215
Total liabilities assumed	$	892

Net assets acquired	$	159

Intangible assets

Intangible assets are primarily related to transportation and storage capacity contracts. The basis for determining the value of these intangible assets was estimated future net cash flows to be derived from acquired transportation and storage capacity contracts that provide future economic benefits due to their market location, discounted using an industry weighted-average cost of capital. This intangible asset is being amortized based on the expected benefit period over which the underlying contracts are expected to contribute to our cash flows ranging from 1 year to 8 years. As a result, we expect a significant portion of the amortization to be recognized within the first few years of this range.

Supplemental Pro Forma

The following pro forma Revenues and Net income (loss) attributable to The Williams Companies, Inc. for the three and six months ended June 30, 2022 and 2021, are presented as if the Trace Acquisition had been completed on January 1, 2021, and the Sequent Acquisition had been completed on January 1, 2020. These pro forma amounts are not necessarily indicative of what the actual results would have been if the Trace Acquisition and Sequent Acquisition had in fact occurred on the dates or for the periods indicated, nor do they purport to project Revenues or Net income (loss) attributable to The Williams Companies, Inc. for any future periods or as of any date. These amounts do not give effect to any potential cost savings, operating synergies, or revenue enhancements to result from the transaction or the potential costs to achieve these cost savings, operating synergies, and revenue enhancements.


Notes (Continued)			Table of Contents


	Three Months Ended June 30, 2022
	As Reported		Pro Forma Trace (1)				Pro Forma Combined
	(Millions)
Revenues	$	2,490	$	10			$	2,500
Net income (loss) attributable to The Williams Companies, Inc.	400		4				404

	Three Months Ended June 30, 2021
	As Reported		Pro Forma Trace		Pro Forma Sequent		Pro Forma Combined
	(Millions)
Revenues	$	2,283	$	26	$	(110)	$	2,199
Net income (loss) attributable to The Williams Companies, Inc.	304		9		(117)		196

	Six Months Ended June 30, 2022
	As Reported		Pro Forma Trace (1)				Pro Forma Combined
	(Millions)
Revenues	$	5,014	$	45			$	5,059
Net income (loss) attributable to The Williams Companies, Inc.	780		18				798

	Six Months Ended June 30, 2021
	As Reported		Pro Forma Trace		Pro Forma Sequent		Pro Forma Combined
	(Millions)
Revenues	$	4,895	$	55	$	188	$	5,138
Net income (loss) attributable to The Williams Companies, Inc.	730		20		4		754

(1)Excludes results from operations acquired in the Trace Acquisition for the period beginning on the acquisition date of April 29, 2022, as these results are included in the amounts as reported.

Seasonality can impact natural gas usage and operating results; thus, the results for the operations acquired in the Sequent Acquisition for interim periods are not necessarily indicative of annual results and can vary significantly from quarter to quarter. The results for the operations acquired in the Sequent Acquisition were favorably impacted by Winter Storm Uri in the first quarter of 2021.


Notes (Continued)			Table of Contents

Note 34 – 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		Gas & NGL Marketing Services		Other		Eliminations		Total
																			(Millions)
Three Months Ended June 30, 2022																		Three Months Ended June 30, 2022
Revenues from contracts with customers:																		Revenues from contracts with customers:
Service revenues:																		Service revenues:
Regulated interstate natural gas transportation and storage																		Regulated interstate natural gas transportation and storage	$	664	$	107	$	—	$	—	$	—	$	—	$	—	$	(18)	$	753
Gathering, processing, transportation, fractionation, and storage:																		Gathering, processing, transportation, fractionation, and storage:
Monetary consideration																		Monetary consideration	—		—		84		350		365		—		—		(34)		765
Commodity consideration																		Commodity consideration	—		—		22		3		61		—		—		—		86
Other																		Other	3		—		6		54		14		—		—		(5)		72
Total service revenues																		Total service revenues	667		107		112		407		440		—		—		(57)		1,676
Product sales																		Product sales	43		—		77		34		252		2,843		180		(526)		2,903
Total revenues from contracts with customers																		Total revenues from contracts with customers	710		107		189		441		692		2,843		180		(583)		4,579
Other revenues (1)																		Other revenues (1)	—		1		2		7		(5)		1,616		16		(6)		1,631
Other adjustments (2)																		Other adjustments (2)	—		—		—		—		—		(3,900)		—		180		(3,720)
Total revenues																		Total revenues	$	710	$	108	$	191	$	448	$	687	$	559	$	196	$	(409)	$	2,490
		Transco		Northwest Pipeline		Gulf of Mexico Midstream		Northeast Midstream		West Midstream		Other		Eliminations		Total
		(Millions)
Three Months Ended June 30, 2021	Three Months Ended June 30, 2021																	Three Months Ended June 30, 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	$	613	$	108	$	0	$	0	$	0	$	0	$	(2)	$	719	Regulated interstate natural gas transportation and storage	$	613	$	108	$	—	$	—	$	—	$	—	$	—	$	(2)	$	719
Gathering, processing, transportation, fractionation, and storage:	Gathering, processing, transportation, fractionation, and storage:																	Gathering, processing, transportation, fractionation, and storage:
Monetary consideration	Monetary consideration	0		0		90		315		278		0		(26)		657		Monetary consideration	—		—		90		315		285		—		—		(33)		657
Commodity consideration	Commodity consideration	0		0		10		2		39		0		0		51		Commodity consideration	—		—		10		2		39		—		—		—		51
Other	Other	2		0		7		52		10		0		(4)		67		Other	2		—		7		52		9		1		—		(4)		67
Total service revenues	Total service revenues	615		108		107		369		327		0		(32)		1,494		Total service revenues	615		108		107		369		333		1		—		(39)		1,494
Product sales	Product sales	16		0		53		24		726		44		(87)		776		Product sales	16		—		53		24		107		727		44		(195)		776
Total revenues from contracts with customers	Total revenues from contracts with customers	631		108		160		393		1,053		44		(119)		2,270		Total revenues from contracts with customers	631		108		160		393		440		728		44		(234)		2,270
Other revenues (1)	Other revenues (1)	0		0		3		6		(1)		8		(3)		13		Other revenues (1)	—		—		3		6		3		(4)		8		(3)		13
Total revenues	Total revenues	$	631	$	108	$	163	$	399	$	1,052	$	52	$	(122)	$	2,283	Total revenues	$	631	$	108	$	163	$	399	$	443	$	724	$	52	$	(237)	$	2,283

Three Months Ended June 30, 2020
Revenues from contracts with customers:
Service revenues:
Regulated interstate natural gas transportation and storage		$	592	$	110	$	0	$	0	$	0	$	0	$	(1)	$	701
Gathering, processing, transportation, fractionation, and storage:
Monetary consideration		0		0		78		308		297		0		(19)		664
Commodity consideration		0		0		3		1		21		0		0		25
Other		2		0		10		41		17		0		(4)		66
Total service revenues		594		110		91		350		335		0		(24)		1,456
Product sales		20		0		17		1		303		0		(31)		310
Total revenues from contracts with customers		614		110		108		351		638		0		(55)		1,766
Other revenues (1)		2		0		1		5		2		9		(4)		15
Total revenues		$	616	$	110	$	109	$	356	$	640	$	9	$	(59)	$	1,781

1518


Notes (Continued)			Table of Contents


		Transco		Northwest Pipeline		Gulf of Mexico Midstream		Northeast Midstream		West Midstream		Other		Eliminations		Total			Transco		Northwest Pipeline		Gulf of Mexico Midstream		Northeast Midstream		West Midstream		Gas & NGL Marketing Services		Other		Eliminations		Total
																			(Millions)
Six Months Ended June 30, 2022																		Six Months Ended June 30, 2022
Revenues from contracts with customers:																		Revenues from contracts with customers:
Service revenues:																		Service revenues:
Regulated interstate natural gas transportation and storage																		Regulated interstate natural gas transportation and storage	$	1,329	$	220	$	—	$	—	$	—	$	—	$	—	$	(36)	$	1,513
Gathering, processing, transportation, fractionation, and storage:																		Gathering, processing, transportation, fractionation, and storage:
Monetary consideration																		Monetary consideration	—		—		166		673		682		—		—		(64)		1,457
Commodity consideration																		Commodity consideration	—		—		43		10		110		—		—		—		163
Other																		Other	5		—		12		105		26		1		—		(11)		138
Total service revenues																		Total service revenues	1,334		220		221		788		818		1		—		(111)		3,271
Product sales																		Product sales	59		—		164		70		439		5,313		284		(919)		5,410
Total revenues from contracts with customers																		Total revenues from contracts with customers	1,393		220		385		858		1,257		5,314		284		(1,030)		8,681
Other revenues (1)																		Other revenues (1)	3		2		4		13		(8)		3,231		(49)		(9)		3,187
Other adjustments (2)																		Other adjustments (2)	—		—		—		—		—		(7,132)		—		278		(6,854)
Total revenues																		Total revenues	$	1,396	$	222	$	389	$	871	$	1,249	$	1,413	$	235	$	(761)	$	5,014
		(Millions)
Six Months Ended June 30, 2021	Six Months Ended June 30, 2021																	Six Months Ended June 30, 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	$	1,238	$	221	$	0	$	0	$	0	$	0	$	(5)	$	1,454	Regulated interstate natural gas transportation and storage	$	1,238	$	221	$	—	$	—	$	—	$	—	$	—	$	(5)	$	1,454
Gathering, processing, transportation, fractionation, and storage:	Gathering, processing, transportation, fractionation, and storage:																	Gathering, processing, transportation, fractionation, and storage:
Monetary consideration	Monetary consideration	0		0		176		626		540		0		(47)		1,295		Monetary consideration	—		—		176		626		554		—		—		(61)		1,295
Commodity consideration	Commodity consideration	0		0		21		5		74		0		0		100		Commodity consideration	—		—		21		5		74		—		—		—		100
Other	Other	5		0		10		93		29		0		(8)		129		Other	5		—		10		93		28		2		—		(9)		129
Total service revenues	Total service revenues	1,243		221		207		724		643		0		(60)		2,978		Total service revenues	1,243		221		207		724		656		2		—		(75)		2,978
Product sales	Product sales	30		0		106		56		1,806		100		(177)		1,921		Product sales	30		—		106		56		257		1,815		100		(443)		1,921
Total revenues from contracts with customers	Total revenues from contracts with customers	1,273		221		313		780		2,449		100		(237)		4,899		Total revenues from contracts with customers	1,273		221		313		780		913		1,817		100		(518)		4,899
Other revenues (1)	Other revenues (1)	2		0		5		12		(32)		15		(6)		(4)		Other revenues (1)	2		—		5		12		6		(38)		15		(6)		(4)
Total revenues	Total revenues	$	1,275	$	221	$	318	$	792	$	2,417	$	115	$	(243)	$	4,895	Total revenues	$	1,275	$	221	$	318	$	792	$	919	$	1,779	$	115	$	(524)	$	4,895

Six Months Ended June 30, 2020
Revenues from contracts with customers:
Service revenues:
Regulated interstate natural gas transportation and storage		$	1,196	$	225	$	0	$	0	$	0	$	0	$	(3)	$	1,418
Gathering, processing, transportation, fractionation, and storage:
Monetary consideration		0		0		177		620		596		0		(41)		1,352
Commodity consideration		0		0		8		3		42		0		0		53
Other		5		0		16		82		26		0		(9)		120
Total service revenues		1,201		225		201		705		664		0		(53)		2,943
Product sales		40		0		49		30		662		0		(60)		721
Total revenues from contracts with customers		1,241		225		250		735		1,326		0		(113)		3,664
Other revenues (1)		2		0		3		10		5		17		(7)		30
Total revenues		$	1,243	$	225	$	253	$	745	$	1,331	$	17	$	(120)	$	3,694

(1)Revenues not derived from contracts with customers primarily 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 ~~the~~our Consolidated Statement of ~~Operations,~~Income, and ~~amounts~~realized and unrealized gains and losses associated with our derivative contracts, which are reported in ~~Product sales~~Net gain (loss) on commodity derivatives in ~~the~~our Consolidated Statement of ~~Operations.~~Income.

(2)Other adjustments reflect certain costs of Gas & NGL Marketing Services’ risk management activities. As we are acting as agent for natural gas marketing customers, the resulting revenues are presented net of the related costs of those activities in our Consolidated Statement of Income. In addition, the related derivatives qualify as held for trading purposes, which requires net presentation. (See Note 1 – General, Description of Business, and Basis of Presentation.)

1619


Notes (Continued)			Table of Contents

Contract Assets

The following table presents a reconciliation of our contract assets:


		Three Months Ended June 30,				Six Months Ended June 30,					Three Months Ended June 30,				Six Months Ended June 30,
		2021		2020		2021		2020			2022		2021		2022		2021
		(Millions)									(Millions)
Balance at beginning of period	Balance at beginning of period	$	25	$	18	$	12	$	8	Balance at beginning of period	$	36	$	25	$	22	$	12
Revenue recognized in excess of amounts invoiced	Revenue recognized in excess of amounts invoiced	38		46		83		69		Revenue recognized in excess of amounts invoiced	49		38		104		83
Minimum volume commitments invoiced	Minimum volume commitments invoiced	(25)		(34)		(57)		(47)		Minimum volume commitments invoiced	(37)		(25)		(78)		(57)
Balance at end of period	Balance at end of period	$	38	$	30	$	38	$	30	Balance at end of period	$	48	$	38	$	48	$	38

Contract Liabilities

The following table presents a reconciliation of our contract liabilities:


		Three Months Ended June 30,				Six Months Ended June 30,					Three Months Ended June 30,				Six Months Ended June 30,
		2021		2020		2021		2020			2022		2021		2022		2021
		(Millions)									(Millions)
Balance at beginning of period	Balance at beginning of period	$	1,171	$	1,189	$	1,209	$	1,215	Balance at beginning of period	$	1,093	$	1,171	$	1,126	$	1,209
Payments received and deferred	Payments received and deferred	72		74		85		102		Payments received and deferred	81		72		110		85
Significant financing component	Significant financing component	2		2		5		5		Significant financing component	3		2		5		5

Recognized in revenue	Recognized in revenue	(52)		(62)		(106)		(119)		Recognized in revenue	(62)		(52)		(126)		(106)
Balance at end of period	Balance at end of period	$	1,193	$	1,203	$	1,193	$	1,203	Balance at end of period	$	1,115	$	1,193	$	1,115	$	1,193

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 (MVC) 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 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 June 30, ~~2021,~~2022, 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 June 30, ~~2021,~~2022, that will be recognized in future periods is also excluded from our remaining performance obligations and is instead reflected in contract liabilities.

