The Williams Companies, Inc. 10Q 2024 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, 2024


☐			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 (800-WILLIAMS)

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 November 1, 2024
Common Stock, $1.00 par value						1,219,011,798

The Williams Companies, Inc.

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						Page
Part I. Financial Information
Item 1. Financial Statements
Consolidated Statement of Income – Three and Nine Months Ended September 30, 2024 and 2023						7
Consolidated Statement of Comprehensive Income (Loss) – Three and Nine Months Ended September 30, 2024 and 2023						8
Consolidated Balance Sheet – September 30, 2024 and December 31, 2023						9
Consolidated Statement of Changes in Equity – Three and Nine Months Ended September 30, 2024 and 2023						10
Consolidated Statement of Cash Flows – Nine Months Ended September 30, 2024 and 2023						12
Notes to Consolidated Financial Statements						13
Note 1 - General, Description of Business, and Basis of Presentation						13
Note 2 - Variable Interest Entities						15
Note 3 - Acquisitions and Divestitures						16
Note 4 - Revenue Recognition						22
Note 5 - Provision (Benefit) for Income Taxes						26


Note 6 - Debt and Banking Arrangements						27

Note 7 - Fair Value Measurements and Guarantees						28
Note 8 - Commodity Derivatives						30
Note 9 - Contingencies						32
Note 10 - Segment Disclosures						33

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations						37
Item 3. Quantitative and Qualitative Disclosures About Market Risk						58
Item 4. Controls and Procedures						59
Part II. Other Information						60
Item 1. Legal Proceedings						60
Item 1A. Risk Factors						60

Item 2. Unregistered Sales of Equity Securities, Use of Proceeds, and Issuer Purchases of Equity Securities						61
Item 5. Other Information						61
Item 6. Exhibits						62

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 and Section 21E of the Exchange Act. These forward-looking statements relate to anticipated financial performance, management’s plans and objectives for future operations, business prospects, outcomes of regulatory proceedings, market conditions, and other matters. We make these forward-looking statements in reliance on the safe harbor protections provided under the Private Securities Litigation Reform Act of 1995.

All statements, other than statements of historical facts, included in this report that address activities, events, or developments that we expect, believe, or anticipate will exist or may occur in the future, are forward-looking statements. Forward-looking statements can be identified by various forms of words such as “anticipates,”

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“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.

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 and the ability of other energy companies with whom we conduct or seek to conduct business, to obtain necessary permits and approvals, and our ability to 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 consummate asset sales on acceptable terms;

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

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

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

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

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

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•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;

•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 and conflicts in the Middle East, including between Israel and Hamas and conflicts involving Iran and its proxy forces;

•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 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, 2023, as filed with the SEC on February 21, 2024, as may be supplemented by disclosures in Part II, Item 1A. Risk Factors in subsequent Quarterly Reports on Form 10‑Q.

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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 of natural gas per day

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

MMBtu: One million 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

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

Securities Act, the: Securities Act of 1933, as amended

Other:

Note: References to numerical notes refer to our Notes to Consolidated Financial Statements.

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

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

GAAP: U.S. generally accepted accounting principles

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

MVC: Minimum volume commitments

NGLs: Natural gas liquids; natural gas liquids result from natural gas processing and crude oil refining and are used as petrochemical feedstocks, heating fuels, and gasoline additives, among other applications

NGL margins: NGL revenues less Btu replacement cost, plant fuel, transportation, and fractionation

Appalachia Midstream Investments: Our equity-method investments with an approximate average 66 percent interest in multiple gas gathering systems in the Marcellus Shale region.

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Discovery Acquisition: On August 1, 2024, we closed on the acquisition of the remaining 40 percent interest in Discovery Producer Services, LLC (Discovery) which operates a natural gas gathering and transportation system in the Gulf of Mexico and processing and fractionation facilities in Louisiana, along with certain other assets.

