The Williams Companies, Inc. (WMB) 10-Q 2022 Q3 Quarterly report

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

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

For the quarterly period ended September 30, 2022

or

☐ 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: (800) 945-5426

NO CHANGE

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

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

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

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

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes ☑ No ☐

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

Large accelerated filer ☑ Accelerated filer ☐ Non-accelerated filer ☐ Smaller reporting company ☐ Emerging growth company ☐

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

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act.) Yes ☐ No ☑

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

Class	Shares Outstanding at October 27, 2022
Common Stock, $1.00 par value	1,218,339,828

The Williams Companies, Inc.

Index

	Page
Part I. Financial Information
Item 1. Financial Statements
Consolidated Statement of Income – Three and Nine Months Ended September 30, 2022 and 2021	6
Consolidated Statement of Comprehensive Income (Loss) – Three and Nine Months Ended September 30, 2022 and 2021	7
Consolidated Balance Sheet – September 30, 2022 and December 31, 2021	8
Consolidated Statement of Changes in Equity – Three and Nine Months Ended September 30, 2022 and 2021	9
Consolidated Statement of Cash Flows – Nine Months Ended September 30, 2022 and 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	18
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	35
Item 3. Quantitative and Qualitative Disclosures About Market Risk	54
Item 4. Controls and Procedures	55
Part II. Other Information	55
Item 1. Legal Proceedings	55
Item 1A. Risk Factors	56
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds	57
Item 5. Other Information	57
Item 6. Exhibits	59

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.

1

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;

2

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

3

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:

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

Partially Owned Entities: Entities in which we do not own a 100 percent ownership interest and which, as of September 30, 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

4

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

5

PART I – FINANCIAL INFORMATION

Item 1. Financial Statements

The Williams Companies, Inc.

Consolidated Statement of Income

(Unaudited)

	Three Months Ended  September 30,				Nine Months Ended  September 30,
	2022		2021		2022		2021
	(Millions, except per-share amounts)
Revenues:
Service revenues	$	1,685	$	1,506	$	4,828	$	4,418
Service revenues – commodity consideration	60		64		223		164
Product sales	1,260		1,296		3,475		3,229
Net gain (loss) on commodity derivatives	16		(391)		(491)		(441)
Total revenues	3,021		2,475		8,035		7,370
Costs and expenses:
Product costs	990		1,043		2,650		2,672
Net processing commodity expenses	29		28		99		67
Operating and maintenance expenses	486		409		1,345		1,148
Depreciation and amortization expenses	500		487		1,504		1,388
Selling, general, and administrative expenses	163		152		477		389
Other (income) expense – net	33		1		14		12
Total costs and expenses	2,201		2,120		6,089		5,676
Operating income (loss)	820		355		1,946		1,694
Equity earnings (losses)	193		157		492		423
Other investing income (loss) – net	1		2		4		6
Interest incurred	(296)		(295)		(871)		(892)
Interest capitalized	5		3		13		8
Other income (expense) – net	(6)		4		5		4
Income (loss) before income taxes	717		226		1,589		1,243
Less: Provision (benefit) for income taxes	96		53		169		313
Net income (loss)	621		173		1,420		930
Less: Net income (loss) attributable to noncontrolling interests	21		8		40		35
Net income (loss) attributable to The Williams Companies, Inc.	600		165		1,380		895
Less: Preferred stock dividends	1		1		2		2
Net income (loss) available to common stockholders	$	599	$	164	$	1,378	$	893
Basic earnings (loss) per common share:
Net income (loss)	$	.49	$	.14	$	1.13	$	.74
Weighted-average shares (thousands)	1,218,964		1,215,434		1,218,202		1,215,113
Diluted earnings (loss) per common share:
Net income (loss)	$	.49	$	.13	$	1.13	$	.73
Weighted-average shares (thousands)	1,222,472		1,217,979		1,222,153		1,217,558

See accompanying notes.

6

The Williams Companies, Inc.

Consolidated Statement of Comprehensive Income (Loss)

(Unaudited)

	Three Months Ended  September 30,				Nine Months Ended  September 30,
	2022		2021		2022		2021
	(Millions)
Net income (loss)	$	621	$	173	$	1,420	$	930
Other comprehensive income (loss):
Designated cash flow hedging activities:
Net unrealized gain (loss) from derivative instruments, net of taxes of $3 and $1 in 2022 and $5 and $14 in 2021	(8)		(17)		(3)		(43)
Reclassifications into earnings of net derivative instruments (gain) loss, net of taxes of $— and $— in 2022 and ($5) and ($7) in 2021	—		15		—		21
Pension and other postretirement benefits:
Net actuarial gain (loss) arising during the year, net of taxes of ($1) and ($1) in 2022 and $— and $— in 2021	2		—		2		—
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 2022 and ($1) and ($3) in 2021	2		3		7		9
Other comprehensive income (loss)	(4)		1		6		(13)
Comprehensive income (loss)	617		174		1,426		917
Less: Comprehensive income (loss) attributable to noncontrolling interests	21		8		40		35
Comprehensive income (loss) attributable to The Williams Companies, Inc.	$	596	$	166	$	1,386	$	882

See accompanying notes.

7

The Williams Companies, Inc.

Consolidated Balance Sheet

(Unaudited)

	September 30, 2022		December 31, 2021
	(Millions, except per-share amounts)
ASSETS
Current assets:
Cash and cash equivalents	$	859	$	1,680
Trade accounts and other receivables	2,674		1,986
Allowance for doubtful accounts	(15)		(8)
Trade accounts and other receivables – net	2,659		1,978
Inventories	447		379
Derivative assets	201		301
Other current assets and deferred charges	272		211
Total current assets	4,438		4,549
Investments	5,066		5,127
Property, plant, and equipment	46,186		44,184
Accumulated depreciation and amortization	(15,848)		(14,926)
Property, plant, and equipment – net	30,338		29,258
Intangible assets – net of accumulated amortization	7,493		7,402
Regulatory assets, deferred charges, and other	1,337		1,276
Total assets	$	48,672	$	47,612
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable	$	2,613	$	1,746
Accrued liabilities	1,527		1,201
Long-term debt due within one year	877		2,025
Total current liabilities	5,017		4,972
Long-term debt	22,530		21,650
Deferred income tax liabilities	2,637		2,453
Regulatory liabilities, deferred income, and other	4,578		4,436
Contingent liabilities and commitments (Note 11)
Equity:
Stockholders’ equity:
Preferred stock ($1 par value; 30 million shares authorized at September 30, 2022 and December 31, 2021; 35,000 shares issued at September 30, 2022 and December 31, 2021)	35		35
Common stock ($1 par value; 1,470 million shares authorized at September 30, 2022 and December 31, 2021; 1,253 million shares issued at September 30, 2022 and 1,250 million shares issued at December 31, 2021)	1,253		1,250
Capital in excess of par value	24,527		24,449
Retained deficit	(13,419)		(13,237)
Accumulated other comprehensive income (loss)	(27)		(33)
Treasury stock, at cost (35 million shares of common stock)	(1,050)		(1,041)
Total stockholders’ equity	11,319		11,423
Noncontrolling interests in consolidated subsidiaries	2,591		2,678
Total equity	13,910		14,101
Total liabilities and equity	$	48,672	$	47,612

See accompanying notes.

8

The Williams Companies, Inc.

Consolidated Statement of Changes in Equity

(Unaudited)

	The Williams Companies, Inc. Stockholders
	Preferred Stock		Common Stock		Capital in Excess of Par Value		Retained Deficit		AOCI*		Treasury Stock		Total Stockholders’ Equity		Noncontrolling Interests		Total Equity
	(Millions)
Balance – June 30, 2022	$	35	$	1,253	$	24,500	$	(13,498)	$	(23)	$	(1,041)	$	11,226	$	2,610	$	13,836
Net income (loss)	—		—		—		600		—		—		600		21		621
Other comprehensive income (loss)	—		—		—		—		(4)		—		(4)		—		(4)
Cash dividends – common stock ($0.425 per share)	—		—		—		(518)		—		—		(518)		—		(518)
Dividends and distributions to noncontrolling interests	—		—		—		—		—		—		—		(46)		(46)
Stock-based compensation and related common stock issuances, net of tax	—		—		28		—		—		—		28		—		28
Contributions from noncontrolling interests	—		—		—		—		—		—		—		7		7
Purchase of treasury stock	—		—		—		—		—		(9)		(9)		—		(9)
Other	—		—		(1)		(3)		—		—		(4)		(1)		(5)
Net increase (decrease) in equity	—		—		27		79		(4)		(9)		93		(19)		74
Balance – September 30, 2022	$	35	$	1,253	$	24,527	$	(13,419)	$	(27)	$	(1,050)	$	11,319	$	2,591	$	13,910

Balance – June 30, 2021	$	35	$	1,249	$	24,401	$	(13,022)	$	(110)	$	(1,041)	$	11,512	$	2,753	$	14,265
Net income (loss)	—		—		—		165		—		—		165		8		173
Other comprehensive income (loss)	—		—		—		—		1		—		1		—		1
Cash dividends – common stock ($0.41 per share)	—		—		—		(498)		—		—		(498)		—		(498)
Dividends and distributions to noncontrolling interests	—		—		—		—		—		—		—		(40)		(40)
Stock-based compensation and related common stock issuances, net of tax	—		—		23		—		—		—		23		—		23
Purchase of partial interest in consolidated subsidiary	—		—		—		—		—		—		—		(3)		(3)
Contributions from noncontrolling interests	—		—		—		—		—		—		—		3		3
Other	—		—		1		(6)		—		—		(5)		—		(5)
Net increase (decrease) in equity	—		—		24		(339)		1		—		(314)		(32)		(346)
Balance – September 30, 2021	$	35	$	1,249	$	24,425	$	(13,361)	$	(109)	$	(1,041)	$	11,198	$	2,721	$	13,919

*Accumulated Other Comprehensive Income (Loss)

See accompanying notes.