1720


Notes (Continued)			Table of Contents

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 June 30, ~~2021.~~2022.


		Contract Liabilities		Remaining Performance Obligations			Contract Liabilities		Remaining Performance Obligations
		(Millions)					(Millions)
2021 (six months)		$	83	$	1,724
2022 (one year)		130		3,409
2022 (six months)						2022 (six months)	$	93	$	1,794
2023 (one year)	2023 (one year)	111		3,137		2023 (one year)	137		3,444
2024 (one year)	2024 (one year)	106		2,723		2024 (one year)	120		3,187
2025 (one year)	2025 (one year)	101		2,330		2025 (one year)	116		2,760
2026 (one year)						2026 (one year)	112		2,404

Thereafter 00	Thereafter 00	662		18,055		Thereafter 00	537		17,028
Total	Total	$	1,193	$	31,378	Total	$	1,115	$	30,617

Accounts Receivable

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


		June 30, 2021		December 31, 2020			June 30, 2022		December 31, 2021
		(Millions)					(Millions)
Accounts receivable related to revenues from contracts with customers	Accounts receivable related to revenues from contracts with customers	$	928	$	892	Accounts receivable related to revenues from contracts with customers	$	1,894	$	1,451
Receivables from derivatives						Receivables from derivatives	835		462
Other accounts receivable	Other accounts receivable	71		107		Other accounts receivable	55		65
Trade accounts and other receivables – net	Trade accounts and other receivables – net	$	999	$	999	Trade accounts and other receivables – net	$	2,784	$	1,978

~~Note 4 – Investing Activities~~

~~Equity Earnings (Losses)~~

~~Equity earnings (losses)~~ for the six months ended June 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.

~~Impairment of Equity-Method Investments~~

~~Impairment of equity-method investments~~ for the six months ended June 30, 2020, includes $938 million associated with the first-quarter 2020 impairment of certain equity-method investments (see Note 10 – Fair Value Measurements and Guarantees).

~~Notes (Continued)~~

Note 5 – Provision (Benefit) for Income Taxes

The Provision (benefit) for income taxes includes:


		Three Months Ended June 30,				Six Months Ended June 30,					Three Months Ended June 30,				Six Months Ended June 30,
		2021		2020		2021		2020			2022		2021		2022		2021
		(Millions)									(Millions)
Current:	Current:									Current:
Federal	Federal	$	0	$	0	$	(2)	$	(28)	Federal	$	(28)	$	—	$	(27)	$	(2)
State	State	1		(1)		0		0		State	8		1		10		—
		1		(1)		(2)		(28)			(20)		1		(17)		(2)
Deferred:	Deferred:									Deferred:
Federal	Federal	85		93		200		(41)		Federal	(10)		85		84		200
State	State	33		25		62		(18)		State	(15)		33		6		62

		118		118		262		(59)			(25)		118		90		262
Provision (benefit) for income taxes	Provision (benefit) for income taxes	$	119	$	117	$	260	$	(87)	Provision (benefit) for income taxes	$	(45)	$	119	$	73	$	260

The effective income tax rates for the total provision (benefit) for ~~both~~the three and six months ended June 30, 2022, are less than the federal statutory rate primarily due to the release of valuation allowances and federal settlements, partially offset by the effect of state income taxes.

The effective income tax rates for the total provision (benefit) for the three and six months ended June 30, 2021, ~~and 2020~~ are greater than the federal statutory rate, primarily due to the effect of state income taxes.

We have a valuation allowance on certain deferred income tax assets that serves to reduce those assets to amounts that will, more likely than not, be realized. We must evaluate whether we will ultimately realize these tax benefits considering all available positive and negative evidence, which incorporates management’s assessment of available tax planning strategies, future reversals of existing taxable temporary differences, and the availability and


Notes (Continued)			Table of Contents

character of future taxable income. In light of current evidence, we have released $88 million of valuation allowance upon determining we expect to utilize an additional $70 million of foreign tax credits and $18 million related to various state net operating loss carryforwards and state credits.

During the ~~next 12 months,~~second quarter of 2022, we ~~do not expect ultimate resolution of any unrecognized tax benefit associated~~finalized settlements for 2011 through 2014 on certain contested matters with ~~domestic or international matters to have a material impact on~~the Internal Revenue Service (IRS). These settlements resulted in decreasing our unrecognized tax ~~benefit position.~~positions of approximately $46 million, which favorably impacted the Provision (benefit) for income taxes. We anticipate receiving $3 million of cash refunds (net of payments) from the IRS related to these items in 2022.

Note 6 – Earnings (Loss) Per Common Share

Three Months Ended
June 30, Six Months Ended
June 30,
2021 2020 2021 2020
(Dollars in millions, except per-share
amounts; shares in thousands)
Net income (loss) available to common stockholders $ 304 $ 303 $ 729 $ (215)
Basic weighted-average shares 1,215,250 1,213,601 1,214,950 1,213,310
Effect of dilutive securities:
Nonvested restricted stock units 2,208 980 2,385 0
Stock options 18 0 9 0
Diluted weighted-average shares (1) 1,217,476 1,214,581 1,217,344 1,213,310
Earnings (loss) per common share:
Basic $ .25 $ .25 $ .60 $ (.18)
Diluted $ .25 $ .25 $ .60 $ (.18)

~~(1)~~For the six months ended June 30, 2020, 1.1 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 to our loss available to common stockholders.


	Three Months Ended June 30,				Six Months Ended June 30,
	2022		2021		2022		2021
	(Dollars in millions, except per-share amounts; shares in thousands)
Net income (loss) available to common stockholders	$	400	$	304	$	779	$	729
Basic weighted-average shares	1,218,678		1,215,250		1,217,814		1,214,950
Effect of dilutive securities:
Nonvested restricted stock units	3,660		2,208		3,892		2,385
Stock options	356		18		284		9
Diluted weighted-average shares	1,222,694		1,217,476		1,221,991		1,217,344
Earnings (loss) per common share:
Basic	$	.33	$	.25	$	.64	$	.60
Diluted	$	.33	$	.25	$	.64	$	.60

~~Notes (Continued)~~

Note 7 – Employee Benefit Plans

Net periodic benefit cost (credit) is as follows:


		Pension Benefits									Pension Benefits
		Three Months Ended June 30,				Six Months Ended June 30,					Three Months Ended June 30,				Six Months Ended June 30,
		2021		2020		2021		2020			2022		2021		2022		2021
		(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	$	7	$	7	$	15	$	15	Service cost	$	7	$	7	$	14	$	15
Interest cost	Interest cost	7		9		14		19		Interest cost	8		7		15		14
Expected return on plan assets	Expected return on plan assets	(11)		(14)		(22)		(27)		Expected return on plan assets	(11)		(11)		(22)		(22)

Amortization of net actuarial loss	Amortization of net actuarial loss	3		7		7		11		Amortization of net actuarial loss	3		3		6		7
Net actuarial loss from settlements	Net actuarial loss from settlements	1		2		1		8		Net actuarial loss from settlements	—		1		—		1
Net periodic benefit cost (credit)	Net periodic benefit cost (credit)	$	7	$	11	$	15	$	26	Net periodic benefit cost (credit)	$	7	$	7	$	13	$	15

Other Postretirement Benefits
Three Months Ended
June 30, Six Months Ended
June 30,
2021 2020 2021 2020
(Millions)
Components of net periodic benefit cost (credit):
Interest cost $ 2 $ 1 $ 3 $ 3
Expected return on plan assets (3) (2) (5) (5)
Reclassification to regulatory liability 0 0 1 1
Net periodic benefit cost (credit) $ (1) $ (1) $ (1) $ (1)


Notes (Continued)			Table of Contents


	Other Postretirement Benefits
	Three Months Ended June 30,				Six Months Ended June 30,
	2022		2021		2022		2021
	(Millions)
Components of net periodic benefit cost (credit):

Interest cost	$	2	$	2	$	3	$	3
Expected return on plan assets	(3)		(3)		(5)		(5)

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

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~~our Consolidated Statement of ~~Operations.~~Income.

During the six months ended June 30, 2021, we contributed $3 million to our pension plans and $3 million to our other postretirement benefit plans. We presently anticipate making additional contributions of approximately $1 million to our pension plans and approximately $2 million to our other postretirement benefit plans in the remainder of 2021.

Note 8 – Debt and Banking Arrangements

Long-Term Debt

Issuances and retirements

On ~~March 2, 2021,~~January 18, 2022, we ~~completed a public offering~~early retired $1.25 billion of ~~$900 million of 2.6~~3.6 percent senior unsecured notes due ~~2031.~~March 15, 2022.

On May 16, 2022, we early retired $750 million of 3.35 percent senior unsecured notes due August 15, 2022.

Commercial Paper Program

At June 30, ~~2021, 0~~2022, the weighted-average interest rate of our Commercial paper outstanding was ~~outstanding under our $4 billion commercial paper program.~~2.05 percent.

~~Notes (Continued)~~

Credit ~~Facilities~~Facility

June 30, 2021
Stated Capacity Outstanding
(Millions)
Long-term credit facility (1) $ 4,500 $ 0
Letters of credit under certain bilateral bank agreements 17


	June 30, 2022
	Stated Capacity		Outstanding
	(Millions)

Long-term credit facility (1)	$	3,750	$	—
Letters of credit under certain bilateral bank agreements			48

~~Note 9 – Stockholders’ Equity~~

~~Stockholder Rights Agreement~~

As disclosed in our Annual Report on Form 10-K filed February 24, 2021, a purported shareholder filed a putative class action lawsuit in the Delaware Court of Chancery challenging our stockholder rights agreement (Rights Agreement). On February 26, 2021, the Delaware Court of Chancery issued a decision which declared the Rights Agreement unenforceable and permanently enjoined the continued operation of the Rights Agreement, which otherwise would have expired on March 20, 2021.

~~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
(Millions)
Balance at December 31, 2020 $ (3) $ (1) $ (92) $ (96)
Other comprehensive income (loss) before reclassifications
(26) 0 0 (26)
Amounts reclassified from accumulated other comprehensive income (loss)
6 0 6 12
Other comprehensive income (loss) (20) 0 6 (14)
Balance at June 30, 2021 $ (23) $ (1) $ (86) $ (110)

~~Reclassifications out of~~ ~~AOCI~~ ~~are presented in the following table by component for the six months ended June 30, 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)~~

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

~~Income tax benefit~~

~~(4)~~

~~Provision (benefit) for income taxes~~

~~Reclassifications during the period~~

2123


Notes (Continued)			Table of Contents

Note 109 – 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,~~accounts payable, and ~~accounts payable~~commercial paper 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											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)			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)											(Millions)
Assets (liabilities) at June 30, 2021:
Assets (liabilities) at June 30, 2022:												Assets (liabilities) at June 30, 2022:
Measured on a recurring basis:	Measured on a recurring basis:											Measured on a recurring basis:
ARO Trust investments	ARO Trust investments	$	257	$	257	$	257	$	0	$	0	ARO Trust investments	$	226	$	226	$	226	$	—	$	—
Commodity derivative assets (1)												Commodity derivative assets (1)	107		107		5		58		44

Commodity derivative liabilities (1)												Commodity derivative liabilities (1)	(858)		(858)		(31)		(755)		(72)

Other financial assets (liabilities) – net												Other financial assets (liabilities) – net	(18)		(18)		—		(18)		—
Additional disclosures:	Additional disclosures:											Additional disclosures:

Long-term debt, including current portion	Long-term debt, including current portion	(23,234)		(27,643)		0		(27,643)		0		Long-term debt, including current portion	(21,676)		(21,520)		—		(21,520)		—
Guarantees	Guarantees	(40)		(26)		0		(10)		(16)		Guarantees	(39)		(25)		—		(9)		(16)

Assets (liabilities) at December 31, 2020:
Assets (liabilities) at December 31, 2021:												Assets (liabilities) at December 31, 2021:
Measured on a recurring basis:	Measured on a recurring basis:											Measured on a recurring basis:
ARO Trust investments	ARO Trust investments	$	235	$	235	$	235	$	0	$	0	ARO Trust investments	$	260	$	260	$	260	$	—	$	—
Commodity derivative assets (2)												Commodity derivative assets (2)	84		84		2		81		1

Commodity derivative liabilities (2)												Commodity derivative liabilities (2)	(488)		(488)		(69)		(403)		(16)

Other financial assets (liabilities) – net												Other financial assets (liabilities) – net	(7)		(7)		—		(7)		—
Additional disclosures:	Additional disclosures:											Additional disclosures:
Long-term debt, including current portion	Long-term debt, including current portion	(22,344)		(27,043)		0		(27,043)		0		Long-term debt, including current portion	(23,675)		(27,768)		—		(27,768)		—
Guarantees	Guarantees	(40)		(27)		0		(11)		(16)		Guarantees	(39)		(26)		—		(10)		(16)

(1)Net commodity derivative assets and liabilities exclude $247 million of net cash collateral in Level 1.

(2)Net commodity derivative assets and liabilities exclude $296 million of net cash collateral in Level 1.

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~~our Consolidated Balance Sheet. Both realized and unrealized gains and losses are ultimately recorded as regulatory assets or liabilities.


Notes (Continued)			Table of Contents

Commodity derivatives: Commodity derivatives include exchange-traded contracts and over-the-counter (OTC) contracts, which consist of physical forwards, futures, and swaps that are measured at fair value on a recurring basis. We also have other derivatives related to asset management agreements and other contracts that require physical delivery. Derivatives classified as Level 1 are valued using New York Mercantile Exchange (NYMEX) futures prices. Derivatives classified as Level 2 are valued using basis transactions that represent the cost to transport natural gas from a NYMEX delivery point to the contract delivery point. These transactions are based on quotes obtained either through electronic trading platforms or directly from brokers. Derivatives classified as Level 3 are valued using a combination of observable and unobservable inputs. The fair value amounts are presented on a net basis and reflect the netting of asset and liability positions permitted under the terms of our master netting arrangements and cash held on deposit in margin accounts that we have received or remitted to collateralize certain derivative positions. Commodity derivative assets are reported in Derivative assets and Regulatory assets, deferred charges, and other in our Consolidated Balance Sheet. Commodity derivative liabilities are reported in Accrued liabilities and Regulatory liabilities, deferred income, and other in our Consolidated Balance Sheet. Changes in the fair value of our derivative assets and liabilities are recorded in Net gain (loss) on commodity derivatives and Net processing commodity expenses in our Consolidated Statement of Income. See Note 10 – Derivatives for additional information on our derivatives.