DJ Basin Acquisitions: On November 30, 2023, we closed on the acquisition of 100 percent of Cureton Front Range, LLC (Cureton) (Cureton Acquisition) and also closed on the acquisition of the remaining 50 percent interest in Rocky Mountain Midstream Holdings LLC (RMM) (RMM Acquisition), both of which operate midstream assets in the Denver-Julesberg (DJ) Basin.

Gulf Coast Storage Acquisition: On January 3, 2024, we closed on the acquisition of 100 percent of both Hartree Cardinal Gas, LLC and Hartree Natural Gas Storage, LLC (collectively, “Hartree”), which own natural gas storage facilities and pipelines in Louisiana and Mississippi.

MountainWest Acquisition: The February 14, 2023, acquisition of 100 percent of MountainWest Pipelines Holding Company (MountainWest), which includes FERC-regulated interstate natural gas pipeline systems and natural gas storage capacity.

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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,
		2024		2023		2024		2023
	(Millions, except per-share amounts)
Revenues:
Service revenues		$	1,911	$	1,770	$	5,653	$	5,212
Service revenues – commodity consideration		34		45		82		108
Product sales		703		720		2,158		2,158
Net gain (loss) from commodity derivatives		5		24		(133)		645
Total revenues		2,653		2,559		7,760		8,123
Costs and expenses:
Product costs		517		484		1,467		1,458
Net processing commodity expenses		7		31		29		129
Operating and maintenance expenses		580		522		1,613		1,466
Depreciation and amortization expenses		566		521		1,654		1,542
Selling, general, and administrative expenses		170		146		520		483



Gain on sale of business (Note 3)		—		(130)		—		(130)
Other (income) expense – net		(25)		(9)		(69)		(49)
Total costs and expenses		1,815		1,565		5,214		4,899
Operating income (loss)		838		994		2,546		3,224
Equity earnings (losses)		147		127		431		434


Other investing income (loss) – net		290		24		332		45
Interest expense		(338)		(314)		(1,026)		(914)



Other income (expense) – net		31		30		95		69
Income (loss) before income taxes		968		861		2,378		2,858
Less: Provision (benefit) for income taxes		227		176		549		635
Income (loss) from continuing operations		741		685		1,829		2,223
Income (loss) from discontinued operations (Note 1)		—		(1)		—		(88)
Net income (loss)		741		684		1,829		2,135
Less: Net income (loss) attributable to noncontrolling interests		35		30		90		94
Net income (loss) attributable to The Williams Companies, Inc.		706		654		1,739		2,041
Less: Preferred stock dividends		1		1		2		2
Net income (loss) available to common stockholders		$	705	$	653	$	1,737	$	2,039
Amounts attributable to The Williams Companies, Inc. available to common stockholders:
Income (loss) from continuing operations		$	705	$	654	$	1,737	$	2,127
Income (loss) from discontinued operations (Note 1)		—		(1)		—		(88)
Net income (loss) available to common stockholders		$	705	$	653	$	1,737	$	2,039
Basic earnings (loss) per common share:
Income (loss) from continuing operations		$	.58	$	.54	$	1.43	$	1.74
Income (loss) from discontinued operations		—		—		—		(.07)
Net income (loss) available to common stockholders		$	.58	$	.54	$	1.43	$	1.67
Weighted-average shares (thousands)		1,219,537		1,216,951		1,219,021		1,218,021
Diluted earnings (loss) per common share:
Income (loss) from continuing operations		$	.58	$	.54	$	1.42	$	1.74
Income (loss) from discontinued operations		—		—		—		(.07)
Net income (loss) available to common stockholders		$	.58	$	.54	$	1.42	$	1.67
Weighted-average shares (thousands)		1,222,869		1,220,073		1,222,444		1,222,650

See accompanying notes.

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The Williams Companies, Inc.