9

The Williams Companies, Inc.

Consolidated Statement of Changes in Equity (Continued)

(Unaudited)

	The Williams Companies, Inc. Stockholders
	Preferred Stock		Common Stock		Capital in Excess of Par Value		Retained Deficit		AOCI*		Treasury Stock		Total Stockholders’ Equity		Noncontrolling Interests		Total Equity
	(Millions)
Balance – December 31, 2021	$	35	$	1,250	$	24,449	$	(13,237)	$	(33)	$	(1,041)	$	11,423	$	2,678	$	14,101
Net income (loss)	—		—		—		1,380		—		—		1,380		40		1,420
Other comprehensive income (loss)	—		—		—		—		6		—		6		—		6
Cash dividends – common stock ($1.275 per share)	—		—		—		(1,553)		—		—		(1,553)		—		(1,553)
Dividends and distributions to noncontrolling interests	—		—		—		—		—		—		—		(141)		(141)
Stock-based compensation and related common stock issuances, net of tax	—		3		79		—		—		—		82		—		82
Contributions from noncontrolling interests	—		—		—		—		—		—		—		15		15
Purchase of treasury stock	—		—		—		—		—		(9)		(9)		—		(9)
Other	—		—		(1)		(9)		—		—		(10)		(1)		(11)
Net increase (decrease) in equity	—		3		78		(182)		6		(9)		(104)		(87)		(191)
Balance – September 30, 2022	$	35	$	1,253	$	24,527	$	(13,419)	$	(27)	$	(1,050)	$	11,319	$	2,591	$	13,910

Balance – December 31, 2020	$	35	$	1,248	$	24,371	$	(12,748)	$	(96)	$	(1,041)	$	11,769	$	2,814	$	14,583
Net income (loss)	—		—		—		895		—		—		895		35		930
Other comprehensive income (loss)	—		—		—		—		(13)		—		(13)		—		(13)
Cash dividends – common stock ($1.23 per share)	—		—		—		(1,494)		—		—		(1,494)		—		(1,494)
Dividends and distributions to noncontrolling interests	—		—		—		—		—		—		—		(135)		(135)
Stock-based compensation and related common stock issuances, net of tax	—		1		53		—		—		—		54		—		54
Purchase of partial interest in consolidated subsidiary	—		—		—		—		—		—		—		(3)		(3)
Contributions from noncontrolling interests	—		—		—		—		—		—		—		9		9
Other	—		—		1		(14)		—		—		(13)		1		(12)
Net increase (decrease) in equity	—		1		54		(613)		(13)		—		(571)		(93)		(664)
Balance – September 30, 2021	$	35	$	1,249	$	24,425	$	(13,361)	$	(109)	$	(1,041)	$	11,198	$	2,721	$	13,919

*Accumulated Other Comprehensive Income (Loss)

See accompanying notes.

10

The Williams Companies, Inc.

Consolidated Statement of Cash Flows

(Unaudited)

	Nine Months Ended  September 30,
	2022		2021
	(Millions)
OPERATING ACTIVITIES:
Net income (loss)	$	1,420	$	930
Adjustments to reconcile to net cash provided (used) by operating activities:
Depreciation and amortization	1,504		1,388
Provision (benefit) for deferred income taxes	182		313
Equity (earnings) losses	(492)		(423)
Distributions from unconsolidated affiliates	688		574
Net unrealized (gain) loss from derivative instruments	329		317
Amortization of stock-based awards	58		60
Cash provided (used) by changes in current assets and liabilities:
Accounts receivable	(672)		(538)
Inventories	(76)		(112)
Other current assets and deferred charges	(62)		(67)
Accounts payable	743		570
Accrued liabilities	167		67
Changes in current and noncurrent derivative assets and liabilities	86		(267)
Other, including changes in noncurrent assets and liabilities	(205)		(6)
Net cash provided (used) by operating activities	3,670		2,806
FINANCING ACTIVITIES:
Proceeds from long-term debt	1,752		898
Payments of long-term debt	(2,019)		(887)
Proceeds from issuance of common stock	53		6
Common dividends paid	(1,553)		(1,494)
Dividends and distributions paid to noncontrolling interests	(141)		(135)
Contributions from noncontrolling interests	15		6
Payments for debt issuance costs	(14)		(7)
Other – net	(49)		(13)
Net cash provided (used) by financing activities	(1,956)		(1,626)
INVESTING ACTIVITIES:
Property, plant, and equipment:
Capital expenditures (1)	(1,447)		(957)
Dispositions – net	(19)		5
Contributions in aid of construction	8		46
Purchases of businesses, net of cash acquired (Note 3)	(933)		(126)
Purchases of and contributions to equity-method investments	(140)		(79)
Other – net	(4)		3
Net cash provided (used) by investing activities	(2,535)		(1,108)
Increase (decrease) in cash and cash equivalents	(821)		72
Cash and cash equivalents at beginning of year	1,680		142
Cash and cash equivalents at end of period	$	859	$	214
_____________
(1) Increases to property, plant, and equipment	$	(1,549)	$	(1,001)
Changes in related accounts payable and accrued liabilities	102		44
Capital expenditures	$	(1,447)	$	(957)

See accompanying notes.

11

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 our consolidated financial statements and notes thereto for the year ended December 31, 2021, in Exhibit 99.1 of our Form 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 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. 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 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 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 and complimentary natural gas storage facilities within 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), 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). Transmission & Gulf of Mexico also includes natural gas storage facilities and pipelines providing services in north Texas.

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

12

Notes (Continued) Table of Contents

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), and Appalachia Midstream Services, LLC, a wholly owned subsidiary that owns equity-method investments with an approximate average 66 percent interest in multiple gas gathering systems in the Marcellus Shale region (Appalachia Midstream Investments).

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 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 equity-method investment in Brazos Permian II, LLC (Brazos Permian II).

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 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 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 September 30, 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.

13

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 expansion activity is expected to be funded with capital contributions from us and the other equity partner.

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

	September 30, 2022		December 31, 2021
	(Millions)
Assets (liabilities):
Cash and cash equivalents	$	53	$	78
Trade accounts and other receivables – net	142		132
Inventories	3		3
Other current assets and deferred charges	6		7
Property, plant, and equipment – net	5,155		5,295
Intangible assets – net of accumulated amortization	2,186		2,267
Regulatory assets, deferred charges, and other	29		20
Accounts payable	(74)		(61)
Accrued liabilities	(28)		(29)
Regulatory liabilities, deferred income, and other	(282)		(287)

Nonconsolidated VIEs

Targa Train 7

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

Note 3 – Acquisitions

Trace Acquisition

On April 29, 2022, we closed on the acquisition of 100 percent of Gemini Arklatex, LLC through which we acquired the Haynesville Shale region gas gathering and 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 country.

During the period from the acquisition date of April 29, 2022 to September 30, 2022, the operations acquired in the Trace Acquisition contributed Revenues of $99 million and Modified EBITDA (as defined in Note 12 – Segment Disclosures) of $48 million.

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

We accounted for the Trace Acquisition 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.

14

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 included 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. After the June 30, 2022, financial statements were issued, we received an updated valuation report from a third-party valuation firm resulting in an increase of $11 million in property, plant, and equipment and a decrease of $11 million in intangible assets.

	(Millions)
Cash and cash equivalents	$	39
Trade accounts and other receivables – net	18
Property, plant, and equipment – net	448
Intangible assets – net of accumulated amortization	472
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

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 of $112 million. Both the Revenues and Modified EBITDA amounts reflect a net unrealized loss on commodity derivatives of $109 million for the period.

15

Notes (Continued) Table of Contents

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.

We accounted for the Sequent Acquisition as a business combination. The following table presents the allocation of the acquisition date fair value of the major classes of the assets acquired, which are included 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 months ended September 30, 2021 and nine months ended September 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.

16

Notes (Continued) Table of Contents

	Three Months Ended September 30, 2021
	As Reported		Pro Forma Trace				Pro Forma Combined
	(Millions)
Revenues	$	2,475	$	31			$	2,506
Net income (loss) attributable to The Williams Companies, Inc.	165		11				176
	Nine Months Ended September 30, 2022
	As Reported		Pro Forma Trace (1)				Pro Forma Combined
	(Millions)
Revenues	$	8,035	$	45			$	8,080
Net income (loss) attributable to The Williams Companies, Inc.	1,380		18				1,398
	Nine Months Ended September 30, 2021
	As Reported		Pro Forma Trace		Pro Forma Sequent (2)		Pro Forma Combined
	(Millions)
Revenues	$	7,370	$	86	$	188	$	7,644
Net income (loss) attributable to The Williams Companies, Inc.	895		31		4		930

(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.

(2)Excludes results from operations acquired in the Sequent Acquisition for the period beginning on the acquisition date of July 1, 2021, 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.

Purchase of North Texas Assets

On August 31, 2022, we purchased a group of assets in north Texas, primarily natural gas storage facilities and pipelines, from NorTex Midstream Holdings, LLC (NorTex Asset Purchase) for approximately $424 million. These assets are included in the Transmission & Gulf of Mexico segment.