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~~Leidy South, 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~~our Consolidated Balance Sheet. The maximum potential undiscounted exposure is approximately ~~$26~~$25 million at June 30, ~~2021.~~2022. 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~~our 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 0no 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~~


Notes (Continued)			Table of Contents

Note 10 – Derivatives

Commodity-Related Derivatives

We are exposed to commodity price risk. To manage this volatility, we use various contracts in our marketing and trading activities that generally meet the ~~total~~definition of derivatives. Derivative positions are monitored using techniques including, but not limited to value at risk. Derivative instruments are recognized at fair value in our Consolidated Balance Sheet as either assets or liabilities and are presented on a net basis by counterparty, net of margin deposits. See Note 9 – Fair Value Measurements and Guarantees for additional fair value information. In our Consolidated Statement of Cash Flows, any cash impacts of settled commodity-related derivatives are recorded as operating activities.

We enter into commodity-related derivatives to economically hedge exposures to natural gas, NGLs, and crude oil and retain exposure to price changes that can, in a volatile energy market, be material and can adversely affect our results of operations.

At June 30, 2022, the notional volume 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 valuenet long (short) positions for our commodity derivative contracts were 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. follows:

Commodity

Unit of Measure

Net Long (Short) Position

Index Risk

Natural Gas

MMBtu

438,638,852

Central Hub Risk - Mont Belvieu

Natural Gas Liquids

Barrels

(1,480,000)

Basis Risk

Natural Gas Liquids

Barrels

(7,228,000)

Central Hub Risk - Henry Hub

Natural Gas

MMBtu

(40,450,862)

Basis Risk

Natural Gas

MMBtu

(21,565,729)

Central Hub Risk - WTI

Crude Oil

Barrels

(375,000)

Derivative Financial Statement Presentation

The fair value of ~~the reporting unit~~commodity-related derivatives, which are not designated as hedging instruments for accounting purposes, was ~~further reconciled to our estimated total enterprise value~~reflected 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.~~follows:


	June 30, 2022				December 31, 2021
Derivative Category	Assets		(Liabilities)		Assets		(Liabilities)
	(Millions)





Current	$	1,027	$	(1,410)	$	619	$	(760)
Noncurrent	262		(630)		166		(429)
Total derivatives	$	1,289	$	(2,040)	$	785	$	(1,189)

Gross amounts recognized	$	1,289	$	(2,040)	$	785	$	(1,189)
Counterparty and collateral netting offset	(969)		1,216		(476)		772
Amounts recognized in our Consolidated Balance Sheet	$	320	$	(824)	$	309	$	(417)

2326


Notes (Continued)			Table of Contents

For the three and six months ended June 30, 2022 and 2021 the pre-tax effects of commodity-related derivatives instrumentsin Net gain (loss) on commodity derivatives reflected within Total revenues and Net processing commodity expenses in our Consolidated Statement of Income were as follows:

~~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
Six Months Ended
June 30,
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


	Gain (Loss)
	Three Months Ended June 30,				Six Months Ended June 30,
	2022		2021		2022		2021
	(Millions)
Realized commodity-related derivatives designated as hedging instruments	$	—	$	(6)	$	—	$	(8)
Realized commodity-related derivatives not designated as hedging instruments	(63)		—		(132)		(34)
Unrealized commodity-related derivative instruments not designated as hedging instruments (1)	(250)		(8)		(375)		(8)
Net gain (loss) on commodity derivatives	$	(313)	$	(14)	$	(507)	$	(50)

Realized commodity-related derivatives not designated as hedging instruments in net processing commodity expenses	$	5	$	—	$	6	$	—
Unrealized commodity-related derivatives not designated as hedging instruments in net processing commodity expenses (2)	$	9	$	—	$	11	$	—

_______________

(1)~~Following~~Amounts for the ~~previously described declining market conditions during~~three months ended June 30, 2022, include $(297) million related to our Gas & NGL Marketing Services segment and $47 million related to our Other segment. Amounts for the ~~first quarter of 2020, we evaluated these investments~~six months ended June 30, 2022, include $(356) million related to our Gas & NGL Marketing Services segment and $(19) million related to our Other segment. Amounts 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 ledthe three and six months ended June 30, 2021, included $(3) million related to reduced estimates of expected future cash flows. Our fair value estimates also reflected discount rates of approximately 17 percent for these investments. We also considered any debt held at the investee level,our Gas & NGL Marketing services segment and ~~its impact~~$(5) million related to ~~fair value. The industry weighted-average discount rates utilized were significantly influenced by the market declines previously discussed.~~our Other segment.

(2)~~Following~~Amounts for the ~~previously described declining market conditions during~~three and six months ended June 30, 2022 related to our Gas & NGL Marketing Services segment.

Contingent Features

Generally, collateral may be provided by a parent guaranty, letter of credit, or cash. If collateral is required, fair value amounts recognized for the ~~first quarter~~right to reclaim cash collateral or the obligation to return cash collateral are offset against fair value amounts recognized for derivatives executed with the same counterparty.

We have specific trade and credit contracts that contain minimum credit rating requirements. These credit rating requirements typically give counterparties the right to suspend or terminate credit if our credit ratings are downgraded to non-investment grade status. Under such circumstances, we would need to post collateral to continue transacting business with these counterparties. As of ~~2020, we evaluated these investments for other-than-temporary impairment. The impairments within our Northeast G&P segment are primarily associated~~June 30, 2022, the contractually required collateral in the event of a credit rating downgrade to non-investment grade status was $17 million.

We maintain accounts 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~~brokers or the clearing houses 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~~certain exchanges to ~~6.2x EBITDA (weighted-average 6.0x). The fair values~~facilitate financial derivative transactions. Based on the value 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~~positions in these accounts and the associated margin requirements, we may be required to ~~13.5 percent (weighted-average 12.6 percent). We also considered any debt~~deposit cash into these accounts. At June 30, 2022, net cash collateral 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.on deposit in broker margin accounts was $247 million.

Note 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 putative class actions against us, our former affiliate WPX Energy, Inc. (WPX) and its subsidiaries, and others alleging the manipulation of published gas price indices in 2000 and 2002 and seeking unspecified amounts of damages. Such actions were


Notes (Continued)			Table of Contents

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)~~

InWe reached an agreement to settle two of the class actions, and on August 5, 2019, the final judgment of dismissal with prejudice was entered. We also reached an agreement to settle the individual action ~~filed by Farmland Industries Inc. (Farmland), the court issued an order~~and 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.~~ 18, 2022, it was dismissed.

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 to30, 2017, the Nevada federal district court and subsequently 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. On June 22, 2021, the appellate court ruled that we are not entitled to summary judgment and remanded the case to the Kansas federal district court. The court has scheduled trial to begin May 9, 2022.

~~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’~~plaintiff’s 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~~court, where the ~~actions, and on April 22, 2019, the Nevada federal district court preliminarily approved the settlements, which are on behalf of Kansas and Missouri~~plaintiffs re-urged their motion for class ~~members. The final fairness hearing on the settlement occurred August 5, 2019, and a final judgment of dismissal with prejudice was entered the same day.~~

certification. Two putative class actions remain unresolved and they have been remanded to their originally filed court, the Wisconsin federal district ~~court.~~ court, where the plaintiffs again re-urged their motion for class certification.

Trial was scheduled to begin June 14, 2021, but the court struck the setting due to the pending motion for class certification. On June 28, 2022, the court granted plaintiffs’ motion for class certification. On July 12, 2022, defendants filed a petition for permission to appeal the order with the United States Court of Appeals for the Seventh Circuit and ~~has not reset it.~~a motion to stay with the trial court.

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 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

~~Notes (Continued)~~

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


Notes (Continued)			Table of Contents

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 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. Oral argument was held on December 15, 2021. 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.

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 settlement to resolve substantially all Pennsylvania royalty cases pending, which settlement applies to both Chesapeake and us. The settlement does not require any contribution from ~~us and is awaiting~~us. On August 23, 2021, the court ~~approval.~~approved the settlement, but two objectors filed an appeal with the United States Court of Appeals for the Fifth Circuit.

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

~~Notes (Continued)~~

counterclaims. On June 27, 2016, we filed an appeal of the court’s decision with the Supreme Court of Delaware, seeking reversal and remand to pursue damages. On March 23, 2017, the Supreme Court of Delaware affirmed the Court of Chancery’s ruling. On March 30, 2017, we filed a motion for reargument with the Supreme Court of Delaware, which was denied on April 5, 2017.


Notes (Continued)			Table of Contents

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 originally scheduled trial for May 20 through May 24, 2019; the court struck that setting and reset trial to occur in 2020. All 2020 trial settings were struck due to COVID-19. Trial was held May 10 through May 17, 2021. Post-trial argument ~~is scheduled for~~occurred September 16, 2021. On December 29, 2021, the court entered judgment in our favor in the amount of $410 million, plus interest at the contractual rate, and our reasonable attorneys’ fees and expenses. After the court determines the amount of interest, attorneys’ fees, and costs, the judgment may be appealed to the Delaware Supreme Court.

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 June 30, ~~2021,~~2022, we have accrued liabilities totaling ~~$31~~$30 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 June 30, ~~2021,~~2022, 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~~propose and ~~propose~~promulgate 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,~~reviews 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 regardingupdates to the National Ambient Air Quality Standards, and rules for ~~ground-level ozone.~~new and existing source performance standards for volatile organic compound and methane. We ~~are monitoring the rule’s implementation as it will trigger additional federal~~continuously monitor these regulatory changes and ~~state regulatory actions that~~how they may impact our operations. Implementation of ~~the~~new or modified regulations ~~is expected to~~may result in impacts to our operations and increase the cost of additions to Property, plant, and equipment – net in ~~the~~our Consolidated Balance Sheet for both new and existing facilities in affected ~~areas. We~~areas; however, due to regulatory uncertainty on final rule content and applicability timeframes, we are unable to reasonably estimate the cost of ~~additions that may be required to meet the regulations~~these regulatory impacts at this ~~time due to uncertainty created by various legal challenges to these regulations and the need for further specific regulatory guidance.~~time.

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 June 30, ~~2021,~~2022, we have accrued liabilities of $4 million for these costs. We expect that these costs will be recoverable through rates.

~~Notes (Continued)~~

We also accrue environmental remediation costs for natural gas underground storage facilities, primarily related to soil and groundwater contamination. At June 30, ~~2021,~~2022, we have accrued liabilities totaling $8 million for these costs.


Notes (Continued)			Table of Contents

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 June 30, ~~2021,~~2022, we have accrued environmental liabilities of ~~$19~~$18 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 June 30, ~~2021,~~2022, 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 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, West, and ~~West.~~Gas & NGL Marketing Services. All remaining business activities are included in Other. (See Note 1 – General, Description of Business, and Basis of Presentation.)

~~Notes (Continued)~~

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


Notes (Continued)			Table of Contents

maker in measuring performance and allocating resources among our reportable segments. Intersegment Service revenues primarily represent transportation services provided to our marketing business and gathering services provided to our oil and gas properties. Intersegment Product sales primarily represent the sale of NGLs from our natural gas processing plants and our oil and gas properties 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.

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


	Three Months Ended June 30,				Six Months Ended June 30,
	2022		2021		2022		2021
	(Millions)
Modified EBITDA by segment:
Transmission & Gulf of Mexico	$	652	$	646	$	1,349	$	1,306
Northeast G&P	450		409		868		811
West	288		223		548		445
Gas & NGL Marketing Services	(282)		8		(269)		101
Other	139		20		144		53
	1,247		1,306		2,640		2,716
Accretion expense associated with asset retirement obligations for nonregulated operations	(13)		(11)		(24)		(21)
Depreciation and amortization expenses	(506)		(463)		(1,004)		(901)

Equity earnings (losses)	163		135		299		266

Other investing income (loss) – net	2		2		3		4
Proportional Modified EBITDA of equity-method investments	(250)		(230)		(475)		(455)
Interest expense	(281)		(298)		(567)		(592)
(Provision) benefit for income taxes	45		(119)		(73)		(260)

Net income (loss)	$	407	$	322	$	799	$	757

2932


Notes (Continued)			Table of Contents

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


		Transmission & Gulf of Mexico		Northeast G&P		West		Other		Eliminations		Total			Transmission & Gulf of Mexico		Northeast G&P		West		Gas & NGL Marketing Services (1)		Other		Eliminations		Total
															(Millions)
Three Months Ended June 30, 2022														Three Months Ended June 30, 2022
Segment revenues:														Segment revenues:
Service revenues														Service revenues
External														External	$	838	$	400	$	364	$	—	$	4	$	—	$	1,606
Internal														Internal	29		11		19		—		3		(62)		—
Total service revenues														Total service revenues	867		411		383		—		7		(62)		1,606
Total service revenues – commodity consideration														Total service revenues – commodity consideration	22		3		61		—		—		—		86
Product sales														Product sales
External														External	58		8		39		979		27		—		1,111
Internal														Internal	55		26		213		(107)		153		(340)		—
Total product sales														Total product sales	113		34		252		872		180		(340)		1,111
Net gain (loss) on commodity derivatives (2)														Net gain (loss) on commodity derivatives (2)	—		—		(9)		(313)		9		—		(313)
Total revenues														Total revenues	$	1,002	$	448	$	687	$	559	$	196	$	(402)	$	2,490
		(Millions)
Three Months Ended June 30, 2021	Three Months Ended June 30, 2021													Three Months Ended June 30, 2021
Segment revenues:	Segment revenues:													Segment revenues:
Service revenues	Service revenues													Service revenues
External	External	$	811	$	364	$	280	$	5	$	—	$	1,460	External	$	811	$	364	$	279	$	1	$	5	$	—	$	1,460
Internal	Internal	12		9		11		3		(35)		—		Internal	12		9		18		—		3		(42)		—
Total service revenues	Total service revenues	823		373		291		8		(35)		1,460		Total service revenues	823		373		297		1		8		(42)		1,460
Total service revenues – commodity consideration	Total service revenues – commodity consideration	10		2		39		0		0		51		Total service revenues – commodity consideration	10		2		39		—		—		—		51
Product sales	Product sales													Product sales
External	External	47		8		696		21		—		772		External	47		8		15		690		26		—		786
Internal	Internal	20		16		26		23		(85)		—		Internal	20		16		97		37		23		(193)		—
Total product sales	Total product sales	67		24		722		44		(85)		772		Total product sales	67		24		112		727		49		(193)		786
Net gain (loss) on commodity derivatives (2)														Net gain (loss) on commodity derivatives (2)	—		—		(5)		(4)		(5)		—		(14)
Total revenues	Total revenues	$	900	$	399	$	1,052	$	52	$	(120)	$	2,283	Total revenues	$	900	$	399	$	443	$	724	$	52	$	(235)	$	2,283