Consolidated Statement of Comprehensive Income (Loss)

(Unaudited)



		Three Months Ended September 30,				Nine Months Ended September 30,
		2024		2023		2024		2023
	(Millions)
Net income (loss)		$	741	$	684	$	1,829	$	2,135
Other comprehensive income (loss):
Designated interest rate cash flow hedging activities:
Net unrealized gain (loss) from derivative instruments, net of taxes of $4 and $(1) in 2024 and $(12) and $(23) in 2023		(13)		36		2		72
Reclassifications into earnings of net derivative instruments (gain) loss, net of taxes of $— and $— in 2024 and $— and $— in 2023		—		(1)		(1)		(2)



Pension and other postretirement benefits:



Amortization of actuarial (gain) loss and net actuarial loss from settlements included in net periodic benefit cost (credit), net of taxes of $— and $— in 2024 and $— and ($1) in 2023		—		1		(1)		2



Other comprehensive income (loss)		(13)		36		—		72
Comprehensive income (loss)		728		720		1,829		2,207
Less: Comprehensive income (loss) attributable to noncontrolling interests		35		30		90		94
Comprehensive income (loss) attributable to The Williams Companies, Inc.		$	693	$	690	$	1,739	$	2,113

See accompanying notes.

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The Williams Companies, Inc.

Consolidated Balance Sheet

(Unaudited)



	September 30,		December 31,
	2024		2023
	(Millions, except per-share amounts)
ASSETS
Current assets:
Cash and cash equivalents	$	762	$	2,150
Trade accounts and other receivables (net of allowance of ($4) at September 30, 2024 and ($3) at December 31, 2023)	1,310		1,655
Inventories	275		274
Derivative assets	143		239
Other current assets and deferred charges	208		195
Total current assets	2,698		4,513

Investments	4,201		4,637
Property, plant, and equipment	56,479		51,842
Accumulated depreciation and amortization	(18,505)		(17,531)
Property, plant, and equipment – net	37,974		34,311
Intangible assets – net of accumulated amortization	7,305		7,593
Regulatory assets, deferred charges, and other	1,659		1,573
Total assets	$	53,837	$	52,627

LIABILITIES AND EQUITY
Current liabilities:
Accounts payable	$	1,137	$	1,379
Derivative liabilities	95		105
Accrued and other current liabilities	1,203		1,284
Commercial paper	—		725
Long-term debt due within one year	2,284		2,337
Total current liabilities	4,719		5,830

Long-term debt	24,825		23,376
Deferred income tax liabilities	4,312		3,846
Regulatory liabilities, deferred income, and other	5,116		4,684
Contingent liabilities and commitments (Note 9)

Equity:
Stockholders’ equity:
Preferred stock ($1 par value; 30 million shares authorized at September 30, 2024 and December 31, 2023; 35 thousand shares issued at September 30, 2024 and December 31, 2023)	35		35
Common stock ($1 par value; 1,470 million shares authorized at September 30, 2024 and December 31, 2023; 1,258 million shares issued at September 30, 2024 and 1,256 million shares issued at December 31, 2023)	1,258		1,256
Capital in excess of par value	24,611		24,578
Retained deficit	(12,296)		(12,287)
Accumulated other comprehensive income (loss)	—		—
Treasury stock, at cost (39 million shares at September 30, 2024 and December 31, 2023 of common stock)	(1,180)		(1,180)
Total stockholders’ equity	12,428		12,402
Noncontrolling interests in consolidated subsidiaries	2,437		2,489
Total equity	14,865		14,891
Total liabilities and equity	$	53,837	$	52,627

See accompanying notes.