17

Notes (Continued) Table of Contents

Note 4 – Revenue Recognition

Revenue by Category

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

	Transco		Northwest Pipeline		Gulf of Mexico Midstream and Storage		Northeast Midstream		West Midstream		Gas & NGL Marketing Services		Other		Eliminations		Total
	(Millions)
Three Months Ended September 30, 2022
Revenues from contracts with customers:
Service revenues:
Regulated interstate natural gas transportation and storage	$	685	$	109	$	—	$	—	$	—	$	—	$	—	$	(18)	$	776
Gathering, processing, transportation, fractionation, and storage:
Monetary consideration	—		—		99		354		407		—		—		(50)		810
Commodity consideration	—		—		11		2		47		—		—		—		60
Other	3		—		9		57		15		1		—		(5)		80
Total service revenues	688		109		119		413		469		1		—		(73)		1,726
Product sales	81		—		51		40		245		3,109		238		(523)		3,241
Total revenues from contracts with customers	769		109		170		453		714		3,110		238		(596)		4,967
Other revenues (1)	3		—		3		6		(6)		2,607		(23)		(1)		2,589
Other adjustments (2)	—		—		—		—		—		(4,779)		—		244		(4,535)
Total revenues	$	772	$	109	$	173	$	459	$	708	$	938	$	215	$	(353)	$	3,021
Three Months Ended September 30, 2021
Revenues from contracts with customers:
Service revenues:
Regulated interstate natural gas transportation and storage	$	642	$	107	$	—	$	—	$	—	$	—	$	—	$	(12)	$	737
Gathering, processing, transportation, fractionation, and storage:
Monetary consideration	—		—		74		340		306		—		—		(37)		683
Commodity consideration	—		—		13		(1)		52		—		—		—		64
Other	3		—		5		52		12		—		—		(6)		66
Total service revenues	645		107		92		391		370		—		—		(55)		1,550
Product sales	20		—		72		19		184		2,140		116		(353)		2,198
Total revenues from contracts with customers	665		107		164		410		554		2,140		116		(408)		3,748
Other revenues (1)	1		1		3		7		(23)		873		(18)		(3)		841
Other adjustments (2)	—		—		—		—		—		(2,131)		—		17		(2,114)
Total revenues	$	666	$	108	$	167	$	417	$	531	$	882	$	98	$	(394)	$	2,475

18

Notes (Continued) Table of Contents

	Transco		Northwest Pipeline		Gulf of Mexico Midstream and Storage		Northeast Midstream		West Midstream		Gas & NGL Marketing Services		Other		Eliminations		Total
	(Millions)
Nine Months Ended September 30, 2022
Revenues from contracts with customers:
Service revenues:
Regulated interstate natural gas transportation and storage	$	2,014	$	329	$	—	$	—	$	—	$	—	$	—	$	(54)	$	2,289
Gathering, processing, transportation, fractionation, and storage:
Monetary consideration	—		—		265		1,027		1,089		—		—		(114)		2,267
Commodity consideration	—		—		54		12		157		—		—		—		223
Other	8		—		21		162		41		2		—		(16)		218
Total service revenues	2,022		329		340		1,201		1,287		2		—		(184)		4,997
Product sales	140		—		215		110		684		8,422		522		(1,442)		8,651
Total revenues from contracts with customers	2,162		329		555		1,311		1,971		8,424		522		(1,626)		13,648
Other revenues (1)	6		2		7		19		(14)		5,838		(72)		(10)		5,776
Other adjustments (2)	—		—		—		—		—		(11,911)		—		522		(11,389)
Total revenues	$	2,168	$	331	$	562	$	1,330	$	1,957	$	2,351	$	450	$	(1,114)	$	8,035
Nine Months Ended September 30, 2021
Revenues from contracts with customers:
Service revenues:
Regulated interstate natural gas transportation and storage	$	1,880	$	328	$	—	$	—	$	—	$	—	$	—	$	(17)	$	2,191
Gathering, processing, transportation, fractionation, and storage:
Monetary consideration	—		—		250		966		860		—		—		(98)		1,978
Commodity consideration	—		—		34		4		126		—		—		—		164
Other	8		—		15		145		40		2		—		(15)		195
Total service revenues	1,888		328		299		1,115		1,026		2		—		(130)		4,528
Product sales	50		—		178		75		441		3,955		216		(796)		4,119
Total revenues from contracts with customers	1,938		328		477		1,190		1,467		3,957		216		(926)		8,647
Other revenues (1)	3		1		8		19		(17)		835		(3)		(9)		837
Other adjustments (2)	—		—		—		—		—		(2,131)		—		17		(2,114)
Total revenues	$	1,941	$	329	$	485	$	1,209	$	1,450	$	2,661	$	213	$	(918)	$	7,370

______________________________

(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 our Consolidated Statement of Income, and realized and unrealized gains and losses associated with our derivative contracts, which are reported in Net gain (loss) on commodity derivatives in our Consolidated Statement of 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.)

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Notes (Continued) Table of Contents

Contract Assets

The following table presents a reconciliation of our contract assets:

	Three Months Ended  September 30,				Nine Months Ended  September 30,
	2022		2021		2022		2021
	(Millions)
Balance at beginning of period	$	48	$	38	$	22	$	12
Revenue recognized in excess of amounts invoiced	54		51		158		134
Minimum volume commitments invoiced	(41)		(39)		(119)		(96)
Balance at end of period	$	61	$	50	$	61	$	50

Contract Liabilities

The following table presents a reconciliation of our contract liabilities:

	Three Months Ended  September 30,				Nine Months Ended  September 30,
	2022		2021		2022		2021
	(Millions)
Balance at beginning of period	$	1,115	$	1,193	$	1,126	$	1,209
Payments received and deferred	34		14		144		99
Significant financing component	2		3		7		8
Contract liability acquired	2		1		2		1
Recognized in revenue	(71)		(48)		(197)		(154)
Balance at end of period	$	1,082	$	1,163	$	1,082	$	1,163

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 September 30, 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 September 30, 2022, that will be recognized in future periods is also excluded from our remaining performance obligations and is instead reflected in contract liabilities.

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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 September 30, 2022.

	Contract Liabilities		Remaining Performance Obligations
	(Millions)
2022 (three months)	$	52	$	916
2023 (one year)	154		3,610
2024 (one year)	126		3,340
2025 (one year)	118		3,015
2026 (one year)	105		2,517
Thereafter	527		17,191
Total	$	1,082	$	30,589

Accounts Receivable

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

	September 30, 2022		December 31, 2021
	(Millions)
Accounts receivable related to revenues from contracts with customers	$	1,824	$	1,451
Receivables from derivatives	788		462
Other accounts receivable	47		65
Trade accounts and other receivables – net	$	2,659	$	1,978

Note 5 – Provision (Benefit) for Income Taxes

The Provision (benefit) for income taxes includes:

	Three Months Ended  September 30,				Nine Months Ended  September 30,
	2022		2021		2022		2021
	(Millions)
Current:
Federal	$	—	$	1	$	(27)	$	(1)
State	4		1		14		1
	4		2		(13)		—
Deferred:
Federal	163		40		247		240
State	(71)		11		(65)		73
	92		51		182		313
Provision (benefit) for income taxes	$	96	$	53	$	169	$	313

The effective income tax rate for the total provision (benefit) for the three months ended September 30, 2022, is less than the federal statutory rate primarily due to the effect of state income taxes, including a $92 million state income tax benefit related to a decrease in our estimate of the deferred state income tax rate (net of federal effect) driven primarily by the enacted decline in the Pennsylvania state income tax rate over the next several years, partially offset by a $23 million unfavorable revision to a state net operating loss carryforward (net of federal benefit).

The effective income tax rate for the total provision (benefit) for the nine months ended September 30, 2022, is less than the federal statutory rate primarily due to the release of a valuation allowance on foreign tax credits, the

21

Notes (Continued) Table of Contents

effect of state income taxes, including a $92 million state income tax benefit related to a decrease in our estimate of the deferred state income tax rate (net of federal effect), and federal settlements.

The effective income tax rates for the total provision (benefit) for the three and nine months ended September 30, 2021, 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 character of future taxable income. During the second quarter of 2022, we 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 second quarter of 2022, we finalized settlements for 2011 through 2014 on certain contested matters with the Internal Revenue Service (IRS). These settlements resulted in decreasing our unrecognized tax 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  September 30,				Nine Months Ended  September 30,
	2022		2021		2022		2021
	(Dollars in millions, except per-share amounts; shares in thousands)
Net income (loss) available to common stockholders	$	599	$	164	$	1,378	$	893
Basic weighted-average shares	1,218,964		1,215,434		1,218,202		1,215,113
Effect of dilutive securities:
Nonvested restricted stock units	3,269		2,539		3,682		2,437
Stock options	239		6		269		8
Diluted weighted-average shares	1,222,472		1,217,979		1,222,153		1,217,558
Earnings (loss) per common share:
Basic	$	.49	$	.14	$	1.13	$	.74
Diluted	$	.49	$	.13	$	1.13	$	.73

Note 7 – Employee Benefit Plans

Net periodic benefit cost (credit) is as follows:

	Pension Benefits
	Three Months Ended  September 30,				Nine Months Ended  September 30,
	2022		2021		2022		2021
	(Millions)
Components of net periodic benefit cost (credit):
Service cost	$	7	$	8	$	21	$	23
Interest cost	8		7		23		21
Expected return on plan assets	(11)		(11)		(33)		(33)
Amortization of net actuarial loss	3		4		9		11
Net actuarial loss from settlements	—		—		—		1
Net periodic benefit cost (credit)	$	7	$	8	$	20	$	23

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	Other Postretirement Benefits
	Three Months Ended  September 30,				Nine Months Ended  September 30,
	2022		2021		2022		2021
	(Millions)
Components of net periodic benefit cost (credit):
Service cost	$	1	$	1	$	1	$	1
Interest cost	1		1		4		4
Expected return on plan assets	(3)		(2)		(8)		(7)
Reclassification to regulatory liability	—		—		1		1
Net periodic benefit cost (credit)	$	(1)	$	—	$	(2)	$	(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 our Consolidated Statement of Income.