Three Months Ended June 30, 2020
Segment revenues:
Service revenues
External		$	783	$	342	$	316	$	5	$	—	$	1,446
Internal		12		12		0		4		(28)		—
Total service revenues		795		354		316		9		(28)		1,446
Total service revenues – commodity consideration		3		1		21		0		0		25
Product sales
External		29		(8)		289		0		—		310
Internal		7		9		14		0		(30)		—
Total product sales		36		1		303		0		(30)		310
Total revenues		$	834	$	356	$	640	$	9	$	(58)	$	1,781

Six Months Ended June 30, 2021
Segment revenues:
Service revenues
External		$	1,633	$	711	$	559	$	9	$	—	$	2,912
Internal		24		20		16		6		(66)		—
Total service revenues		1,657		731		575		15		(66)		2,912
Total service revenues – commodity consideration		21		5		74		0		0		100
Product sales
External		87		12		1,714		70		—		1,883
Internal		47		44		54		30		(175)		—
Total product sales		134		56		1,768		100		(175)		1,883
Total revenues		$	1,812	$	792	$	2,417	$	115	$	(241)	$	4,895

3033


Notes (Continued)			Table of Contents


		Transmission & Gulf of Mexico		Northeast G&P		West		Other		Eliminations		Total			Transmission & Gulf of Mexico		Northeast G&P		West		Gas & NGL Marketing Services (1)		Other		Eliminations		Total
		(Millions)													(Millions)

Six Months Ended June 30, 2020
Six Months Ended June 30, 2022														Six Months Ended June 30, 2022
Segment revenues:	Segment revenues:													Segment revenues:
Service revenues	Service revenues													Service revenues
External	External	$	1,597	$	686	$	627	$	10	$	—	$	2,920	External	$	1,683	$	770	$	680	$	1	$	9	$	—	$	3,143
Internal	Internal	27		26		0		7		(60)		—		Internal	58		21		34		—		7		(120)		—
Total service revenues	Total service revenues	1,624		712		627		17		(60)		2,920		Total service revenues	1,741		791		714		1		16		(120)		3,143
Total service revenues – commodity consideration	Total service revenues – commodity consideration	8		3		42		0		0		53		Total service revenues – commodity consideration	43		10		110		—		—		—		163
Product sales	Product sales													Product sales
External	External	70		15		636		0		—		721		External	109		13		50		1,994		49		—		2,215
Internal	Internal	18		15		26		0		(59)		—		Internal	104		57		389		(154)		235		(631)		—
Total product sales	Total product sales	88		30		662		0		(59)		721		Total product sales	213		70		439		1,840		284		(631)		2,215
Net gain (loss) on commodity derivatives (2)														Net gain (loss) on commodity derivatives (2)	—		—		(14)		(428)		(65)		—		(507)
Total revenues	Total revenues	$	1,720	$	745	$	1,331	$	17	$	(119)	$	3,694	Total revenues	$	1,997	$	871	$	1,249	$	1,413	$	235	$	(751)	$	5,014

June 30, 2021
Total assets (1)		$	19,575	$	14,470	$	10,448	$	2,570	$	(1,556)	$	45,507
December 31, 2020
Total assets		$	19,110	$	14,569	$	10,558	$	927	$	(999)	$	44,165
Six Months Ended June 30, 2021														Six Months Ended June 30, 2021
Segment revenues:														Segment revenues:
Service revenues														Service revenues
External														External	$	1,633	$	711	$	557	$	2	$	9	$	—	$	2,912
Internal														Internal	24		20		31		—		6		(81)		—
Total service revenues														Total service revenues	1,657		731		588		2		15		(81)		2,912
Total service revenues – commodity consideration														Total service revenues – commodity consideration	21		5		74		—		—		—		100
Product sales														Product sales
External														External	87		12		30		1,729		75		—		1,933
Internal														Internal	47		44		234		86		30		(441)		—
Total product sales														Total product sales	134		56		264		1,815		105		(441)		1,933
Net gain (loss) on commodity derivatives (2)														Net gain (loss) on commodity derivatives (2)	—		—		(7)		(38)		(5)		—		(50)
Total revenues														Total revenues	$	1,812	$	792	$	919	$	1,779	$	115	$	(522)	$	4,895

______________

(1) ~~The increase~~See Note 1 – General, Description of Business, and Basis of Presentation.

(2) We record transactions that qualify as derivatives at ~~our Other segment is primarily due to increased cash balance and the acquisitions of oil and gas properties~~fair value with changes in ~~2021. In February 2021, we acquired properties~~fair value recognized in earnings in the ~~Wamsutter field~~period of change and characterized as unrealized gains or losses. Gains and losses on derivatives held for energy trading purposes are presented on a net basis in Wyoming from a supermajor oil and gas company for approximately $79 million, a portion of which was paid in the prior year. We recorded $290 million of property, plant, and equipment and $207 million of ARO related to this transaction. In June 2021, we acquired additional properties also in the Wamsutter field in Wyoming from an oil and gas company for approximately $86 million in cash, which is net of approximately $48 million reflecting the full settlement of outstanding receivables. We recorded $257 million of property, plant, and equipment and $125 million of ARO related to this transaction. Our oil and gas exploration and production activities are accounted for under the successful efforts method.revenue.

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~~Notes (Continued)~~

Table of Contents

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

Three Months Ended
June 30, Six Months Ended
June 30,
2021 2020 2021 2020
(Millions)
Modified EBITDA by segment:
Transmission & Gulf of Mexico $ 646 $ 615 $ 1,306 $ 1,277
Northeast G&P 409 370 811 739
West 231 253 546 468
Other 20 8 53 15
1,306 1,246 2,716 2,499
Accretion expense associated with asset retirement obligations for nonregulated operations (11) (7) (21) (17)
Depreciation and amortization expenses (463) (430) (901) (859)
Impairment of goodwill 0 0 0 (187)
Equity earnings (losses) 135 108 266 130
Impairment of equity-method investments 0 0 0 (938)
Other investing income (loss) – net 2 1 4 4
Proportional Modified EBITDA of equity-method investments (230) (192) (455) (384)
Interest expense (298) (294) (592) (590)
(Provision) benefit for income taxes (119) (117) (260) 87
Net income (loss) $ 322 $ 315 $ 757 $ (255)

~~Note 13 – Subsequent Event~~

In July 2021, we completed the acquisition of 100 percent of Sequent Energy Management, L.P. and Sequent Energy Canada, Corp. (collectively, Sequent). Total consideration paid was $134 million, which includes $84 million of working capital acquired, and is subject to post-closing adjustment. Sequent focuses on asset management and the wholesale marketing, trading, storage, and transportation of natural gas for a diverse set of natural gas utilities and producers, and moves gas to markets through transportation and storage agreements on strategically positioned assets, including along our Transco system. Due to the recent closing of this acquisition, we have not provided all required disclosures as the information necessary is still under development. We plan to provide these disclosures in future filings.

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

General

We are an energy company committed to being the leader in providing infrastructure ~~company focused on connecting North America’s significant hydrocarbon resource plays to growing markets for~~that safely delivers natural gas ~~and NGLs through our gas pipeline and midstream business.~~products to reliably fuel the clean energy economy. 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~~The rates are established ~~in accordance with~~primarily through the FERC’s ratemaking ~~process.~~process, but we also may negotiate rates with our customers pursuant to the terms of our tariffs and FERC policy. 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: Transmission & Gulf of Mexico, Northeast G&P, West, and ~~West.~~Gas & NGL Marketing Services. All remaining business activities, including our ~~recently acquired~~ upstream operations ~~as well as~~and 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 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 of Caiman II 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 east Texas and northwest Louisiana, and the Mid-Continent region which includes the Anadarko 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.~~II, LLC.

•Gas & NGL Marketing Services includes our NGL and natural gas marketing and trading operations previously reported within the West segment prior to January 1, 2022, as well as the operations acquired in

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Management’s Discussion and Analysis (Continued)			Table of Contents

the Sequent Acquisition in 2021. This segment includes risk management and ~~Analysis (Continued)~~the storage and transportation of natural gas on strategically positioned assets, including our Transco system.

Dividends

In June ~~2021,~~2022, we paid a regular quarterly dividend of ~~$0.41~~$0.425 per share.

Overview of Six Months Ended June 30, ~~2021~~2022

Net income (loss) attributable to The Williams Companies, Inc., for the six months ended June 30, ~~2021,~~2022, increased ~~$944~~$50 million compared to the six months ended June 30, ~~2020, reflecting:~~

•~~The absence~~2021, reflecting the benefit of ~~$938 million of~~ ~~Impairment of equity-method investments~~higher service revenues from commodity-based gathering and processing rates and higher gathering volumes, including from the Trace Acquisition in the ~~first quarter~~West, as well as Transco’s Leidy South project placed in service during the second half of ~~2020;~~

•~~The absence~~2021, higher results from our upstream operations associated with increased scale of ~~$187 million of~~ ~~Impairment of goodwill~~ ~~in 2020, of which $65 million was attributable to noncontrolling interests;~~

•~~A $136 million favorable change in our~~operations, higher commodity margins, ~~primarily~~higher equity earnings, and favorable interest expense 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 $136 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 and higher volumes from certain of our Northeast G&P investments;

•~~A $100 million increase in~~ ~~Product sales~~ ~~at our Other segment reflecting sales related to our recently acquired upstream operations.~~

debt retirements. These favorable ~~changes~~impacts were partially offset ~~by:~~

•~~A $347~~by a $356 million unfavorable change in ~~provision for income taxes, driven by higher pre-tax earnings;~~

•~~$82~~net unrealized loss on commodity derivatives, increased intangible asset amortization, the absence of a $77 million ~~of higher~~ ~~Operating and maintenance expensesprimarily due to the inclusion of our recently acquired upstream operations at our Other segment~~favorable impact in 2021 from Winter Storm Uri, and higher ~~employee-related expenses;~~selling, general, and administrative expenses, primarily resulting from the Sequent Acquisition. The tax provision benefited from $134 million associated with the release of valuation allowances on deferred income tax assets and federal income tax settlements.

•~~A $42~~Our results include a $356 million unfavorable change in ~~Depreciation~~net unrealized losses from commodity derivatives not designated as hedges for accounting purposes. We can experience significant earnings volatility from the fair value accounting required for the derivatives used to hedge a portion of the economic value of the underlying transportation and ~~amortization expenses~~.storage marketing portfolio as well as upstream related production. However, the unrealized fair value measurement gains and losses are generally offset by valuation changes in the economic value of the underlying production or contracts, which is not recognized until the underlying transaction occurs.

The following discussion and analysis of results of operations and financial condition and liquidity should be read in conjunction with ~~the~~our consolidated financial statements and notes thereto of this Form 10‑Q and in Exhibit 99.1 of our ~~Annual Report on~~ Form ~~10-K~~8-K dated ~~February 24, 2021.~~May 2, 2022.

Recent Developments

~~Sequent~~Trace Acquisition

~~In July 2021,~~On April 29, 2022, we ~~completed~~closed on the acquisition of 100 percent of ~~Sequent Energy Management, L.P.~~Gemini Arklatex, LLC through which we acquired the Haynesville Shale region gas gathering and ~~Sequent Energy Canada, Corp. (collectively, Sequent). Total consideration paid was $134~~related assets of Trace Midstream (Trace Acquisition) for $972 million, ~~which includes $84 million of working capital acquired, and is~~ subject to post-closing ~~adjustment. Sequent focuses on asset management and~~adjustments. The purpose of the ~~wholesale marketing, trading, storage, and transportation~~Trace Acquisition was to expand our footprint into the east Texas area of ~~natural gas for a diverse set~~the Haynesville Shale region, increasing in-basin scale in one of natural gas utilities and producers, and moves gas to markets through transportation and storage agreements on strategically positioned assets, including along our Transco system. The addition of Sequent complements the ~~current geographic footprint of our core pipeline transportation and storage business and is expected to enhance our gas marketing capabilities.~~

~~Wamsutter Upstream Joint Venture~~

~~During the second quarter of 2021, we agreed to cross-convey certain of our oil and gas properties~~largest growth basins in the ~~Wamsutter field (see Note 12 - Segment Disclosures of Notes to Consolidated Financial Statements) to a venture~~

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

along with certain oil and gas properties cross-conveyed by a third-party operator in the region. The combined properties consist of over 1.2 million net acres and an interest in over 3,500 wells. Under the terms of the agreement which became effective during the third quarter of 2021, our partner owns a 25 percent undivided interest in each well’s working interest percentage, and we own a 75 percent undivided interest in each well’s working interest percentage.

~~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 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.country.

Company Outlook

Our strategy is to provide a large-scale, reliable, and clean 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 including seeking opportunities for renewable energy ventures, operational excellence, and customer satisfaction. We believe that accomplishing these goals will position us to deliver safe, ~~and~~ reliable, ~~service~~clean energy services to our customers and an attractive return to our shareholders. Our business plan for ~~2021~~2022 includes a continued focus on earnings and cash flow ~~growth, while continuing to improve leverage metrics and control operating costs.~~growth.

In ~~2021,~~2022, our operating results are expected to benefit from higher commodity prices and volume growth in our ~~Northeast G&P gathering~~Haynesville and ~~processing volumes.~~Ohio Valley Midstream areas. We also anticipate increases resulting from recently completed Transco expansion projects, development of our upstream oil and ~~higher Gulf~~gas properties, and our recently completed Trace


Management’s Discussion and Analysis (Continued)			Table of Contents

Acquisition. These increases are partially offset by the absence of ~~Mexico~~favorable results captured during Winter Storm Uri in 2021 by our Gas & NGL Marketing Services business and lower expected results in the Bradford Supply Hub primarily due to lower ~~planned hurricane impacts. Our results also benefited~~gathering rates resulting from ~~the overall net favorable impact~~annual cost of ~~unusually high natural gas prices~~service contract redeterminations.

We seek to maintain a strong financial position and liquidity, as well as manage a diversified portfolio of safe, clean, and reliable energy infrastructure assets that continue to serve key growth markets and supply basins 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 future value in upstream natural gas properties. We also expect a modest increase in expenses, including higher operating taxes.

United States. Our growth capital and investment expenditures in ~~2021~~2022 are expected to be in a range from ~~$1.0~~$2.25 billion to ~~$1.2~~$2.35 billion. Growth capital spending in ~~2021~~2022 primarily includes Transco expansions, all of which are fully contracted with firm transportation agreements, projects supporting the Northeast G&P business, ~~midstream opportunities~~the Trace Acquisition, and an expansion in the ~~Haynesville area~~Western Gulf area. We also expect to invest capital in the ~~West segment,~~development of our upstream oil and ~~the recent acquisitions of certain upstream operations and Sequent.~~gas properties. 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.