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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 at June 30, 2024	$	35	$	1,258	$	24,589	$	(12,419)	$	13	$	(1,180)	$	12,296	$	2,450	$	14,746

Net income (loss)	—		—		—		706		—		—		706		35		741
Other comprehensive income (loss)	—		—		—		—		(13)		—		(13)		—		(13)



Cash dividends – common stock ($0.4750 per share)	—		—		—		(579)		—		—		(579)		—		(579)

Stock-based compensation and related common stock issuances, net of tax	—		—		22		—		—		—		22		—		22


Dividends and distributions to noncontrolling interests	—		—		—		—		—		—		—		(48)		(48)


Other	—		—		—		(4)		—		—		(4)		—		(4)
Net increase (decrease) in equity	—		—		22		123		(13)		—		132		(13)		119
Balance at September 30, 2024	$	35	$	1,258	$	24,611	$	(12,296)	$	—	$	(1,180)	$	12,428	$	2,437	$	14,865

Balance at June 30, 2023	$	35	$	1,256	$	24,538	$	(12,982)	$	12	$	(1,180)	$	11,679	$	2,530	$	14,209
Net income (loss)	—		—		—		654		—		—		654		30		684
Other comprehensive income (loss)	—		—		—		—		36		—		36		—		36
Cash dividends – common stock ($0.4475 per share)	—		—		—		(544)		—		—		(544)		—		(544)

Stock-based compensation and related common stock issuances, net of tax	—		—		23		—		—		—		23		—		23

Dividends and distributions to noncontrolling interests	—		—		—		—		—		—		—		(62)		(62)


Other	—		—		1		(4)		—		—		(3)		—		(3)
Net increase (decrease) in equity	—		—		24		106		36		—		166		(32)		134
Balance at September 30, 2023	$	35	$	1,256	$	24,562	$	(12,876)	$	48	$	(1,180)	$	11,845	$	2,498	$	14,343

*Accumulated Other Comprehensive Income (Loss)

See accompanying notes.

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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 at December 31, 2023	$	35	$	1,256	$	24,578	$	(12,287)	$	—	$	(1,180)	$	12,402	$	2,489	$	14,891

Net income (loss)	—		—		—		1,739		—		—		1,739		90		1,829




Cash dividends – common stock ($1.4250 per share)	—		—		—		(1,737)		—		—		(1,737)		—		(1,737)

Stock-based compensation and related common stock issuances, net of tax	—		2		33		—		—		—		35		—		35


Dividends and distributions to noncontrolling interests	—		—		—		—		—		—		—		(178)		(178)
Contributions from noncontrolling interests	—		—		—		—		—		—		—		36		36

Other	—		—		—		(11)		—		—		(11)		—		(11)
Net increase (decrease) in equity	—		2		33		(9)		—		—		26		(52)		(26)
Balance at September 30, 2024	$	35	$	1,258	$	24,611	$	(12,296)	$	—	$	(1,180)	$	12,428	$	2,437	$	14,865

Balance at December 31, 2022	$	35	$	1,253	$	24,542	$	(13,271)	$	(24)	$	(1,050)	$	11,485	$	2,560	$	14,045
Net income (loss)	—		—		—		2,041		—		—		2,041		94		2,135
Other comprehensive income (loss)	—		—		—		—		72		—		72		—		72
Cash dividends – common stock ($1.3425 per share)	—		—		—		(1,635)		—		—		(1,635)		—		(1,635)

Stock-based compensation and related common stock issuances, net of tax	—		3		19		—		—		—		22		—		22

Dividends and distributions to noncontrolling interests	—		—		—		—		—		—		—		(174)		(174)
Contributions from noncontrolling interests	—		—		—		—		—		—		—		18		18
Purchases of treasury stock	—		—		—		—		—		(130)		(130)		—		(130)
Other	—		—		1		(11)		—		—		(10)		—		(10)
Net increase (decrease) in equity	—		3		20		395		72		(130)		360		(62)		298
Balance at September 30, 2023	$	35	$	1,256	$	24,562	$	(12,876)	$	48	$	(1,180)	$	11,845	$	2,498	$	14,343

*Accumulated Other Comprehensive Income (Loss)

See accompanying notes.

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The Williams Companies, Inc.