Note 8 – Debt and Banking Arrangements

Long-Term Debt

Issuances and retirements

On January 18, 2022, we early retired $1.25 billion of 3.6 percent senior unsecured notes due March 15, 2022.

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

On August 8, 2022, we issued $1.0 billion of 4.65 percent senior unsecured notes due August 15, 2032, and $750 million of 5.30 percent senior unsecured notes due August 15, 2052.

On October 17, 2022, we early retired $850 million of 3.7 percent senior unsecured notes due January 15, 2023.

Commercial Paper Program

At September 30, 2022, no commercial paper was outstanding under our $3.5 billion commercial paper program.

Credit Facility

	September 30, 2022
	Stated Capacity		Outstanding
	(Millions)
Long-term credit facility (1)	$	3,750	$	—
Letters of credit under certain bilateral bank agreements			40

(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.

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Note 9 – 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, and accounts payable approximate fair value because of the short-term nature of these instruments. Therefore, these assets and liabilities are not presented in the following table.

					Fair Value Measurements Using
	Carrying Amount		Fair Value		Quoted Prices In Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
	(Millions)
Assets (liabilities) at September 30, 2022:
Measured on a recurring basis:
ARO Trust investments	$	216	$	216	$	216	$	—	$	—
Commodity derivative assets (1)	95		95		3		54		38
Commodity derivative liabilities (1)	(815)		(815)		(54)		(717)		(44)
Other financial assets (liabilities) – net	(11)		(11)		—		(11)		—
Additional disclosures:
Long-term debt, including current portion	(23,407)		(21,911)		—		(21,911)		—
Guarantees	(38)		(25)		—		(9)		(16)
Assets (liabilities) at December 31, 2021:
Measured on a recurring basis:
ARO Trust investments	$	260	$	260	$	260	$	—	$	—
Commodity derivative assets (2)	84		84		2		81		1
Commodity derivative liabilities (2)	(488)		(488)		(69)		(403)		(16)
Other financial assets (liabilities) – net	(7)		(7)		—		(7)		—
Additional disclosures:
Long-term debt, including current portion	(23,675)		(27,768)		—		(27,768)		—
Guarantees	(39)		(26)		—		(10)		(16)

(1)Net commodity derivative assets and liabilities exclude $210 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 our

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

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, 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.

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 our Consolidated Balance Sheet. The maximum potential undiscounted exposure is approximately $24 million at September 30, 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 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 no carrying value. We have never been called upon to perform under these indemnifications and have no current expectation of a future claim.

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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 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 September 30, 2022, the notional volume of the net long (short) positions for our commodity-related derivative contracts were as follows:

	Commodity	Unit of Measure	Net Long (Short) Position
Index Risk	Natural Gas	MMBtu	485,699,255
Central Hub Risk - Henry Hub	Natural Gas	MMBtu	(58,780,281)
Basis Risk	Natural Gas	MMBtu	(60,614,348)
Central Hub Risk - Mont Belvieu	Natural Gas Liquids	Barrels	(52,710,000)
Basis Risk	Natural Gas Liquids	Barrels	(2,520,000)
Central Hub Risk - WTI	Crude Oil	Barrels	(216,000)

Derivative Financial Statement Presentation

The fair value of commodity-related derivatives, which are not designated as hedging instruments for accounting purposes, was reflected as follows:

	September 30, 2022				December 31, 2021
Derivative Category	Assets		(Liabilities)		Assets		(Liabilities)
	(Millions)
Current	$	1,144	$	(1,475)	$	619	$	(760)
Noncurrent	328		(717)		166		(429)
Total derivatives	$	1,472	$	(2,192)	$	785	$	(1,189)
Gross amounts recognized	$	1,472	$	(2,192)	$	785	$	(1,189)
Counterparty and collateral netting offset	(1,246)		1,456		(476)		772
Amounts recognized in our Consolidated Balance Sheet	$	226	$	(736)	$	309	$	(417)

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

	Gain (Loss)
	Three Months Ended  September 30,				Nine Months Ended  September 30,
	2022		2021		2022		2021
	(Millions)
Realized commodity-related derivatives designated as hedging instruments	$	—	$	(20)	$	—	$	(28)
Realized commodity-related derivatives not designated as hedging instruments	(13)		(62)		(145)		(96)
Unrealized commodity-related derivatives not designated as hedging instruments	29		(309)		(346)		(317)
Net gain (loss) on commodity derivatives	$	16	$	(391)	$	(491)	$	(441)
Realized commodity-related derivatives not designated as hedging instruments in Net processing commodity expenses	$	6	$	1	$	12	$	1
Unrealized commodity-related derivatives not designated as hedging instruments in Net processing commodity expenses	$	6	$	—	$	17	$	—

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 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 September 30, 2022, the contractually required collateral in the event of a credit rating downgrade to non-investment grade status was $18 million.

We maintain accounts with brokers or the clearing houses of certain exchanges to facilitate financial derivative transactions. Based on the value of the positions in these accounts and the associated margin requirements, we may be required to deposit cash into these accounts. At September 30, 2022, net cash collateral held on deposit in broker margin accounts was $210 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 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.

We 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 and on January 18, 2022, it was dismissed.

On March 30, 2017, the Nevada federal district 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 plaintiff’s

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

We reached an agreement to resolve the two remaining actions, which the court must approve. We have fully accrued for the preliminary settlement agreement.

Alaska Refinery Contamination Litigation

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

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

In January 2020, the Alaska Superior Court issued its Memorandum of Decision finding in favor of the State of Alaska and FHRA, with the total incurred and potential future damages estimated to be $86 million. The court found that FHRA is not entitled to contractual indemnification from us because FHRA contributed to the sulfolane contamination. On March 23, 2020, the court entered final judgment in the case. Filing deadlines were stayed until May 1, 2020. However, on April 21, 2020, we filed a Notice of Appeal. We also filed post-judgment motions including a Motion for New Trial and a Motion to Alter or Amend the Judgment. These post-trial motions 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.

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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. On August 23, 2021, the court 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 counterclaims. On June 27, 2016, we filed an appeal of the court’s decision with the Supreme Court of Delaware, seeking reversal and remand to pursue damages. On March 23, 2017, the Supreme Court of Delaware affirmed the Court of Chancery’s ruling. On March 30, 2017, we filed a motion for reargument with the Supreme Court of Delaware, which was denied on April 5, 2017.

On September 16, 2016, we filed an amended complaint with the Court of Chancery seeking damages for breaches of the ETE Merger Agreement by defendants. On September 23, 2016, Energy Transfer filed a second amended and supplemental affirmative defenses and verified counterclaim with the Court of Chancery seeking, among other things, payment of the $1.48 billion termination fee due to our alleged breaches of the ETE Merger Agreement. On December 1, 2017, the court granted our motion to dismiss certain of Energy Transfer’s counterclaims, including its claim seeking payment of the $1.48 billion termination fee. On December 8, 2017, Energy Transfer filed a motion for reargument, which the Court of Chancery denied on April 16, 2018. Trial was held May 10 through May 17, 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. On September 21, 2022, the court entered a final order and judgment awarding us the termination fee, attorney’s fees,

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expenses, and interest in the amount of $602 million plus additional interest starting September 17, 2022. Energy Transfer has 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 September 30, 2022, we have accrued liabilities totaling $32 million for these matters, as discussed below. Estimates of the most likely costs of cleanup are generally based on completed assessment studies, preliminary results of studies, or our experience with other similar cleanup operations. At September 30, 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 propose and 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, reviews and updates to the National Ambient Air Quality Standards, and rules for new and existing source performance standards for volatile organic compound and methane. We continuously monitor these regulatory changes and how they may impact our operations. Implementation of new or modified regulations may result in impacts to our operations and increase the cost of additions to Property, plant, and equipment – net in our Consolidated Balance Sheet for both new and existing facilities in affected areas; however, due to regulatory uncertainty on final rule content and applicability timeframes, we are unable to reasonably estimate the cost of these regulatory impacts at this 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 September 30, 2022, we have accrued liabilities of $4 million for these costs. We expect that these costs will be recoverable through rates.

We also accrue environmental remediation costs for natural gas underground storage facilities, primarily related to soil and groundwater contamination. At September 30, 2022, we have accrued liabilities totaling $10 million for these costs.

Former operations

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

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

•Former petroleum products and natural gas pipelines;

•Former petroleum refining facilities;

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•Former exploration and production and mining operations;

•Former electricity and natural gas marketing and trading operations.

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

Performance Measurement

We evaluate segment operating performance based upon Modified EBITDA. This measure represents the basis of our internal financial reporting and is the primary performance measure used by our chief operating decision maker in measuring performance and allocating resources among our reportable segments. Intersegment 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);

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◦Other investing income (loss) – net;

◦Depreciation and amortization expenses;

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

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

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

	Three Months Ended  September 30,				Nine Months Ended  September 30,
	2022		2021		2022		2021
	(Millions)
Modified EBITDA by segment:
Transmission & Gulf of Mexico	$	638	$	630	$	1,987	$	1,936
Northeast G&P	464		442		1,332		1,253
West	337		257		885		702
Gas & NGL Marketing Services (1)	20		(262)		(249)		(161)
Other	140		38		284		91
	1,599		1,105		4,239		3,821
Accretion expense associated with asset retirement obligations for nonregulated operations	(12)		(12)		(36)		(33)
Depreciation and amortization expenses	(500)		(487)		(1,504)		(1,388)
Equity earnings (losses)	193		157		492		423
Other investing income (loss) – net	1		2		4		6
Proportional Modified EBITDA of equity-method investments	(273)		(247)		(748)		(702)
Interest expense	(291)		(292)		(858)		(884)
(Provision) benefit for income taxes	(96)		(53)		(169)		(313)
Net income (loss)	$	621	$	173	$	1,420	$	930

_____________

(1)    Modified EBITDA for the three and nine months ended September 30, 2022, includes charges of $64 million and $76 million associated with lower of cost or net realizable value adjustments to our inventory. These charges are reflected in Product Sales and Product costs in our Consolidated Statement of Income.