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

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;

•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 inflation and 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,~~2021, as filed with the SEC on February ~~24, 2021.~~

~~We seek to maintain a strong financial position and liquidity,~~28, 2022, as ~~well as manage a diversified portfolio of energy infrastructure assets that continue to serve key growth markets and supply basins~~supplemented by disclosures in ~~the United States.~~Part II, Item 1A. Risk Factors in subsequent Quarterly Reports on Form 10-Q.

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,~~2024, assuming timely receipt of all necessary regulatory approvals. The project is expected to increase capacity by 829 Mdth/d.

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Management’s Discussion and Analysis (Continued)			Table of Contents

Southside Reliability Enhancement

In May 2022, we filed an application with the FERC for the project which is an incremental expansion of Transco’s existing natural gas transmission system to provide firm transportation capacity from receipt points in Virginia and North Carolina to delivery points in North Carolina. The expansion project will add a total of approximately 423 Mdth/d of capacity. We plan to place the project into service as early as the 2024/2025 winter heating season assuming timely receipt of all necessary regulatory approvals.

West

Louisiana Energy Gateway

In June 2022, we announced our intention to construct new natural gas gathering assets which are expected to gather 1.8 Bcf/d of natural gas produced in the Haynesville Shale basin for delivery to premium markets, including Transco, industrial markets, and growing LNG export demand along the Gulf Coast. This project is expected to go into service in late 2024. We may consider a partner for this project.


Management’s Discussion and Analysis (Continued)			Table of Contents

Results of Operations

Consolidated Overview

The following table and discussion is a summary of our consolidated results of operations for the three and six months ended June 30, ~~2021,~~2022, compared to the three and six months ended June 30, ~~2020.~~2021. The results of operations by segment are discussed in further detail following this consolidated overview discussion.


		Three Months Ended June 30,							Six Months Ended June 30,								Three Months Ended June 30,							Six Months Ended June 30,
		2021		2020		$ Change*	% Change*		2021		2020		$ Change*	% Change*			2022		2021		$ Change*	% Change*		2022		2021		$ Change*	% Change*
		(Millions)							(Millions)								(Millions)							(Millions)
Revenues:	Revenues:															Revenues:
Service revenues	Service revenues	$	1,460	$	1,446	+14	+1	%	$	2,912	$	2,920	-8	—	%	Service revenues	$	1,606	$	1,460	+146	+10	%	$	3,143	$	2,912	+231	+8	%
Service revenues – commodity consideration	Service revenues – commodity consideration	51		25		+26	+104	%	100		53		+47	+89	%	Service revenues – commodity consideration	86		51		+35	+69	%	163		100		+63	+63	%
Product sales	Product sales	772		310		+462	+149	%	1,883		721		+1,162	+161	%	Product sales	1,111		786		+325	+41	%	2,215		1,933		+282	+15	%
Net gain (loss) on commodity derivatives																Net gain (loss) on commodity derivatives	(313)		(14)		-299	NM		(507)		(50)		-457	NM
Total revenues	Total revenues	2,283		1,781					4,895		3,694					Total revenues	2,490		2,283					5,014		4,895
Costs and expenses:	Costs and expenses:															Costs and expenses:
Product costs	Product costs	697		271		-426	-157	%	1,629		667		-962	-144	%	Product costs	857		697		-160	-23	%	1,660		1,629		-31	-2	%
Processing commodity expenses		18		15		-3	-20	%	39		28		-11	-39	%
Net processing commodity expenses																Net processing commodity expenses	40		18		-22	-122	%	70		39		-31	-79	%
Operating and maintenance expenses	Operating and maintenance expenses	379		320		-59	-18	%	739		657		-82	-12	%	Operating and maintenance expenses	465		379		-86	-23	%	859		739		-120	-16	%
Depreciation and amortization expenses	Depreciation and amortization expenses	463		430		-33	-8	%	901		859		-42	-5	%	Depreciation and amortization expenses	506		463		-43	-9	%	1,004		901		-103	-11	%
Selling, general, and administrative expenses	Selling, general, and administrative expenses	114		127		+13	+10	%	237		240		+3	+1	%	Selling, general, and administrative expenses	160		114		-46	-40	%	314		237		-77	-32	%

Impairment of goodwill		—		—		—	—	%	—		187		+187	+100	%

Other (income) expense – net	Other (income) expense – net	12		6		-6	-100	%	11		13		+2	+15	%	Other (income) expense – net	(10)		12		+22	NM		(19)		11		+30	NM
Total costs and expenses	Total costs and expenses	1,683		1,169					3,556		2,651					Total costs and expenses	2,018		1,683					3,888		3,556
Operating income (loss)	Operating income (loss)	600		612					1,339		1,043					Operating income (loss)	472		600					1,126		1,339
Equity earnings (losses)	Equity earnings (losses)	135		108		+27	+25	%	266		130		+136	+105	%	Equity earnings (losses)	163		135		+28	+21	%	299		266		+33	+12	%
Impairment of equity-method investments		—		—		—	—	%	—		(938)		+938	+100	%

Other investing income (loss) – net	Other investing income (loss) – net	2		1		+1	+100	%	4		4		—	—	%	Other investing income (loss) – net	2		2		—	—	%	3		4		-1	-25	%
Interest expense	Interest expense	(298)		(294)		-4	-1	%	(592)		(590)		-2	—	%	Interest expense	(281)		(298)		+17	+6	%	(567)		(592)		+25	+4	%
Other income (expense) – net	Other income (expense) – net	2		5		-3	-60	%	—		9		-9	-100	%	Other income (expense) – net	6		2		+4	+200	%	11		—		+11	NM
Income (loss) before income taxes	Income (loss) before income taxes	441		432					1,017		(342)					Income (loss) before income taxes	362		441					872		1,017
Less: Provision (benefit) for income taxes	Less: Provision (benefit) for income taxes	119		117		-2	-2	%	260		(87)		-347	NM		Less: Provision (benefit) for income taxes	(45)		119		+164	NM		73		260		+187	+72	%

Net income (loss)	Net income (loss)	322		315					757		(255)					Net income (loss)	407		322					799		757
Less: Net income (loss) attributable to noncontrolling interests	Less: Net income (loss) attributable to noncontrolling interests	18		12		-6	-50	%	27		(41)		-68	NM		Less: Net income (loss) attributable to noncontrolling interests	7		18		+11	+61	%	19		27		+8	+30	%
Net income (loss) attributable to The Williams Companies, Inc.	Net income (loss) attributable to The Williams Companies, Inc.	$	304	$	303				$	730	$	(214)				Net income (loss) attributable to The Williams Companies, Inc.	$	400	$	304				$	780	$	730

* + = 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.

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Management’s Discussion and Analysis (Continued)			Table of Contents

Three months ended June 30, ~~2021~~2022 vs. three months ended June 30, ~~2020~~2021

Service revenues increased primarily due to higher gathering rates driven by favorable commodity prices and annual contractual rate escalations for certain of our West and Northeast operations, higher gathering volumes including from the Trace Acquisition, higher transportation fee revenues associated with the Leidy South expansion ~~projects~~project placed fully in service at Transco in ~~2020~~December 2021, and ~~2021, the absence of certain 2020 Gulf of Mexico maintenance shut-ins,~~higher reimbursable electric power and ~~an increase in reimbursable electricity expenses~~storage costs, which isare substantially offset in Operating and maintenance expenses in our Northeast G&P segment. These increases were partially offset by lower volumes driven by production declines, lower deferred revenue amortization, and the absence of a temporary volume deficiency fee from a customer, in our West segment..

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.

Product sales increased primarily due to higher ~~net realized NGL~~marketing sales volumes of NGLs and natural gas, including the increase associated with the Sequent Acquisition in third-quarter 2021, higher sales prices and ~~higher natural gas~~ volumes associated with our ~~marketing activities, and~~upstream operations presented in our Other segment, higher ~~net realized~~sales prices related to our equity NGL sales ~~activities. This increase also includes our recently acquired upstream operations~~and gas marketing activities, and higher other product sales. These increases were partially offset by the impact of netting the 2022 legacy natural gas marketing revenues with the associated costs (see Note 121 – ~~Segment Disclosures~~General, Description of Business, and Basis of Presentation of Notes to Consolidated Financial Statements). As we are acting as agent for natural gas marketing customers of our Gas & NGL Marketing Services segment, our natural gas marketing product sales are ~~offset~~presented net of the related costs of those activities.

Net gain (loss) on commodity derivatives includes realized and unrealized gains and losses from derivative instruments reflected within ~~Product costs~~Total revenues. The unfavorable change primarily reflects net realized and unrealized losses in our Gas & NGL Marketing Services segment, as well as higher net realized losses related to derivative contracts in our Other and West segments. Higher net realized gains at our Other segment partially offset these impacts.

Product costs increased primarily due to higher ~~NGL and natural gas~~ prices ~~and higher natural gas volumes~~ for our NGL marketing activities, as well as higher NGL prices associated with volumes acquired as commodity consideration related to our equity NGL production ~~activities.~~activities, and higher other product costs. These increases were partially offset by the impact of netting the 2022 legacy natural gas marketing revenues with the associated costs.

Net processing commodity expenses increased primarily due to higher net realized prices for natural gas purchases associated with our equity NGL production activities, including a net gain from commodity derivatives related to these purchases in 2022. This net gain from commodity derivatives includes a realized gain in our West segment and an unrealized gain in our Gas & NGL Marketing segment.

The net sum of Service revenues – commodity consideration, Product sales, Product costs, net realized gains and ~~Processing~~losses on commodity derivatives related to sales of product, and net realized processing commodity expenses comprise our ~~commodity margins.~~Commodity margins. However, ~~Product~~Net realized product sales at our Other segment reflect sales of our upstream related ~~to our oil~~production net of the associated realized gains and ~~gas producing properties~~losses and are excluded from our commodity margins.

Operating and maintenance expenses increased primarily due to ~~the inclusion of~~higher operating costs including higher expenses associated with our ~~recently acquired~~ upstream operations, ~~as well as~~ higher ~~maintenance~~reimbursable electric power and ~~reimbursable electricity~~storage costs, which are substantially offset in Service revenues, higher employee-related expenses, and ~~higher employee-related expenses.~~increased costs associated with Transco's Leidy South expansion project placed in service in 2021.

Depreciation and amortization expensesincreased primarily due to ~~reduced estimated useful lives for~~amortization of intangibles acquired in the Sequent and Trace Acquisitions and an increase in depreciation at Transco related to ARO revisions (offset in Other (income) expense – net within Operating income (loss) resulting in no net impact on our results of operations), partially offset by the absence of 2021 depreciation on certain decommissioned facilities in our West ~~segment expected to be decommissioned during 2021, as well as the inclusion of our recently acquired upstream operations.~~segment.

Selling, general, and administrative expenses ~~decreased~~increased primarily due to ~~lower expenses for various corporate costs, partially offset by~~ higher employee-related ~~expenses.~~expenses, including those associated with the Sequent Acquisition, and Trace Acquisition costs.


Management’s Discussion and Analysis (Continued)			Table of Contents

Other (income) expense – net within Operating income (loss) changed favorably primarily due to the deferral of ARO depreciation (offset in Depreciation and amortization expenses resulting in no net impact on our results of operations).

Equity earnings (losses) changed favorably primarily due to an increase at ~~Appalachia Midstream Investments.~~Laurel Mountain.

Interest expensechanged favorably primarily due to the early retirement of notes, partially offset by interest on outstanding commercial paper (see Note 8 – Debt and Banking Arrangements of Notes to Consolidated Financial Statements).

Provision (benefit) for income taxes changed favorably primarily due to a benefit of $134 million related to the release of valuation allowances on certain federal and state deferred income tax assets and federal income tax settlements, as well as lower 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.

Six months ended June 30, ~~2021~~2022 vs. six months ended June 30, ~~2020~~2021

Service revenues ~~decreased~~increased primarily due to ~~lower volumes driven by production declines, lower~~higher gathering and processing rates ~~lower deferred revenue amortization,~~driven by favorable commodity prices and ~~the absence~~annual contractual rate escalations for certain of ~~a temporary volume deficiency fee from a customer, in~~ our West ~~segment. This decrease was partially offset by~~and Northeast operations, higher gathering volumes including from the Trace Acquisition, higher transportation fee revenues associated with the Leidy South expansion ~~projects~~project placed fully in service at Transco in ~~2020~~December 2021, and ~~2021,~~ higher ~~MVC revenue~~reimbursable electric power and storage costs, which are substantially offset in ~~our West segment, higher revenue associated with reimbursable electricity~~Operating and maintenance expenses ~~and an increase associated with Norphlet.~~.

Product salesincreased primarily due to higher ~~net realized~~marketing sales volumes of NGLs and natural gas, ~~and NGL~~including the increase associated with the Sequent Acquisition in third-quarter 2021, higher sales prices and ~~higher natural gas~~ volumes associated with our ~~marketing activities, and the inclusion of~~upstream operations presented in our ~~recently acquired upstream operations~~

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

~~(see Note 12 – Segment Disclosures of Notes to Consolidated Financial Statements). This increase also includes~~Other segment, higher sales prices related to our equity NGL sales ~~activities.~~activities, and higher other product sales. These increases were partially offset by the impact of netting the 2022 legacy natural gas marketing revenues with the associated costs (see Note 1 – General, Description of Business, and Basis of Presentation of Notes to Consolidated Financial Statements) and lower gas marketing sales prices related to the absence of severe winter weather in 2022 as compared to the first quarter of 2021. As we are acting as agent for natural gas marketing customers of our Gas & NGL Marketing Services segment, our natural gas marketing product sales are ~~partially offset within~~presented net of the related costs of those activities.

The unfavorable change in ~~Product costs~~Net gain (loss) on commodity derivatives. primarily reflects net realized and unrealized losses in our Gas & NGL Marketing Services and Other segments.

Product costs increased primarily due to higher ~~natural gas and NGL~~ prices ~~and higher natural gas volumes~~ for our NGL marketing activities, as well as higher NGL prices associated with volumes acquired as commodity consideration related to our equity NGL production ~~activities.~~activities, and higher other product costs. These increases were partially offset by the impact of netting the 2022 legacy natural gas marketing revenues with the associated costs.