Consolidated Statement of Cash Flows

(Unaudited)


	Nine Months Ended September 30,
	2024		2023
	(Millions)
OPERATING ACTIVITIES:
Net income (loss)	$	1,829	$	2,135
Adjustments to reconcile to net cash provided (used) by operating activities:
Depreciation and amortization	1,654		1,542
Provision (benefit) for deferred income taxes	467		586
Equity (earnings) losses	(431)		(434)
Distributions from equity-method investees	580		607



Net unrealized (gain) loss from commodity derivative instruments	210		(433)
Gain on sale of business (Note 3)	—		(130)
Gain on disposition of equity-method investments (Note 3)	(149)		—
Gain on consolidation of equity-method investments (Note 3)	(127)		—
Inventory write-downs	8		28
Amortization of stock-based awards	69		59
Cash provided (used) by changes in current assets and liabilities:
Accounts receivable	367		1,295
Inventories	(6)		29
Other current assets and deferred charges	(16)		(5)
Accounts payable	(317)		(1,072)
Accrued and other current liabilities	(108)		(114)
Changes in current and noncurrent commodity derivative assets and liabilities	(74)		172
Other, including changes in noncurrent assets and liabilities	(200)		(140)
Net cash provided (used) by operating activities	3,756		4,125
FINANCING ACTIVITIES:
Proceeds from (payments of) commercial paper – net	(723)		(352)
Proceeds from long-term debt	3,594		2,754
Payments of long-term debt	(2,286)		(21)
Payments for debt issuance costs	(31)		(21)
Proceeds from issuance of common stock	8		8
Purchases of treasury stock	—		(130)
Common dividends paid	(1,737)		(1,635)
Dividends and distributions paid to noncontrolling interests	(178)		(174)
Contributions from noncontrolling interests	36		18
Other – net	(34)		(19)
Net cash provided (used) by financing activities	(1,351)		428
INVESTING ACTIVITIES:
Property, plant, and equipment:
Capital expenditures (1)	(1,805)		(1,845)
Dispositions – net	(73)		(33)

Proceeds from sale of business (Note 3)	—		348
Purchases of businesses, net of cash acquired (Note 3)	(1,995)		(1,024)
Proceeds from dispositions of equity-method investments (Note 3)	161		—
Purchases of and contributions to equity-method investments	(101)		(80)
Other – net	20		3
Net cash provided (used) by investing activities	(3,793)		(2,631)
Increase (decrease) in cash and cash equivalents	(1,388)		1,922
Cash and cash equivalents at beginning of year	2,150		152
Cash and cash equivalents at end of period	$	762	$	2,074
_________
(1) Increases to property, plant, and equipment	$	(1,840)	$	(1,960)
Changes in related accounts payable and accrued liabilities	35		115
Capital expenditures	$	(1,805)	$	(1,845)

See accompanying notes.

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The Williams Companies, Inc.
Notes to Consolidated Financial Statements

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, 2023, in our Annual Report on Form 10-K. The accompanying unaudited financial statements include all normal recurring adjustments and others that, in the opinion of management, are necessary to present fairly our interim financial statements.

The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the amounts reported in 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.

Share Repurchase Program

In September 2021, our Board of Directors authorized a share repurchase program with a maximum dollar limit of $1.5 billion. Repurchases may be made from time to time in the open market, by block purchases, in privately negotiated transactions, or in such other manner as determined by our management. Our management will also determine the timing and amount of any repurchases based on market conditions and other factors. The share repurchase program does not obligate us to acquire any particular amount of common stock, and it may be suspended or discontinued at any time. This share repurchase program does not have an expiration date. During the nine months ended September 30, 2024 and 2023, there have been $0 and $130 million in repurchases under the program which are included in our Consolidated Statement of Changes in Equity. Cumulative repurchases to date under the program total $139 million.

Description of Business

We are a Delaware corporation whose common stock is listed and traded on the New York Stock Exchange. Our operations are located in the United States and 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 and corporate activities, are included in Other.