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Notes (Continued) Table of Contents

The following table reflects the reconciliation of Segment revenues to Total revenues as reported in our Consolidated Statement of Income.

	Transmission & Gulf of Mexico		Northeast G&P		West		Gas & NGL Marketing Services (1)		Other		Eliminations		Total
	(Millions)
Three Months Ended September 30, 2022
Segment revenues:
Service revenues
External	$	880	$	408	$	393	$	1	$	3	$	—	$	1,685
Internal	30		9		32		—		3		(74)		—
Total service revenues	910		417		425		1		6		(74)		1,685
Total service revenues – commodity consideration	11		2		47		—		—		—		60
Product sales
External	78		11		61		1,079		31		—		1,260
Internal	43		29		184		(195)		207		(268)		—
Total product sales	121		40		245		884		238		(268)		1,260
Net gain (loss) on commodity derivatives
Realized	—		—		(9)		54		(58)		—		(13)
Unrealized	1		—		—		(1)		29		—		29
Total net gain (loss) on commodity derivatives (2)	1		—		(9)		53		(29)		—		16
Total revenues	$	1,043	$	459	$	708	$	938	$	215	$	(342)	$	3,021
Three Months Ended September 30, 2021
Segment revenues:
Service revenues
External	$	812	$	390	$	300	$	—	$	4	$	—	$	1,506
Internal	24		9		20		—		4		(57)		—
Total service revenues	836		399		320		—		8		(57)		1,506
Total service revenues – commodity consideration	13		(1)		52		—		—		—		64
Product sales
External	54		(1)		13		1,183		47		—		1,296
Internal	34		20		164		51		64		(333)		—
Total product sales	88		19		177		1,234		111		(333)		1,296
Net gain (loss) on commodity derivatives
Realized	—		—		(18)		(58)		(6)		—		(82)
Unrealized	—		—		—		(294)		(15)		—		(309)
Total net gain (loss) on commodity derivatives (2)	—		—		(18)		(352)		(21)		—		(391)
Total revenues	$	937	$	417	$	531	$	882	$	98	$	(390)	$	2,475

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Notes (Continued) Table of Contents

	Transmission & Gulf of Mexico		Northeast G&P		West		Gas & NGL Marketing Services (1)		Other		Eliminations		Total
	(Millions)
Nine Months Ended September 30, 2022
Segment revenues:
Service revenues
External	$	2,563	$	1,178	$	1,073	$	2	$	12	$	—	$	4,828
Internal	88		30		66		—		10		(194)		—
Total service revenues	2,651		1,208		1,139		2		22		(194)		4,828
Total service revenues – commodity consideration	54		12		157		—		—		—		223
Product sales
External	187		24		111		3,073		80		—		3,475
Internal	147		86		573		(349)		442		(899)		—
Total product sales	334		110		684		2,724		522		(899)		3,475
Net gain (loss) on commodity derivatives
Realized	—		—		(23)		(18)		(104)		—		(145)
Unrealized	1		—		—		(357)		10		—		(346)
Total net gain (loss) on commodity derivatives (2)	1		—		(23)		(375)		(94)		—		(491)
Total revenues	$	3,040	$	1,330	$	1,957	$	2,351	$	450	$	(1,093)	$	8,035
Nine Months Ended September 30, 2021
Segment revenues:
Service revenues
External	$	2,445	$	1,101	$	857	$	2	$	13	$	—	$	4,418
Internal	48		29		51		—		10		(138)		—
Total service revenues	2,493		1,130		908		2		23		(138)		4,418
Total service revenues – commodity consideration	34		4		126		—		—		—		164
Product sales
External	141		11		43		2,912		122		—		3,229
Internal	81		64		398		137		94		(774)		—
Total product sales	222		75		441		3,049		216		(774)		3,229
Net gain (loss) on commodity derivatives
Realized	—		—		(25)		(93)		(6)		—		(124)
Unrealized	—		—		—		(297)		(20)		—		(317)
Total net gain (loss) on commodity derivatives (2)	—		—		(25)		(390)		(26)		—		(441)
Total revenues	$	2,749	$	1,209	$	1,450	$	2,661	$	213	$	(912)	$	7,370

_____________

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

(2)    We record transactions that qualify as derivatives at fair value with changes in fair value recognized in earnings in the 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 revenue.

34

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 that safely delivers natural gas 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. The rates are established primarily through the FERC’s ratemaking 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, compression, and storage, NGL fractionation, transportation and storage, crude oil production handling and transportation, as well as marketing services for NGL, crude oil and natural gas.

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 Gas & NGL Marketing Services. All remaining business activities, including our upstream operations 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 and complimentary natural gas storage facilities within 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), a 50 percent equity-method investment in Gulfstream, and a 60 percent equity-method investment in Discovery. Transmission & Gulf of Mexico also includes natural gas storage facilities and pipelines providing services in north Texas.

•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, 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 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 equity-method investment in Brazos Permian II, LLC.

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

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

Dividends

In September 2022, we paid a regular quarterly dividend of $0.425 per share.

Overview of Nine Months Ended September 30, 2022

Net income (loss) attributable to The Williams Companies, Inc., for the nine months ended September 30, 2022, increased $485 million compared to the nine months ended September 30, 2021, reflecting the benefit of higher service revenues from commodity-based gathering and processing rates and higher gathering volumes, including from the Trace Acquisition in the West, as well as Transco’s Leidy South project placed in service in December 2021, higher results from our upstream operations associated with higher prices and increased scale of operations, higher commodity margins, higher equity earnings, and favorable interest expense due to debt retirements. These favorable impacts were partially offset by a $12 million unfavorable change in net unrealized loss on commodity derivatives, increased intangible asset amortization, the absence of a $77 million favorable impact in 2021 from Winter Storm Uri, higher operating and maintenance expenses, and higher selling, general, and administrative expenses, primarily resulting from the Sequent Acquisition. The tax provision benefited from the release of valuation allowances on deferred income tax assets and federal income tax settlements, as well as from a decrease in our estimated deferred state income tax rate.

Our results include a $12 million unfavorable change in 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 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 our consolidated financial statements and notes thereto of this Form 10‑Q and in Exhibit 99.1 of our Form 8-K dated May 2, 2022.

Recent Developments

Trace Acquisition

On April 29, 2022, we closed on the acquisition of 100 percent of Gemini Arklatex, LLC through which we acquired the Haynesville Shale region gas gathering and related assets of Trace Midstream for $972 million, 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 country.

Purchase of North Texas Assets

On August 31, 2022, we purchased a group of assets in north Texas, primarily natural gas storage facilities and pipelines, from NorTex Midstream Holdings, LLC for approximately $424 million. These assets are included in the Transmission & Gulf of Mexico segment.

Northwest Pipeline FERC Rate Case Settlement Filing

On August 26, 2022, Northwest Pipeline filed a petition with the FERC for approval of a stipulation and settlement agreement, which establishes a new general system firm rate, to be effective January 1, 2023, resolves other rate issues, establishes a Modernization and Emission Reduction Program, and satisfies its rate case filing

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

obligation. Provisions were included in the settlement that a new rate case can be filed to be effective after January 1, 2026, and that a general rate case filing must be made for rates to become effective no later than April 1, 2028.

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, reliable, clean energy services to our customers and an attractive return to our shareholders. Our business plan for 2022 includes a continued focus on earnings and cash flow growth.

In 2022, our operating results are expected to benefit from higher commodity prices and volume growth in our Haynesville and Ohio Valley Midstream areas. We also anticipate increases resulting from Transco expansion projects, development of our upstream oil and gas properties, and our recently completed Trace Acquisition. These increases are partially offset by the absence of 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 gathering rates resulting from annual cost of 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 United States. Our growth capital and investment expenditures in 2022 are expected to be in a range from $1.25 billion to $1.35 billion, which excludes approximately $1.5 billion in total acquisitions and follow-on expenditures for the Trace Acquisition and NorTex Asset Purchase. Growth capital spending in 2022, excluding the Trace Acquisition and NorTex Asset Purchase, primarily includes Transco expansions, all of which are fully contracted with firm transportation agreements, projects supporting the Northeast G&P business, and an expansion in the Western Gulf area. We also expect to invest capital in the development of our upstream oil and 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.

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 downturns in financial markets and commodity prices, as well as impact demand for natural gas and related products;

•Opposition to, and 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, including delays caused by supply chain disruptions;

•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 industry downturns, including increased inflation and interest rates;

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

•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, 2021, as filed with the SEC on February 28, 2022, as supplemented by disclosures in 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

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

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. 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. The project is expected to increase capacity by 423 Mdth/d.

Texas to Louisiana Energy Pathway

In August 2022, we filed an application with the FERC for the project, which involves an expansion of Transco’s existing natural gas transmission system to provide incremental firm transportation capacity from receipt points in south Texas to delivery points in Texas and Louisiana. We plan to place the project into service as early as the fourth quarter of 2025, assuming timely receipt of all necessary regulatory approvals. The project is expected to provide 364 Mdth/d of new firm transportation service through a combination of increasing capacity, converting interruptible capacity to firm, and utilizing existing capacity.

Southeast Energy Connector

In August 2022, we filed an application with the FERC for the project, which is an expansion of Transco’s existing natural gas transmission system to provide incremental firm transportation capacity from receipt points in Mississippi and Alabama to a delivery point in Alabama. We plan to place the project into service in the fourth quarter of 2025, assuming timely receipt of all necessary regulatory approvals. The project is expected to increase capacity by 150 Mdth/d.