~~Processing~~Net processing commodity expenses increased primarily due to higher net realized prices for natural gas purchases associated with our equity NGL production ~~activities.~~

~~The~~activities, including a net ~~sum of~~ ~~Service revenues –~~gain from commodity ~~consideration~~, ~~Product sales~~, ~~Product costs,~~ ~~and~~ ~~Processing commodity expenses~~ ~~comprise our commodity margins. However,~~ ~~Product sales~~ ~~at our Other segment reflect sales~~derivatives related to these purchases in 2022. This net gain from commodity derivatives includes a realized gain in our ~~oil~~West segment and ~~gas producing properties and are excluded from~~an unrealized gain in our ~~commodity margins.~~Gas & NGL Marketing segment.

Operating and maintenance expenses increased primarily due to ~~the inclusion of~~higher operating costs including higher expenses associated with our ~~recently acquired~~ upstream operations, ~~as well as~~ higher ~~maintenance~~reimbursable electric power and ~~reimbursable electricity expenses,~~storage costs which are substantially offset in Service revenues, increased costs associated with Transco's Leidy South expansion project placed in service in 2021, and higher employee-related expenses.


Management’s Discussion and Analysis (Continued)			Table of Contents

Depreciation and amortization expensesincreased primarily due to ~~reduced estimated useful lives for~~amortization of intangibles acquired in the Sequent and Trace Acquisitions and an increase in depreciation at Transco related to ARO revisions (offset in Other (income) expense – net within Operating income (loss) resulting in no net impact on our results of operations), partially offset by the absence of 2021 depreciation on certain decommissioned facilities in our West ~~segment expected to be decommissioned during 2021, the inclusion of our recently acquired upstream operations, as well as new assets placed in-service at Transco.~~segment.

Selling, general, and administrative expenses ~~decreased~~increased primarily due to ~~lower~~higher employee-related and other general expenses, ~~for various corporate costs,~~primarily resulting from the Sequent Acquisition, as well as Trace Acquisition costs.

Equity earnings (losses) changed favorably primarily due to increases at Laurel Mountain and RMM, offset by a decrease at Appalachia Midstream Investments.

Interest expense changed favorably primarily due to the early retirement of notes, partially offset by ~~higher employee-related expenses.~~

~~Impairment of goodwill~~ ~~reflects the 2020 charge at the Northeast reporting unit~~interest on outstanding commercial paper (see Note 108 – ~~Fair Value Measurements~~Debt and ~~Guarantees~~Banking Arrangements of Notes to Consolidated Financial Statements).

~~Equity earnings (losses)~~The favorable change in ~~changed favorably primarily due to the absence of the 2020 impairment of goodwill at RMM, increases at Appalachia Midstream Investments and Discovery, 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).~~

Other income (expense) – net ~~includes~~below Operating income (loss) reflects the ~~unfavorable impact~~absence of an accrual for a loss contingency in 2021.

Provision (benefit) for income taxes changed ~~unfavorably~~favorably primarily due to ~~higher~~a benefit of $134 million related to the release of valuation allowances on certain federal and state deferred income tax assets and federal income tax settlements, as well as lower 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. Note 12 – 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 June 30,				Six Months Ended June 30,
	2022		2021		2022		2021
	(Millions)
Service revenues	$	867	$	823	$	1,741	$	1,657
Service revenues – commodity consideration	22		10		43		21
Product sales	113		67		213		134
Segment revenues	1,002		900		1,997		1,812

Product costs	(109)		(68)		(209)		(134)
Net processing commodity expenses	(15)		(2)		(21)		(6)
Other segment costs and expenses	(271)		(230)		(511)		(459)

Proportional Modified EBITDA of equity-method investments	45		46		93		93
Transmission & Gulf of Mexico Modified EBITDA	$	652	$	646	$	1,349	$	1,306

Commodity margins	$	11	$	7	$	26	$	15


Management’s Discussion and Analysis (Continued)			Table of Contents

~~Transmission & Gulf of Mexico~~

Three Months Ended
June 30, Six Months Ended
June 30,
2021 2020 2021 2020
(Millions)
Service revenues $ 823 $ 795 $ 1,657 $ 1,624
Service revenues – commodity consideration
10 3 21 8
Product sales 67 36 134 88
Segment revenues 900 834 1,812 1,720
Product costs (68) (37) (134) (89)
Processing commodity expenses (2) (1) (6) (3)
Other segment costs and expenses (230) (223) (459) (437)
Proportional Modified EBITDA of equity-method investments 46 42 93 86
Transmission & Gulf of Mexico Modified EBITDA $ 646 $ 615 $ 1,306 $ 1,277
Commodity margins $ 7 $ 1 $ 15 $ 4

Three months ended June 30, ~~2021~~2022 vs. three months ended June 30, ~~2020~~2021

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

Service revenues increased primarily due to a $51 million increase in Transco’s natural gas transportation and storage revenues primarily associated with the Leidy South expansion project placed fully in service in December 2021 and higher storage rates effective during the second quarter of 2022. The 2022 quarter also benefited from higher reimbursable electric power costs, which is offset by a similar change in electricity charges reflected in Other segment costs and expenses.

Other segment costs and expenses increased primarily due to higher operating costs, including costs associated with the Leidy South expansion project, higher reimbursable electric power costs and storage costs, which are offset by a similar change in electricity reimbursements and storage revenues, reflected in Service revenues, and higher employee-related costs. These increases are partially offset by a favorable change in the deferral of ARO related depreciation at Transco.

Six months ended June 30, 2022 vs. six months ended June 30, 2021

Transmission & Gulf of Mexico Modified EBITDA increased primarily due to a favorable change to Service revenuesand Commodity margins, partially offset by higher Other segment costs and expenses.

Service revenues increased primarily due ~~to:~~

•~~A $19~~to a $91 million increase in Transco’s natural gas transportation and storage revenues primarily associated with the Leidy South expansion ~~projects~~project placed fully in service in ~~2020~~December 2021 and ~~2021;~~higher storage rates effective during the second quarter of 2022. The 2022 period also benefited from higher reimbursable electric power costs, which is offset by a similar change in electricity charges reflected in Other segment costs and expenses.

•Commodity margins~~A $12 million increase in the Western Gulf Coast region primarily due to the absence of temporary shut-ins in 2020 related to scheduled maintenance.~~

~~The increase in~~ ~~Product sales~~ ~~includes an 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.~~ ~~Our commodity margins~~ associated with our equity NGLs increased $5$10 million primarily driven by favorable NGL sales ~~prices.~~prices, partially offset by higher prices for natural gas purchases associated with our equity NGL production activities.

~~Six~~


Management’s Discussion and Analysis (Continued)			Table of Contents

Northeast G&P


	Three Months Ended June 30,				Six Months Ended June 30,
	2022		2021		2022		2021
	(Millions)
Service revenues	$	411	$	373	$	791	$	731
Service revenues – commodity consideration	3		2		10		5
Product sales	34		24		70		56
Segment revenues	448		399		871		792

Product costs	(34)		(26)		(71)		(58)
Net processing commodity expenses	(2)		—		(2)		—

Other segment costs and expenses	(136)		(126)		(254)		(238)

Proportional Modified EBITDA of equity-method investments	174		162		324		315
Northeast G&P Modified EBITDA	$	450	$	409	$	868	$	811

Commodity margins	$	1	$	—	$	7	$	3

Three months ended June 30, ~~2021~~2022 vs. ~~six~~three months ended June 30, ~~2020~~2021

~~Transmission & Gulf of Mexico~~Northeast G&P Modified EBITDA increased primarily due to ~~favorable changes to~~higher Service revenuesand higher ~~Commodity margins~~Proportional Modified EBITDA of equity-method investments, partially offset by higherOther segment costs and ~~expenses.~~expenses.

Service revenues increased primarily due to:

•A ~~$36~~$15 million increase in ~~Transco’s natural gas transportation~~ revenues at the Northeast JV primarily ~~associated with expansion projects placed in service in 2020~~related to higher processing and ~~2021, partially offset by one less billing day;~~gathering volumes;

•A ~~$16 million increase associated with Norphlet;~~

•~~An $11~~$10 million increase in ~~the Western Gulf Coast region~~revenues at Susquehanna Supply Hub primarily ~~due to the absence of temporary shut-ins in 2020~~ related to ~~scheduled maintenance;~~higher gathering rates resulting from annual rate escalation, partially offset by lower gathering volumes;

•A ~~$16~~$10 million ~~decrease due to lower volumes primarily from certain Eastern Gulf Coast region operations due to producer operational issues;~~

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

•~~An $8 million decrease at Gulfstar One for the Tubular Bells field primarily due to lower deferred revenue amortization.~~

~~The~~ increase in ~~Product sales~~ ~~includes an increase~~revenues in ~~commodity marketing sales~~the Utica Shale region primarily ~~due~~related to higher ~~NGL prices. Marketing sales are substantially offset in~~ ~~Product costs~~ ~~and therefore have little impact to~~ ~~Modified EBITDA.~~ ~~Our commodity margins associated with our equity NGLs increased $9 million primarily driven by favorable NGL sales prices.~~gathering rates resulting from annual cost of service contract redetermination.

Other segment costs and expenses increased primarily due to higher ~~employee-related costs and an unfavorable change in allowance for equity funds used during construction.~~operating expenses.

Proportional Modified EBITDA of equity-method investments increased at ~~Discovery~~Laurel Mountain due to higher commodity-based gathering rates and higher MVC revenue, partially offset by a decrease at Appalachia Midstream Investments primarily driven by ~~higher volumes due to absence~~lower gathering rates resulting from annual cost of ~~prior year scheduled maintenance and temporary shut-ins related to Gulf of Mexico weather-related events and pricing.~~service contract redetermination.

~~Northeast G&P~~

Three Months Ended
June 30, Six Months Ended
June 30,
2021 2020 2021 2020
(Millions)
Service revenues $ 373 $ 354 $ 731 $ 712
Service revenues – commodity consideration
2 1 5 3
Product sales 24 1 56 30
Segment revenues 399 356 792 745
Product costs (26) — (58) (29)
Processing commodity expenses — (1) — (2)
Other segment costs and expenses (126) (111) (238) (221)
Proportional Modified EBITDA of equity-method investments 162 126 315 246
Northeast G&P Modified EBITDA $ 409 $ 370 $ 811 $ 739
Commodity margins $ — $ 1 $ 3 $ 2

~~Three~~Six months ended June 30, ~~2021~~2022 vs. ~~three~~six months ended June 30, ~~2020~~2021

Northeast G&P Modified EBITDA increased primarily due to ~~increased~~higher Service revenues and higher Proportional Modified EBITDA of equity-method investments ~~and higher~~ ~~Service revenues~~, partially offset by ~~increased~~higher Other segment costs and expenses.

Service revenues increased primarily due to:

•A ~~$10~~$20 million increase in revenues at the Northeast JV primarily related to higher processing volumes;

•A $19 million increase in revenues at Susquehanna Supply Hub primarily related to higher gathering rates resulting from annual rate escalation, partially offset by lower gathering volumes;

•A $9 million increase in revenues in the Utica Shale region primarily related to higher gathering rates resulting from annual cost of service contract redetermination;


Management’s Discussion and Analysis (Continued)			Table of Contents

•A $9 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~~;

•~~A $7 million increase in revenues at the Northeast JV primarily related to higher processing and fractionation volumes.~~

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

Other segment costs and expenses increased primarily due to higher ~~maintenance and~~ operating expenses, including higher electricity charges.

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

Proportional Modified EBITDA of equity-method investments increased at Laurel Mountain due to higher commodity-based gathering rates and higher MVC revenue, partially offset by a decrease at Appalachia Midstream Investments primarily driven by ~~higher volumes. Additionally, there was an increase at Blue Racer/Caiman II due to the favorable impact~~lower gathering rates resulting from annual cost of ~~increased ownership, partially offset by the absence of a gain on early debt retirement at Blue Racer in the second quarter of 2020.~~service contract redetermination.

~~Six~~

West


	Three Months Ended June 30,				Six Months Ended June 30,
	2022		2021		2022		2021
	(Millions)
Service revenues	$	383	$	297	$	714	$	588
Service revenues – commodity consideration	61		39		110		74
Product sales	252		112		439		264
Net gain (loss) on commodity derivatives	(9)		(5)		(14)		(7)
Segment revenues	687		443		1,249		919

Product costs	(247)		(104)		(429)		(241)
Net processing commodity expenses	(37)		(16)		(63)		(33)
Other segment costs and expenses	(146)		(122)		(267)		(247)

Proportional Modified EBITDA of equity-method investments	31		22		58		47
West Modified EBITDA	$	288	$	223	$	548	$	445

Commodity margins	$	25	$	26	$	48	$	57

Three months ended June 30, ~~2021~~2022 vs. ~~six~~three months ended June 30, ~~2020~~2021

~~Northeast G&P~~West Modified EBITDA increased primarily due to ~~increased~~ ~~Proportional Modified EBITDA of equity-method investments~~ ~~and~~ higher Service revenues, partially offset by ~~increased~~higher Other segment costs and expenses.

Service revenues increased primarily due to:

•A ~~$12~~$50 million increase in ~~revenues~~the Haynesville Shale region primarily associated with ~~reimbursable electricity expenses, which is~~higher gathering volumes including from the Trace Acquisition (see Note 3 – Acquisitions of Notes to Consolidated Financial Statements)in April 2022 as well as higher gathering rates driven by favorable commodity pricing;

•A $34 million increase in the Barnett Shale region primarily due to higher gathering rates driven by favorable commodity pricing.

Product margins from our equity NGLs decreased $1 million, primarily due to higher net realized prices for natural gas purchases associated with our equity NGLs production activities and lower non-ethane sales volumes, substantially offset by ~~similar changes~~higher net realized commodity sales prices.

Other segment costs and expenses changed unfavorably primarily due to higher operating expenses and expenses associated with our Trace Acquisition in ~~electricity charges, reflected~~April 2022.

Proportional Modified EBITDA of equity-method investments increased primarily due to higher commodity prices at RMM.


Management’s Discussion and Analysis (Continued)			Table of Contents

Six months ended June 30, 2022 vs. six months ended June 30, 2021

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

Service revenues increased primarily due to:

•A $68 million increase in the Haynesville Shale region primarily due to higher gathering volumes including from the Trace Acquisition as well as higher gathering rates driven by favorable commodity pricing;

•A $42 million increase in the Barnett Shale region primarily due to higher gathering rates driven by favorable commodity pricing;

•A $25 million increase in the Piceance region primarily driven by higher processing rates driven by favorable commodity pricing; partially offset by

•An $11 million decrease associated with lower MVC revenue in the Wamsutter region;

•A $2 million decrease in the Eagle Ford Shale region primarily due to a production decline, substantially offset by higher MVC revenue.

Marketing margins decreased $17 million, primarily due to the absence of severe winter weather in the first quarter of 2022 as compared to 2021. Product margins from our equity NGLs were zero with higher net realized commodity sales prices offset by higher net realized prices for natural gas purchases associated with our equity NGLs production activities and lower non-ethane sales volumes. Other product margins increased $8 million primarily due to higher commodity prices.