Commonwealth Energy Connector

In August 2022, we filed an application with the FERC for the project, which involves an expansion of Transco’s existing natural gas transmission system to provide incremental firm transportation capacity in Virginia. We plan to place the project into service as early as the fourth quarter of 2025, assuming timely receipt of all necessary regulatory approvals. The project is expected to increase capacity by 105 Mdth/d.

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

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.

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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 nine months ended September 30, 2022, compared to the three and nine months ended September 30, 2021. The results of operations by segment are discussed in further detail following this consolidated overview discussion.

	Three Months Ended  September 30,							Nine Months Ended  September 30,
	2022		2021		$ Change*	% Change*		2022		2021		$ Change*	% Change*
	(Millions)							(Millions)
Revenues:
Service revenues	$	1,685	$	1,506	+179	+12	%	$	4,828	$	4,418	+410	+9	%
Service revenues – commodity consideration	60		64		-4	-6	%	223		164		+59	+36	%
Product sales	1,260		1,296		-36	-3	%	3,475		3,229		+246	+8	%
Net gain (loss) on commodity derivatives	16		(391)		+407	NM		(491)		(441)		-50	-11	%
Total revenues	3,021		2,475					8,035		7,370
Costs and expenses:
Product costs	990		1,043		+53	+5	%	2,650		2,672		+22	+1	%
Net processing commodity expenses	29		28		-1	-4	%	99		67		-32	-48	%
Operating and maintenance expenses	486		409		-77	-19	%	1,345		1,148		-197	-17	%
Depreciation and amortization expenses	500		487		-13	-3	%	1,504		1,388		-116	-8	%
Selling, general, and administrative expenses	163		152		-11	-7	%	477		389		-88	-23	%
Other (income) expense – net	33		1		-32	NM		14		12		-2	-17	%
Total costs and expenses	2,201		2,120					6,089		5,676
Operating income (loss)	820		355					1,946		1,694
Equity earnings (losses)	193		157		+36	+23	%	492		423		+69	+16	%
Other investing income (loss) – net	1		2		-1	-50	%	4		6		-2	-33	%
Interest expense	(291)		(292)		+1	—	%	(858)		(884)		+26	+3	%
Other income (expense) – net	(6)		4		-10	NM		5		4		+1	+25	%
Income (loss) before income taxes	717		226					1,589		1,243
Less: Provision (benefit) for income taxes	96		53		-43	-81	%	169		313		+144	+46	%
Net income (loss)	621		173					1,420		930
Less: Net income (loss) attributable to noncontrolling interests	21		8		-13	-163	%	40		35		-5	-14	%
Net income (loss) attributable to The Williams Companies, Inc.	$	600	$	165				$	1,380	$	895

*    + = 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 September 30, 2022 vs. three months ended September 30, 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 G&P operations, higher gathering volumes including from the Trace Acquisition, higher transportation fee revenues associated with the Leidy South expansion project placed fully in service at Transco in December 2021, and higher reimbursable electric power and storage costs, which are substantially offset in Operating and maintenance expenses.

Product sales decreased primarily due to 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). 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 presented net of the related costs of those activities including a 2022 lower of cost or net realizable value adjustment to our gas marketing storage inventory. Additional unfavorable impacts include lower marketing and equity NGL sales volumes. These decreases were substantially offset by higher marketing sales prices, higher sales prices and volumes associated with our upstream operations presented in our Other segment, higher sales prices related to our equity NGL sales, and higher other product sales.

Net gain (loss) on commodity derivatives includes realized and unrealized gains and losses from derivative instruments reflected within Total revenues. The favorable change primarily reflects a net gain related to derivative contracts in our Gas & NGL Marketing Services segment.

Product costs decreased primarily due to the impact of netting the 2022 legacy natural gas marketing revenues with the associated costs. This decrease was partially offset by higher prices, volumes, and lower of cost or net realizable value inventory adjustments in 2022 associated with our NGL marketing activities, higher NGL prices associated with volumes acquired as commodity consideration related to our equity NGL production activities, and higher other product costs.

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

Operating and maintenance expenses increased primarily due to higher operating costs including higher reimbursable electric power and storage costs, which are substantially offset in Service revenues, higher expenses associated with our upstream operations, and increased costs associated with Transco's Leidy South expansion project placed in service in December 2021.

Depreciation and amortization expenses increased primarily due to amortization of intangibles acquired in the Sequent and Trace Acquisitions, partially offset by the absence of 2021 depreciation on certain decommissioned facilities in our West segment.

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

Other (income) expense – net within Operating income (loss) changed unfavorably primarily due to losses related to Eminence storage cavern abandonments and regulatory charges associated with a decrease in Transco’s estimated deferred state income tax rate.

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

Provision (benefit) for income taxes changed unfavorably primarily due to higher pre-tax income, partially offset by a benefit related to a decrease in our estimate of the state deferred income tax rate. 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.

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

Nine months ended September 30, 2022 vs. nine months ended September 30, 2021

Service revenues increased primarily due to higher gathering and processing rates driven by favorable commodity prices and annual contractual rate escalations for certain of our West and Northeast G&P operations, higher gathering volumes including from the Trace Acquisition, higher transportation fee revenues associated with the Leidy South expansion project placed fully in service at Transco in December 2021, and higher reimbursable electric power and storage costs, which are substantially offset in Operating and maintenance expenses.

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 marketing sales prices and volumes, including the increase associated with the Sequent Acquisition in third-quarter 2021, higher sales prices and volumes associated with our upstream operations presented in our Other segment, higher sales prices related to our equity NGL sales activities, and higher other product sales. These increases were substantially offset by the impact of netting the 2022 legacy natural gas marketing revenues with the associated costs, including a 2022 lower of cost or net realizable value adjustment to our gas marketing storage inventory (see Note 1 – General, Description of Business, and Basis of Presentation of Notes to Consolidated Financial Statements) as well as lower gas marketing sales prices related to the absence of a 2021 favorable impact from Winter Storm Uri severe winter weather.

The unfavorable change in Net gain (loss) on commodity derivatives primarily reflects a higher net realized loss, offset by a favorable change in net unrealized gains and losses related to derivative contracts in our Other segment. The change also reflects a lower net realized loss, offset by a higher net unrealized loss related to derivative contracts in our Gas & NGL Marketing Services segment.

Product costs decreased primarily due to the impact of netting the 2022 legacy natural gas marketing revenues with the associated costs. This decrease was partially offset by higher prices, volumes, and lower of cost or net realizable value inventory adjustments in 2022 associated with our NGL marketing activities, higher NGL prices associated with volumes acquired as commodity consideration related to our equity NGL production activities, and higher other product costs.

Net processing commodity expenses increased primarily due to higher net realized prices for natural gas purchases associated with our equity NGL production activities, partially offset by favorable change in net unrealized gains from commodity derivatives related to these purchases. These net gains from commodity derivatives include realized gains in our West segment and unrealized gains in our Gas & NGL Marketing segment.

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

Depreciation and amortization expenses increased primarily due to 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.

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

Other (income) expense – net within Operating income (loss) changed unfavorably primarily due to losses related to Eminence storage cavern abandonments and regulatory charges associated with a decrease in Transco’s estimated deferred state income tax rate, offset by the deferral of ARO depreciation (offset in Depreciation and amortization expenses resulting in no net impact on our results of operations).

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

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 (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 related to the release of a valuation allowance, a benefit associated with a decrease in our estimate of the state deferred income tax rate, and federal settlements, partially offset by higher pre-tax income. See Note 5 – Provision (Benefit) for Income Taxes of Notes to Consolidated Financial Statements for a discussion of the effective tax rate compared to the federal statutory rate for both periods.

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  September 30,				Nine Months Ended  September 30,
	2022		2021		2022		2021
	(Millions)
Service revenues	$	910	$	836	$	2,651	$	2,493
Service revenues – commodity consideration	11		13		54		34
Product sales	121		88		334		222
Net unrealized gain (loss) from derivative instruments	1		—		1		—
Segment revenues	1,043		937		3,040		2,749
Product costs	(120)		(89)		(329)		(223)
Net processing commodity expenses	(2)		(4)		(23)		(10)
Other segment costs and expenses	(333)		(259)		(844)		(718)
Proportional Modified EBITDA of equity-method investments	50		45		143		138
Transmission & Gulf of Mexico Modified EBITDA	$	638	$	630	$	1,987	$	1,936
Commodity margins	$	10	$	8	$	36	$	23

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

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

Service revenues increased primarily due to:

•A $43 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 since the second quarter of 2022 as well as benefited from higher reimbursable electric power costs, which is offset by a similar change in electricity charges reflected in Other segment costs and expenses.

•A $24 million increase in the Eastern Gulf Coast region primarily due to higher volumes from the absence of temporary shut-ins due to producer operational issues and weather-related events in 2021.

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

Other segment costs and expenses increased primarily due to higher operating costs including 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; losses related to Eminence storage cavern abandonments; higher maintenance costs primarily related to general maintenance at Transco; regulatory charges associated with a decrease in Transco’s estimated deferred state income tax rate; and costs associated with the Leidy South expansion project.

Nine months ended September 30, 2022 vs. nine months ended September 30, 2021

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

Service revenues increased primarily due to:

•A $134 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 since the second quarter of 2022 as well as benefited from higher reimbursable electric power costs, which is offset by a similar change in electricity charges reflected in Other segment costs and expenses and higher short-term firm transportation, overall demand and commodity revenues.

•A $19 million increase in the Eastern Gulf Coast region primarily due to higher volumes from the absence of temporary shut-ins due to producer operational issues and weather-related events in 2021, partially offset by a decrease at Gulfstar One for the Tubular Bells field primarily due to lower volumes from natural decline.

Commodity margins associated with our equity NGLs increased $10 million primarily driven by favorable NGL sales prices, partially offset by higher prices for natural gas purchases associated with our equity NGL production activities.

Other segment costs and expenses increased primarily due to higher operating costs including 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; costs associated with the Leidy South expansion project; higher maintenance costs primarily related to general maintenance at Transco and Gulf Coast region; higher employee-related costs; losses related to Eminence storage cavern abandonments; and regulatory charges associated with a decrease in Transco’s estimated deferred state income tax rate. These increases are partially offset by a favorable change in the deferral of ARO related depreciation at Transco.

44

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

Northeast G&P

	Three Months Ended  September 30,				Nine Months Ended  September 30,
	2022		2021		2022		2021
	(Millions)
Service revenues	$	417	$	399	$	1,208	$	1,130
Service revenues – commodity consideration	2		(1)		12		4
Product sales	40		19		110		75
Segment revenues	459		417		1,330		1,209
Product costs	(39)		(19)		(110)		(77)
Net processing commodity expenses	—		(1)		(2)		(1)
Other segment costs and expenses	(138)		(130)		(392)		(368)
Proportional Modified EBITDA of equity-method investments	182		175		506		490
Northeast G&P Modified EBITDA	$	464	$	442	$	1,332	$	1,253
Commodity margins	$	3	$	(2)	$	10	$	1

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

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

Service revenues increased primarily due to a $16 million increase in revenues at the Northeast JV primarily related to higher gathering and processing volumes as well as higher processing rates. Higher escalated rates at Susquehanna Supply Hub and higher cost of service rates in the Utica Shale region were substantially offset by lower volumes.

Other segment costs and expenses increased primarily due to higher operating expenses, including higher electricity and fuel, which is partially offset by reimbursable revenue.

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 lower gathering rates resulting from annual cost of service contract redetermination.

Nine months ended September 30, 2022 vs. nine months ended September 30, 2021

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

Service revenues increased primarily due to:

•A $36 million increase in revenues at the Northeast JV primarily related to higher gathering and processing volumes as well as higher processing rates;

•A $15 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 $12 million increase in revenues in the Utica Shale region primarily related to higher gathering rates resulting from annual cost of service contract redetermination;

•A $12 million increase in revenues associated with reimbursable expenses, which is offset by similar changes in the charges reflected in Other segment costs and expenses.

45

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

Other segment costs and expenses increased primarily due to higher operating expenses, including higher electricity and fuel, which is partially offset by reimbursable revenue.

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 lower gathering rates resulting from annual cost of service contract redetermination.

West

	Three Months Ended  September 30,				Nine Months Ended  September 30,
	2022		2021		2022		2021
	(Millions)
Service revenues	$	425	$	320	$	1,139	$	908
Service revenues – commodity consideration	47		52		157		126
Product sales	245		177		684		441
Net realized gain (loss) on commodity derivatives – service revenues	(10)		(4)		(15)		(4)
Net realized gain (loss) on commodity derivatives – product sales	1		(14)		(8)		(21)
Net realized gain (loss) on commodity derivatives	(9)		(18)		(23)		(25)
Segment revenues	708		531		1,957		1,450
Product costs	(238)		(170)		(667)		(411)
Net processing commodity expenses	(28)		(24)		(91)		(57)
Other segment costs and expenses	(146)		(107)		(413)		(354)
Proportional Modified EBITDA of equity-method investments	41		27		99		74
West Modified EBITDA	$	337	$	257	$	885	$	702
Commodity margins	$	27	21		$	75	$	78

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

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

Service revenues increased primarily due to:

•A $59 million increase in the Haynesville Shale region primarily associated with 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 $40 million increase in the Barnett Shale region primarily due to higher gathering rates driven by favorable commodity pricing.

Product margins from our equity NGLs increased $5 million, primarily due to higher net realized commodity sales prices, partially 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 $6 million primarily due to the Trace Acquisition. Marketing margins decreased $5 million.

46

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

Other segment costs and expenses increased primarily due to higher operating expenses related to the Trace Acquisition as well as higher compressor electricity and fuel costs, and the absence of a gain on an asset sale in 2021.

Proportional Modified EBITDA of equity-method investments increased primarily due to higher commodity prices and volumes at RMM as well as higher volumes at OPPL.

Nine months ended September 30, 2022 vs. nine months ended September 30, 2021

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

Service revenues increased primarily due to:

•A $127 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;

•An $88 million increase in the Barnett Shale region primarily due to higher gathering rates driven by favorable commodity pricing;

•A $16 million increase in the Piceance region primarily driven by higher processing rates driven by favorable commodity pricing;

•A $1 million increase in the Eagle Ford Shale region primarily due to higher MVC revenues, escalated gathering rates, and higher deferred revenue amortization, substantially offset by a production decline; partially offset by

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

Marketing margins decreased $21 million, primarily due to the absence of the favorable impact of Winter Storm Uri in the first quarter of 2021. Other product margins increased $13 million primarily due to higher condensate sales and the Trace Acquisition in 2022. Product margins from our equity NGLs increased $5 million primarily due to higher net realized commodity sales prices, partially offset by higher net realized prices for natural gas purchases associated with our equity NGLs production activities and lower sales volumes primarily due to a customer contract change.

Other segment costs and expenses increased primarily due to higher operating expenses related to higher electricity and compressor fuel costs, the absence of gains on asset sales in 2021, higher corporate allocations, and expenses associated with the Trace Acquisition in 2022.

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

47

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

Gas & NGL Marketing Services

	Three Months Ended September 30,				Nine Months Ended September 30,
	2022		2021		2022		2021
	(Millions)
Service revenues	$	1	$	—	$	2	$	2
Product sales	884		1,234		2,724		3,049
Net realized gain (loss) from derivative instruments	54		(58)		(18)		(93)
Net unrealized gain (loss) from derivative instruments	(1)		(294)		(357)		(297)
Net gain (loss) on commodity derivatives	53		(352)		(375)		(390)
Segment revenues	938		882		2,351		2,661
Net unrealized gain (loss) from derivative instruments within Net processing commodity expenses	6		—		17		—
Product costs	(899)		(1,130)		(2,544)		(2,802)
Other segment costs and expenses	(25)		(14)		(73)		(20)
Gas & NGL Marketing Services Modified EBITDA	$	20	$	(262)	$	(249)	$	(161)
Commodity margins	$	39	$	46	$	162	$	154

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

Gas & NGL Marketing Services Modified EBITDA increased primarily due to the absence of a 2021 net unrealized loss from derivative instruments, partially offset by higher Other segment costs and expenses and lower Commodity margins.

Commodity margins decreased $7 million primarily due to:

•A $55 million decrease in NGL marketing margins primarily due to:

◦A $38 million unfavorable change in realized gains and losses on sales of product;

◦A $22 million charge related to lower of cost or net realizable value inventory adjustments in the third quarter of 2022; partially offset by

◦A $5 million favorable change in net realized gain (loss) from derivative instruments.

•A $48 million increase from our natural gas marketing operations including $83 million of higher natural gas transportation capacity marketing margins due to favorable pricing spreads, partially offset by $35 million lower natural gas storage marketing margins primarily due to a third-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 not designated as hedges for accounting purposes. The change from 2021 is primarily due to a change in forward commodity prices relative to our hedge positions in 2022 compared to 2021.

Other segment costs and expenses increased primarily due to higher employee-related costs.

Nine months ended September 30, 2022 vs. nine months ended September 30, 2021

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

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

Commodity margins increased $8 million primarily due to:

•A $56 million increase in natural gas marketing margins which included the following:

◦A $169 million increase in natural gas transportation capacity marketing margins primarily associated with the Sequent Acquisition in the third quarter of 2021 and favorable pricing spreads in the third quarter of 2022; partially offset by

◦A $58 million decrease associated with our legacy natural gas marketing operations primarily due to the absence of the favorable impact of Winter Storm Uri in the first quarter of 2021;

◦A $40 million decrease in natural gas storage marketing margins due primarily to a lower of cost or net realizable value inventory adjustment in 2022; and

◦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.

•A $48 million decrease in our NGL marketing margins primarily due to:

◦A $25 million unfavorable change in realized gains on sales of product;

◦A $25 million charge related to lower of cost or net realizable value inventory adjustments in 2022; partially offset by

◦A $2 million favorable change in net realized gain (loss) from derivative instruments.

Net unrealized gain (loss) from derivative instruments changed primarily due to the Sequent Acquisition in July 2021, and a change in forward commodity prices relative to our hedge positions in 2022 compared to 2021.

Other segment costs and expenses increased primarily due to higher employee-related costs related to the Sequent Acquisition.

Other

	Three Months Ended September 30,				Nine Months Ended September 30,
	2022		2021		2022		2021
	(Millions)
Service revenues	$	6	$	8	$	22	$	23
Product sales	238		111		522		216
Net realized gain (loss) from derivative instruments	(58)		(6)		(104)		(6)
Net unrealized gain (loss) from derivative instruments	29		(15)		10		(20)
Net gain (loss) on commodity derivatives	(29)		(21)		(94)		(26)
Segment revenues	215		98		450		213
Other segment costs and expenses	(75)		(60)		(166)		(122)
Other Modified EBITDA	$	140	$	38	$	284	$	91
Net realized product sales	$	180	$	105	$	418	$	210

49

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

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

Other Modified EBITDA increased primarily due to $105 million higher results from our upstream operations which included the following:

•A $75 million increase in Net realized product sales primarily due to higher net realized commodity prices and higher volumes associated with production from new wells, partially offset by an unfavorable change in Net realized gain (loss) from derivative instruments due to an increase in commodity prices relative to our hedge positions;

•A $44 million favorable change in Net unrealized gain (loss) from derivative instruments due to a change in forward commodity prices relative to our hedge positions and an increase in the volume of production hedged in 2022 compared to 2021; partially offset by

•A $14 million increase in Other segment costs and expenses primarily due to the increased scale of our upstream operations and higher associated property and production taxes which were also impacted by higher commodity prices.