Other segment costs and expenses changed unfavorably primarily due to higher operating expenses and expenses associated with our Trace Acquisition in April 2022.

Proportional Modified EBITDA of equity-method investments increased primarily due to higher commodity prices at RMM.

Gas & NGL Marketing Services


	Three Months Ended June 30,				Six Months Ended June 30,
	2022		2021		2022		2021
	(Millions)
Service revenues	$	—	$	1	$	1	$	2
Product sales	872		727		1,840		1,815

Net realized gain (loss) from derivative instruments	(16)		(1)		(72)		(35)
Net unrealized gain (loss) from derivative instruments	(297)		(3)		(356)		(3)
Net gain (loss) on commodity derivatives	(313)		(4)		(428)		(38)

Segment revenues	559		724		1,413		1,779
Net unrealized gain (loss) from derivative instruments within Net processing commodity expenses	9		—		11		—
Product costs	(833)		(713)		(1,645)		(1,672)
Other segment costs and expenses	(17)		(3)		(48)		(6)
Gas & NGL Marketing Services Modified EBITDA	$	(282)	$	8	$	(269)	$	101

Commodity margins	$	23	$	13	$	123	$	108


Management’s Discussion and Analysis (Continued)			Table of Contents

Three months ended June 30, 2022 vs. three months ended June 30, 2021

Gas & NGL Marketing Services Modified EBITDA decreased primarily due to higher net unrealized loss from derivative instruments and higher Other segment costs and expenses;, partially offset by higher Commodity margins.

Commodity margins increased $10 million primarily due to:

•A $9$7 million increase in ~~revenues at the Northeast JV primarily related to higher processing and fractionation volumes; partially offset by~~

•~~An $8 million decrease associated with lower gathering volumes at Susquehanna Supply Hub.~~

~~Product sales~~ ~~increased~~NGL marketing margins primarily due to higher net realized prices on sales ~~prices~~ of ~~NGLs associated with~~inventory;

•A $3 million increase from our natural gas marketing ~~activities, which were~~operations including $13 million of higher natural gas transportation capacity marketing margins due to favorable net realized commodity pricing, partially offset by $10 million lower ~~sales volumes. Marketing sales~~natural gas storage marketing margins due to a second-quarter 2022 charge related to a lower of cost or net realizable value inventory adjustment.

Net unrealized gain (loss) from derivative instruments relates to derivative contracts that are ~~offset by similar changes~~not designated as hedges for accounting purposes. The change from 2021 is primarily related to the Sequent Acquisition in ~~marketing purchases, reflected above as~~ ~~Product costs~~,July 2021 and ~~therefore have little impact to~~ ~~Modified EBITDA~~.the discontinuance of hedge accounting for new hedges beginning in the second half of 2021.

Other segment costs and expenses increased primarily due to higher ~~maintenance and operating expenses, including higher electricity charges.~~

~~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 primarily due~~employee-related costs related to the ~~favorable impact of increased ownership, partially offset by the absence of a gain on early debt retirement at Blue Racer in the second quarter of 2020.~~Sequent Acquisition.

~~West~~

Three Months Ended
June 30, Six Months Ended
June 30,
2021 2020 2021 2020
(Millions)
Service revenues $ 291 $ 316 $ 575 $ 627
Service revenues – commodity consideration
39 21 74 42
Product sales 722 303 1,768 662
Segment revenues 1,052 640 2,417 1,331
Product costs (704) (281) (1,640) (649)
Processing commodity expenses (16) (13) (33) (23)
Other segment costs and expenses (123) (117) (245) (243)
Proportional Modified EBITDA of equity-method investments 22 24 47 52
West Modified EBITDA $ 231 $ 253 $ 546 $ 468
Commodity margins $ 41 $ 30 $ 169 $ 32

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

~~Three~~Six months ended June 30, ~~2021~~2022 vs. ~~three~~six months ended June 30, ~~2020~~2021

~~West~~Gas & NGL Marketing Services Modified EBITDAdecreased primarily due to ~~lower~~ ~~Service revenues~~higher net unrealized loss from derivative instruments and higher Other segment costs and expenses, partially offset by higher Commodity margins.

~~Service revenues~~Commodity margins ~~decreased~~increased $15 million primarily due to:

•~~A $10~~An $8 million ~~decrease~~increase in natural gas marketing margins which included the following:

•An $86 million increase in natural gas transportation capacity marketing margins primarily associated with ~~lower volumes, primarily due to production declines in~~ the ~~Haynesville Shale region;~~Sequent Acquisition;

•A $9$5 million ~~decrease related to lower deferred revenue amortization primarily~~increase in ~~the Barnett Shale region;~~

•~~A $9 million decrease due to the absence of a temporary volume deficiency fee from a customer in 2020.~~

•Higher gathering rates in the Barnett Shale region and higher processing rates in the Piceance region, both driven by favorable commodity pricing, were substantially offset by lower gathering rates in the Haynesville Shale region due to a customer contract change.

~~The net sum of~~ ~~Service revenues~~ – ~~commodity consideration, Product sales, Product costs,~~ ~~and~~ ~~Processing commodity expenses~~ ~~comprise our commodity~~natural gas storage marketing margins ~~which we further segregate into product margins associated with our equity NGLs and marketing margins. Product margins from our equity NGLs increased $7 million, primarily~~ due to higher net realized sales prices, partially offset by lower sales volumes and an increase in natural gas purchases associated with our equity NGLs. Commodity marketing sales increased primarily due to higher net realized NGL and natural gas prices. Marketing sales are substantially offset in ~~Product costs~~ ~~and therefore have little impact to~~ ~~Modified EBITDA~~.

~~Six months ended June 30, 2021 vs. six months ended June 30, 2020~~

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

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

•A $47 million decrease associated with lower volumes, primarily due to production declines in the Eagle Ford Shale region which impact is substantially offset by the recognition of higher MVC revenue (see below). Additionally, lower volumes in the Haynesville Shale region were impacted by production declines;

•A $25 million decrease associated with lower gathering rates in the Haynesville Shale region due to a customer contract change and lower processing rates in the Piceance region driven primarily by unfavorable commodity ~~pricing. These decreases are partially offset by an increase in gathering rates in the Barnett Shale region primarily due to favorable commodity pricing;~~

•~~An $18 million decrease related to lower deferred revenue amortization primarily in the Barnett Shale region;~~

•~~A $9 million decrease due to the absence of a temporary volume deficiency fee from a customer in 2020;~~prices; partially offset by

•A ~~$36~~$58 million ~~increase~~decrease associated with ~~higher MVC revenue, primarily in the Eagle Ford Shale and Wamsutter regions;~~

•An $11 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~~.

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

~~Marketing margins increased by $122 million~~our legacy natural gas marketing operations primarily due to ~~favorable changes in~~lower net realized natural gas ~~and NGL~~ prices ~~including~~from the ~~impact~~absence of severe winter weather in the first quarter of ~~2021. Product~~2022 as compared to the first quarter of 2021;

•A $15 million charge in 2022 related to the remaining recognition of a purchase accounting inventory fair value adjustment which increased the weighted-average cost of inventory; and

•A $10 million charge related to a lower of cost or net realizable value inventory adjustment in 2022;

•A $7 million increase in our NGL marketing margins ~~from our equity NGLs increased $11 million,~~ primarily due to higher net realized ~~sales~~commodity prices ~~partially offset by an increase~~and higher volumes.

Net unrealized gain (loss) from derivative instruments changed significantly primarily due to the Sequent Acquisition in ~~natural gas purchases associated with our equity NGLs~~July 2021 and ~~lower sales volumes.~~the discontinuance of hedge accounting for new hedges beginning in the second half of 2021.

Other segment costs and expenses increased primarily due to higher ~~maintenance expenses including costs associated with the timing and scope of activities as well as higher reimbursable compressor power and fuel purchases which are offset in~~ ~~Service revenues. These increases are partially offset by lower operating expenses including~~employee-related costs related to ~~fewer leased compressors.~~the Sequent Acquisition.

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


Management’s Discussion and Analysis (Continued)			Table of Contents

Other

Three Months Ended June 30, Six Months Ended June 30,
2021 2020 2021 2020
(Millions)
Other Modified EBITDA $ 20 $ 8 $ 53 $ 15


	Three Months Ended June 30,				Six Months Ended June 30,
	2022		2021		2022		2021
	(Millions)
Service revenues	$	7	$	8	$	16	$	15
Product sales	180		49		284		105

Net realized gain (loss) from derivative instruments	(38)		—		(46)		—
Net unrealized gain (loss) from derivative instruments	47		(5)		(19)		(5)
Net gain (loss) on commodity derivatives	9		(5)		(65)		(5)

Segment revenues	196		52		235		115

Other segment costs and expenses	(57)		(32)		(91)		(62)
Other Modified EBITDA	$	139	$	20	$	144	$	53

Net realized product sales	$	142	$	49	$	238	$	105

Three ~~and six~~ months ended June 30, ~~2021~~2022 vs. three ~~and six~~ months ended June 30, ~~2020~~2021

Other Modified EBITDA increased primarily due to $117 million higher results from our ~~recently acquired~~ upstream operations ~~including~~which included the following:

•A $93 million increase in Net realized product sales primarily due to higher net realized commodity prices in the second quarter of 2022 and higher volumes associated with acquisitions of additional ownership interests in the second and third quarters of 2021 and higher production from new wells;

•A $52 million favorable change in Net unrealized gain (loss) from derivative instruments due to a change in forward commodity ~~price impact~~prices relative to our hedge positions and an increase in the volume of ~~severe~~production hedged in 2022 compared to 2021; partially offset by

•A $28 million increase in Other segment costs and expenses primarily related to higher expenses associated with the increased scale of our upstream operations and higher production and property taxes associated with higher commodity prices.

Six months ended June 30, 2022 vs. six months ended June 30, 2021

Other Modified EBITDA increased primarily due to $85 million higher results from our upstream operations which included the following:

•A $133 million increase in Net realized product sales primarily due to higher volumes associated with acquisitions of additional ownership interests in the second and third quarters of 2021 and higher production from new wells. Net realized product sales also increased due to higher net realized commodity prices in the second quarter of 2022, partially offset by lower prices from the absence of winter weather in the first quarter of ~~2021. See Note 12 – Segment Disclosures~~2022 compared to the first quarter of ~~Notes~~2021; partially offset by

•A $14 million unfavorable change in Net unrealized gain (loss) from derivative instruments due to ~~Consolidated Financial Statements. The year-to-date comparative period~~a change in forward commodity prices relative to our hedge positions and an increase in production hedged in 2022 compared to 2021; and


Management’s Discussion and Analysis (Continued)			Table of Contents

•A $34 million increase in Other segment costs and expenses primarily related to higher expenses associated with the increased scale of our upstream operations and higher production and property taxes associated with higher commodity prices.

Other segment costs and expenses also ~~includes~~reflects a $10 million favorable impact for the ~~unfavorable impact~~absence of an accrual for a loss contingency in 2021.

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Management’s Discussion and Analysis (Continued)			Table of Contents

Management’s Discussion and Analysis of Financial Condition and Liquidity

Outlook

~~As previously discussed in Company Outlook, our~~Our growth capital and investment expenditures in ~~2021~~2022 are currently expected to be in a range from ~~$1.0~~$2.25 billion to ~~$1.2~~$2.35 billion. Growth capital spending in ~~2021~~2022 primarily includes Transco expansions, all of which are fully contracted with firm transportation agreements, projects supporting the Northeast G&P business, ~~midstream opportunities~~the Trace Acquisition, and an expansion in the ~~Haynesville area~~Western Gulf area. We also expect to invest capital in the ~~West segment,~~development of our upstream oil and ~~the recent acquisitions of certain upstream operations and Sequent.~~gas properties. 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 funded the Trace Acquisition with available sources of short-term liquidity and intend to fund substantially all ~~of our~~additional planned ~~2021~~2022 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.~~opportunities including the repurchase of our common stock.

In the first half of 2021, we acquired various oil and gas properties in the Wamsutter field in Wyoming, funding the $165 million paid with cash on hand (see Note 12 – Segment Disclosures of Notes to Consolidated Financial Statements). In July 2021, we acquired Sequent, funding the $134 million paid with cash on hand (see Note 13 – Subsequent Event of Notes to Consolidated Financial Statements).

During the first quarter of 2022, we early retired $1.25 billion of 3.6 percent senior unsecured notes that were scheduled to mature in March 2022 using proceeds from our October 2021 debt offering. During the second quarter of 2022, we ~~issued $900~~early retired $750 million of ~~new long-term debt~~3.35 percent senior unsecured notes that were scheduled to ~~fund the repayment~~mature in August 2022 using issuances of ~~long-term debt maturing in 2021 and for general corporate purposes.~~commercial paper. As of June 30, ~~2021,~~2022, we have ~~approximately $2.1 billion~~$876 million of long-term debt due within one ~~year.~~year and $1.040 billion of Commercial paper outstanding (at par value). 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, or our commercial paper program, as well as proceeds from asset monetizations. ~~In August 2021, we expect to early retire our $500 million of 4 percent senior unsecured notes that are scheduled to mature in November 2021.~~

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.~~2022. 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
			Repayments of borrowings under our credit facility and/or commercial paper program
			Debt service payments, including payments of long-term debt
			Distributions to noncontrolling interests
			Share repurchase program

As of June 30, ~~2021,~~2022, we have ~~approximately $21.1~~$20.8 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, or our commercial paper program, as well as proceeds from asset monetizations.

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Management’s Discussion and Analysis (Continued)			Table of Contents

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

As of June 30, ~~2021,~~2022, we had a working capital deficit of ~~$1.134~~$2.051 billion, including cash and cash equivalents, ~~and~~ long-term debt due within one ~~year.~~year, and commercial paper. Our available liquidity is as follows:


Available Liquidity	June 30, ~~2021~~2022
	(Millions)
Cash and cash equivalents	$	~~1,201~~133
Capacity available under our ~~$4.5~~$3.75 billion credit facility, less amounts outstanding under our $4$3.5 billion commercial paper program (1)	~~4,500~~2,710
	$	~~5,701~~2,843

(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~~$1.040 billion of Commercial paper (at par value) outstanding as of June 30, ~~2021.~~2022. Through June 30, ~~there was no~~2022, the highest amount outstanding under our commercial paper program and credit facility during ~~2021.~~2022 was $1.219 billion. At June 30, ~~2021,~~2022, we were in compliance with the financial covenants associated with our credit facility. Borrowing capacity under our credit facility as of July 28, 2022 was $2.712 billion.