Other segment costs and expenses also includes an $11 million charge related to an accrual for loss contingency in the third quarter of 2022.

Nine months ended September 30, 2022 vs. nine months ended September 30, 2021

Other Modified EBITDA increased primarily due to $190 million higher results from our upstream operations which included the following:

•A $208 million increase in Net realized product sales primarily due to higher net realized commodity prices in the second and third quarters of 2022, partially offset by lower prices from the absence of the favorable impact of Winter Storm Uri in the first quarter of 2021 and an unfavorable change in Net realized gain (loss) from derivative instruments due to an increase in commodity prices relative to our hedge positions. Net realized product sales also increased due to higher production from new wells and higher volumes associated with acquisitions of additional ownership interests in 2021; and

•A $30 million favorable change in Net unrealized gain (loss) from derivative instruments due to a change in forward commodity prices relative to our hedge positions and an increase in the volume of production hedged in 2022 compared to 2021; partially offset by

•A $48 million increase in Other segment costs and expenses primarily due to the increased scale of our upstream operations and higher associated property and production taxes which were also impacted by higher commodity prices.

Other segment costs and expenses also includes an $11 million charge related to an accrual for loss contingency in the third quarter of 2022, substantially offset by the absence of a $10 million charge related to an accrual for 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

Our growth capital and investment expenditures in 2022 are currently expected to be in a range from $1.25 billion to $1.35 billion, which excludes approximately $1.5 billion in total acquisitions and follow-on expenditures for the Trace Acquisition and NorTex Asset Purchase. Growth capital spending in 2022, excluding the Trace Acquisition and NorTex Asset Purchase, primarily includes Transco expansions, all of which are fully contracted with firm transportation agreements, projects supporting the Northeast G&P business, and an expansion in the Western Gulf area. We also expect to invest capital in the development of our upstream oil and 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 both the Trace Acquisition and the NorTex Asset Purchase with available sources of short-term liquidity and intend to fund substantially all additional planned 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 including the repurchase of our common stock.

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 early retired $750 million of 3.35 percent senior unsecured notes that were scheduled to mature in August 2022 using issuances of commercial paper. During the third quarter of 2022, we issued $1.75 billion of long-term debt that we used to pay down our commercial paper outstanding and, in October 2022, to early retire our $850 million of 3.7 percent senior unsecured notes that were scheduled to mature in January 2023.

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 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

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

As of September 30, 2022, we have $22.5 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, our credit facility, or our commercial paper program, as well as proceeds from asset monetizations.

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

As of September 30, 2022, we had a working capital deficit of $579 million, including cash and cash equivalents and long-term debt due within one year. Our available liquidity is as follows:

Available Liquidity	September 30, 2022
	(Millions)
Cash and cash equivalents	$	859
Capacity available under our $3.75 billion credit facility, less amounts outstanding under our $3.5 billion commercial paper program (1)	3,750
	$	4,609

(1)In managing our available liquidity, we do not expect a maximum outstanding amount in excess of the capacity of our credit facility inclusive of any outstanding amounts under our commercial paper program. We had no commercial paper outstanding as of September 30, 2022. Through September 30, 2022, the highest amount outstanding under our commercial paper program and credit facility during 2022 was $1.219 billion. At September 30, 2022, we were in compliance with the financial covenants associated with our credit facility. Borrowing capacity under our credit facility as of October 27, 2022 was $3.630 billion.

Dividends

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

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.

52

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	Nine Months Ended  September 30,
	Category	2022		2021
		(Millions)
Sources of cash and cash equivalents:
Operating activities – net	Operating	$	3,670	$	2,806
Proceeds from long-term debt	Financing	1,752		898
Uses of cash and cash equivalents:
Payments of long-term debt	Financing	(2,019)		(887)
Common dividends paid	Financing	(1,553)		(1,494)
Capital expenditures	Investing	(1,447)		(957)
Purchases of businesses, net of cash acquired (see Note 3)	Investing	(933)		(126)
Dividends and distributions paid to noncontrolling interests	Financing	(141)		(135)
Purchases of and contributions to equity-method investments	Investing	(140)		(79)
Other sources / (uses) – net	Financing and Investing	(10)		46
Increase (decrease) in cash and cash equivalents		$	(821)	$	72

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, and Net unrealized (gain) loss from derivative instruments.

Our Net cash provided (used) by operating activities for the nine months ended September 30, 2022, increased from the same period in 2021 primarily due higher operating income (excluding noncash items as previously discussed), favorable changes in margin requirements, and higher Distributions from unconsolidated affiliates.

53

Item 3. Quantitative and Qualitative Disclosures About Market Risk

Interest Rate Risk

Our current interest rate risk exposure is related primarily to our debt portfolio and has not materially changed during the first nine months of 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 September 30, 2022 were as follows:

	Total Fair Value		Maturity
Fair Value Measurements Using (1)			2022		2023 - 2024		2025 - 2026+
	(Millions)
Level 1 (2)	$	(51)	$	44	$	(93)	$	(2)
Level 2	(663)		(60)		(359)		(244)
Level 3	(6)		8		(15)		1
Fair value of contracts outstanding at end of period	$	(720)	$	(8)	$	(467)	$	(245)

_______________

(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 of Notes to Consolidated Financial Statements for the amount of change in fair value recognized in our Consolidated Statement of Income.

(2)Net commodity derivative assets and liabilities exclude $210 million of net cash collateral 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 trading activities 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.

54

At September 30, 2022, the VaR associated with this activity was $7 million. We had the following VaRs for the periods shown:

	Three Months Ended  March 31, 2022		Six Months Ended  September 30, 2022
	Sequent Only		Trading
	(Millions)
Average	$	6.2	$	11.1
High	$	10.4	$	20.6
Low	$	4.1	$	5.6

Our remaining portfolio primarily consists of derivatives that hedge our upstream business and certain gathering and processing contracts. At September 30, 2022, the VaR associated with these derivatives was $11 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 third quarter of 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

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predict the final outcome of the proceedings that are still pending, we do not anticipate a material effect on our consolidated financial position if we receive an unfavorable outcome in any one or more of such proceedings. 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 pursuing global resolution of the claims at these facilities, as well as alleged violations at certain other facilities, with the DOJ. Global resolution, once finalized, would include both payment of a civil penalty and an injunctive relief component. We continue to work with the DOJ and the other agencies towards final resolution of these claims.

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 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, 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.

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Item 2. Unregistered Sales of Equity Securities and Use of Proceeds

ISSUER PURCHASES OF EQUITY SECURITIES
Period	(a) Total Number of Shares Purchased	(b) Average Price Paid Per Share		(c) Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs(1)	(d) Maximum Number (or Approximate Dollar Value) of Shares that May Yet Be Purchased Under the Plans or Programs
July 1 - July 31, 2022	—	$	—	—	$	1,500,000,000
August 1 - August 31, 2022	—	$	—	—	$	1,500,000,000
September 1 - September 30, 2022	304,281	$	28.76	304,281	$	1,491,248,057
Total	304,281			304,281

(1)We announced a stock repurchase program on September 8, 2021. Our board of directors has authorized the repurchase of up to $1.5 billion of the company’s common stock. The stock repurchase program has no expiration date. We intend to purchase shares of our stock from time to time in open market transactions, block purchases, privately negotiated or structured transactions, or in such other manner as determined at our discretion, subject to market conditions and other factors.

Item 5. Other Information

On October 25, 2022, our Board of Directors (the “Board”) approved amendments to the By-laws of The Williams Companies, Inc. (the “By-laws”), effective immediately. Changes to the amended and restated By-laws include the following:

•Changes to conform with recent amendments to the General Corporation Law of the State of Delaware to (i) provide greater flexibility for adjourning and reconvening stockholder meetings; and (ii) delete the requirement that the Company make a list of stockholder information available during a meeting of stockholders.

•Updates stemming from the SEC’s recently adopted “universal proxy” rules in Rule 14a-19 under the Exchange Act to provide for the use of universal proxy cards (“Universal Proxy Card Rules”) and updates enhancing procedural mechanics and disclosure requirements in connection with stockholder nominations of directors and submissions of stockholder proposals (other than proposals to be included in the Company’s proxy statement pursuant to Rule 14a-8 under the Exchange Act or nominations pursuant to the company’s proxy access bylaws), including by (i) requiring additional disclosures from nominating stockholders, proposed nominees and other persons associated with nominating stockholders; (ii) conforming existing provisions to the Universal Proxy Card Rules by providing that a proposed nominee consent to being named in any proxy statement and form of proxy card; (iii) requiring a representation as to whether such stockholder intends to solicit proxies in support of director nominees other than the Company’s nominees in accordance with the Universal Proxy Card Rules and the procedures set forth in the By-Laws, and that such stockholder will provide the Company with evidence demonstrating compliance

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with such requirements; and (iv) requiring that stockholders directly or indirectly soliciting proxies from other stockholders use a proxy card color other than white.

•Changes incorporating other ministerial, clarifying, and conforming changes.

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*	—	By-Laws of The Williams Companies, Inc., as last amended effective October 25, 2022.
10.1§*	—	The Williams Companies, Inc. Executive Severance Pay Plan as amended and restated, effective August 1, 2022.
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.

§ Management contract or compensatory plan or arrangement.

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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/ Mary A. Hausman

Mary A. Hausman

Vice President, Chief Accounting Officer and Controller (Duly Authorized Officer and Principal Accounting Officer)

October 31, 2022