Dividends

We increased our regular quarterly cash dividend to common stockholders by approximately ~~2.5~~3.7 percent from the ~~$0.40~~$0.41 per share paid in each quarter of ~~2020,~~2021, to ~~$0.41~~$0.425 per share paid in March and June ~~2021.~~

~~Registrations~~

~~In February 2021, we filed a shelf registration statement as a well-known seasoned issuer.~~2022.

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

Stable

Baa2

Fitch Ratings

Stable

BBB

~~In June 2021, Moody’s upgraded our credit rating from Baa3 to Baa2, and changed our Outlook from Positive to Stable.~~

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, if ratings were to fall below investment-grade, could require us to provide additional collateral to third parties, negatively impacting our available liquidity.

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Management’s Discussion and Analysis (Continued)			Table of Contents

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	Six Months Ended June 30,					Cash Flow	Six Months Ended June 30,
		Category	2021		2020			Category	2022		2021
			(Millions)						(Millions)
Sources of cash and cash equivalents:	Sources of cash and cash equivalents:						Sources of cash and cash equivalents:
Operating activities – net	Operating activities – net	Operating	$	1,972	$	1,930	Operating activities – net	Operating	$	2,180	$	1,972
Proceeds from long-term debt (see Note 8)		Financing	898		2,196
Proceeds from credit-facility borrowings		Financing	—		1,700
Proceeds from commercial paper - net							Proceeds from commercial paper - net	Financing	1,037		—
Proceeds from long-term debt							Proceeds from long-term debt	Financing	5		898

Uses of cash and cash equivalents:	Uses of cash and cash equivalents:						Uses of cash and cash equivalents:
Payments of long-term debt							Payments of long-term debt	Financing	(2,012)		(11)
Common dividends paid	Common dividends paid	Financing	(996)		(971)		Common dividends paid	Financing	(1,035)		(996)
Capital expenditures	Capital expenditures	Investing	(685)		(613)		Capital expenditures	Investing	(606)		(685)

Purchases of businesses, net of cash acquired (see Note 3)							Purchases of businesses, net of cash acquired (see Note 3)	Investing	(933)		—
Dividends and distributions paid to noncontrolling interests	Dividends and distributions paid to noncontrolling interests	Financing	(95)		(98)		Dividends and distributions paid to noncontrolling interests	Financing	(95)		(95)
Purchases of and contributions to equity-method investments	Purchases of and contributions to equity-method investments	Investing	(44)		(66)		Purchases of and contributions to equity-method investments	Investing	(100)		(44)
Payments of long-term debt		Financing	(11)		(1,526)
Payments on credit-facility borrowings		Financing	—		(1,700)

Other sources / (uses) – net	Other sources / (uses) – net	Financing and Investing	20		(8)		Other sources / (uses) – net	Financing and Investing	12		20
Increase (decrease) in cash and cash equivalents	Increase (decrease) in cash and cash equivalents		$	1,059	$	844	Increase (decrease) in cash and cash equivalents		$	(1,547)	$	1,059

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~~Net unrealized (gain) loss from derivative instruments.

. Our Net cash provided (used) by operating activities for the six months ended June 30, ~~2021,~~2022, increased from the same period in ~~2020~~2021 primarily due to higher operating income (excluding noncash items as previously discussed), favorable changes in ~~2021,~~margin requirements, and higher distributions from unconsolidated affiliates, partially offset by ~~the~~ net unfavorable changes in ~~net~~ operating working ~~capital in 2021.~~capital.

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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 six months of ~~2021.~~2022.

Commodity Price Risk

We are exposed to commodity price risk through our natural gas and NGL marketing activities, including contracts to purchase, sell, transport, and store product. We routinely manage this risk with a variety of exchange-traded and OTC energy contracts such as forward contracts, futures contracts, and basis swaps, as well as physical transactions. Although many of the contracts used to manage commodity exposure are derivative instruments, these economic hedges are not designated or do not qualify for hedge accounting treatment.

We are also exposed to commodity prices through our upstream business and certain gathering and processing contracts. We use derivative instruments to lock in forward sales prices on a portion of our expected future production. These economic hedges are not designated for hedge accounting treatment.

The maturities of our derivative contracts at June 30, 2022 were as follows:


	Total Fair Value		Maturity
Fair Value Measurements Using (1)			2022		2023 - 2024		2025 - 2026+
	(Millions)
Level 1	$	(26)	$	38	$	(66)	$	2
Level 2	(697)		(128)		(326)		(243)
Level 3	(28)		(4)		(24)		—
Fair value of contracts outstanding at end of period (2)	$	(751)	$	(94)	$	(416)	$	(241)

_______________

(1)See Note 9 – Fair Value Measurements and Guarantees of Notes to Consolidated Financial Statements for discussion of valuation techniques by level within the fair value hierarchy. See Note 10 – Derivatives for the amount of change in fair value recognized in our Consolidated Statement of Income.

(2)Excludes cash collateral of $247 million in Level 1.

Value at Risk (VaR)

VaR is the maximum predicted loss in portfolio value over a specified time period that is not expected to be exceeded within a given degree of probability. Our VaR may not be comparable to that of other companies due to differences in the factors used to calculate VaR. Our VaR is determined using parametric models with 95 percent confidence intervals and one-day holding periods, which means that 95 percent of the time, the risk of loss in a day from a portfolio of positions is expected to be less than or equal to the amount of VaR calculated. Our open exposure is managed in accordance with established policies that limit market risk and require daily reporting of predicted financial loss to management. Because we generally manage physical gas assets and economically protect our positions by hedging in the futures markets, our open exposure is generally mitigated. We employ daily risk testing, using both VaR and stress testing, to evaluate the risk of our positions.

We actively monitor open commodity marketing positions and the resulting VaR and maintain a relatively small risk exposure as total buy volume is close to sell volume, with minimal open natural gas price risk. Starting in the second quarter of 2022, following the further integration of our legacy natural gas and NGL marketing with the operations acquired in the Sequent Acquisition, we now present VaR for our integrated trading operations. For the first quarter of 2022, the VaR presented reflects the legacy Sequent operations only.

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We had the following VaRs for the periods shown:


	Three Months Ended March 31, 2022		Three Months Ended June 30, 2022
	Sequent Only		Trading
	(Millions)
Average	$	6.2	$	12.1
High	$	10.4	$	20.6
Low	$	4.1	$	8.2

Our remaining portfolio primarily consists of derivatives that hedge our upstream business and certain gathering and processing contracts. At June 30, 2022, the VaR associated with these derivatives was $22 million.

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 second quarter of ~~2021~~2022 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

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consolidated financial position if we receive an unfavorable outcome in any one or more of such proceedings. Our threshold for disclosing material environmental legal proceedings involving a 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.

Other environmental matters called for by this Item are described under the caption “Environmental Matters” in Note 11 – 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 ~~9 – Stockholders’ Equity and Note~~ 11 – 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, ~~2020,~~2021, as filed with the SEC on February 28, 2022, as supplemented by the disclosures in Part II, Item 1A. Risk Factors in our Quarterly Report on Form 10-Q, as filed with the SEC on May 2, 2022, includes risk factors that could materially affect our business, financial condition, or future results. Those Risk Factors have not materially changed.

Item ~~5. Other Information~~2. Unregistered Sales of Equity Securities and Use of Proceeds

Share Repurchase Program

~~On July 28,~~In September 2021, our Board of Directors ~~(the “Board”) approved amendments~~authorized a share repurchase program with a maximum dollar limit of $1.5 billion. Repurchases may be made from time to ~~the By-laws of The Williams Companies, Inc. (the “By-laws”), effective immediately. In addition to certain technical and conforming amendments, the amended By-laws, among other things:~~

~~Notice and Record Date Provisions~~

•~~Reflect certain changes~~time in the ~~General Corporation Law~~open market, by block purchases, in privately negotiated transactions or in such other manner as determined by our management. Our management will also determine the timing and amount of the State of Delaware (the “DGCL”) to (i) allow the Board to set a record date for determining the stockholders entitled to vote at a stockholder meeting that is different than the record date for determining the stockholders entitled to notice of a stockholder meeting; (ii) provide for a record date for the stockholders entitled to vote at a stockholder meeting if the Board fails to establish one; (iii) provide for the record date for an adjourned stockholder meeting or allow the Board to reset the record date for an adjourned stockholder meeting; (iv) allow the Board to fix a record date for purpose of allowingany repurchases based on market conditions and other factors. The share repurchase program does not obligate us to ~~determine~~acquire any particular amount of common stock, and it may be suspended or discontinued at any time. This share repurchase program does not have an expiration date. There were no repurchases under the stockholders entitled to consent to a corporation action without a meeting; and (v) allow the Board to set a record date to allow us to determine the stockholders entitled to receive payment of any dividend or other distribution or allotment of any rights or the stockholders entitled to exercise any rights in respect of any change, conversion or exchange of stock or for the purpose of any other lawful action (Article V, Section 5);

•Update the notices required to be sent prior to a special or general stockholder meeting to provide that the notices shall include the record date for determining the stockholders entitled to vote at the meeting if that record date is different from the record date for determining stockholders entitled to notice (Article II, Sections 2);

•~~Clarify that our secretary shall send the notice of any special meetings (Article II, Section 3);~~

•~~Provide that for an adjourned annual or special meeting of stockholders, if adjournment is for more than~~program through June 30, ~~calendar days, or if after the adjournment a new record date for stockholders entitled to vote is fixed for the~~2022.

adjourned meeting, a notice of the adjournment shall be given to stockholders entitled to vote at the adjourned meeting as of the record date fixed for the notice of the adjourned meeting (Article II, Section 5);

•Provide that if the record date for determining the stockholders entitled to vote is less than 10 days before the meeting date, the list of stockholders entitled to vote shall reflect the stockholders entitled to vote as of the tenth day before the meeting (Article II, Section 8);

•~~Specify the information the notice of any special Board meeting shall contain and to specify the delivery and timing requirements for the notice of any special Board meeting (Article III, Section 6);~~

•Reflect (i) certain definitional changes to the DGCL related to the transmission of notices; and (ii) provide for the delivery of notices to stockholders by electronic mail and facsimile under certain circumstances (Article VI, Section 1 and Article VII, Section 5).

~~Miscellaneous Updates~~

•Provide, among other things, the Board has the sole right to determine the time, date and place of a special meeting, including whether to allow the meeting by remote communication, and our secretary shall send a notice of the special meeting (Article II, Section 3);

•Clarify that to determine whether a quorum is present at a stockholder meeting, the standard is the majority of the voting power of the outstanding shares of capital stock entitled to vote at the annual or special stockholder meeting, except as otherwise provided by law or by the Certificate of Incorporation (Article II, Section 4);

•Clarify, among other things, that adjournment of a meeting by stockholders requires a majority of the voting power of our outstanding shares of capital stock that are present in person or represented by proxy at the meeting and entitled to vote (even though less than a quorum) (Article II, Section 5);

•Provide that a stockholder entitled to vote at any meeting of stockholders or to express consent or dissent to corporate action without a meeting may authorize up to three people to act for such stockholder as a proxy in accordance with Section 212 of the DGCL (Article II, Section 6);

•~~Delete duplicative provisions already contained in the Certificate of Incorporation pertaining to votes by a class of stockholders and one share equating to one vote (Article II, Section 6);~~

•~~Provide that the chair of the Board may designate someone to preside at a stockholder meeting (Article II, Section 7);~~

•~~Provide that a series of preferred stock may have a different voting standard for the election of a director (Article III, Section 1);~~

•Clarify that a majority of the directors of the Board may create a new directorship without a vacancy left by an existing director subject to the provisions of the Certificate of Incorporation (Article III, Section 2);

•Allow for the record of Board actions or consents to be in any format permitted by the DGCL, and provide that the record of actions as well as consents be filed with the minutes of the proceedings of the Board (Article III, Section 8);

•~~Clarify that a committee established by the Board may approve or recommend to the stockholders the election or removal of directors (Article III, Section 11).~~

The foregoing is only a summary of the changes made to the By-laws and is qualified in its entirety by reference to the full text of the By-laws, which is filed as Exhibit 3.4 to this Quarterly Report on Form 10-Q and is incorporated herein by reference.

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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*3.4	—	By-Laws of The Williams Companies, Inc., as last amended effective July 28, ~~2021.~~2021 (
~~3.5~~	—	~~Certificate of Designations of Series C Participating Preferred Stock of The Williams Companies, Inc. (filed~~filed on ~~March 20, 2020~~August 2, 2021 as Exhibit ~~3.1~~3.4 to The Williams Companies, Inc.’s ~~current~~quarterly report on Form ~~8‑K~~10‑Q (File No. ~~001-04174)~~00104174) and incorporated herein by reference).
31.1*	—	Certification of Chief Executive Officer pursuant to Rules 13a-14(a) and 15d-14(a) promulgated under the Securities Exchange Act of 1934, as amended, and Item 601(b)(31) of Regulation S‑K, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2*	—	Certification of Chief Financial Officer pursuant to Rules 13a-14(a) and 15d-14(a) promulgated under the Securities Exchange Act of 1934, as amended, and Item 601(b)(31) of Regulation S-K, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32**	—	Certification of Chief Executive Officer and Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
101.INS*	—	XBRL Instance Document. The instance document does not appear in the interactive data file because its XBRL tags are embedded within the inline XBRL document.
101.SCH*	—	XBRL Taxonomy Extension Schema.
101.CAL*	—	XBRL Taxonomy Extension Calculation Linkbase.
101.DEF*	—	XBRL Taxonomy Extension Definition Linkbase.
101.LAB*	—	XBRL Taxonomy Extension Label Linkbase.

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Exhibit
No.

Description

101.PRE*

—

XBRL Taxonomy Extension Presentation Linkbase.

104*

—

Cover Page Interactive Data File. The cover page interactive data file does not appear in the interactive data file because its XBRL tags are embedded within the inline XBRL document (contained in Exhibit 101).

* Filed herewith.

** Furnished herewith.

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~~Mary A. Hausman
			~~John D. Porter~~Mary A. Hausman
			Vice President, ~~Controller, and~~ Chief Accounting Officer and Controller (Duly Authorized Officer and Principal Accounting Officer)

August ~~2, 2021~~1, 2022


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

Other comprehensive income (loss) before reclassifications	(26)		0		0		(26)
Amounts reclassified from accumulated other comprehensive income (loss)	6		0		6		12
Other comprehensive income (loss)	(20)		0		6		(14)

Balance at June 30, 2021	$	(23)	$	(1)	$	(86)	$	(110)


					Impairments
					Six Months Ended June 30,
	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