Transmission & Gulf of Mexico is comprised of our interstate natural gas pipelines, Transcontinental Gas Pipe Line Company, LLC (Transco), Northwest Pipeline LLC (Northwest Pipeline), and MountainWest Pipelines Holding Company (MountainWest), and their related natural gas storage facilities, 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 Discovery Producer Services LLC (Discovery), a former 60 percent equity-method investment in which we acquired the remaining ownership interest in August 2024 (see Note 3 – Acquisitions and Divestitures). Transmission & Gulf of Mexico also includes natural gas storage facilities and pipelines providing services in north Texas, and also in Louisiana and Mississippi related to the January 2024 Gulf Coast Storage Acquisition (see Note 3 – Acquisitions and Divestitures).

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

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Notes (Continued)

as a 65 percent interest in Ohio Valley Midstream LLC (Northeast JV) (a consolidated VIE) which operates in West Virginia, Ohio, and Pennsylvania, a 66 percent interest in Cardinal Gas Services, L.L.C. (Cardinal) (a consolidated VIE) which operates in Ohio, a 69 percent equity-method investment in Laurel Mountain Midstream, LLC (Laurel Mountain), a 50 percent equity-method investment in Blue Racer Midstream LLC (Blue Racer), 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, the Mid-Continent region which includes the Anadarko and Permian basins, and the Denver-Julesberg Basin (DJ Basin) of Colorado which includes Rocky Mountain Midstream Holdings LLC (RMM), a former 50 percent equity-method investment in which we acquired the remaining ownership interest in November 2023 (see Note 3 – Acquisitions and Divestitures). This segment also includes our NGL storage facilities, an undivided 50 percent interest in an NGL fractionator near Conway, Kansas, and a 50 percent equity-method investment in Overland Pass Pipeline Company LLC (OPPL).

Gas & NGL Marketing Services is comprised of our natural gas liquid (NGL) and natural gas marketing and trading operations, which includes risk management and transactions related to the storage and transportation of natural gas and NGLs on strategically positioned assets.

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.

Discontinued operations

During the second quarter of 2023, we recorded pre-tax charges of $115 million to Income (loss) from discontinued operations in our Consolidated Statement of Income related to litigation associated with our former Alaska refinery. An additional $1 million of pre-tax interest expense was recorded in the third quarter of 2023. This matter was settled in January 2024. Except for this item and unless indicated otherwise, the information in the Notes to Consolidated Financial Statements relates to our continuing operations.

Accounting Standards Issued But Not Yet Adopted

In November 2023, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) 2023-07, Segment Reporting (Topic 280): Improvements to Reportable Segment Disclosures, which requires disclosure of significant segment expenses and expanded interim disclosures. This ASU is effective for fiscal years beginning after December 15, 2023, and interim periods within fiscal years beginning after December 15, 2024, and early adoption is permitted. We do not expect adoption of ASU 2023-07 will have a material impact on our financial

statements.

In December 2023, the FASB issued ASU 2023-09, Income Taxes: Improvements to Income Tax Disclosures, which requires disclosure of specific categories in the rate reconciliation and additional information for reconciling items that meet a quantitative threshold. This ASU is effective for fiscal years beginning after December 15, 2024,

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Notes (Continued)

and early adoption is permitted. We do not expect adoption of ASU 2023-09 will have a material impact on our financial statements.

Note 2 – Variable Interest Entities

Consolidated VIEs

As of September 30, 2024, we consolidate the following VIEs:

Northeast JV

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

Gulfstar One

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

Cardinal

We own 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. In order to meet contractual gas gathering commitments, we may fund more than our proportional share of future expansion activity, which could ultimately impact relative ownership.

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,		December 31,
	2024		2023
	(Millions)
Assets (liabilities):
Cash and cash equivalents	$	35	$	33
Trade accounts and other receivables – net	184		215
Inventories	5		5
Other current assets and deferred charges	5		4
Property, plant, and equipment – net	4,934		5,046
Intangible assets – net of accumulated amortization	1,968		2,049
Regulatory assets, deferred charges, and other	27		31
Accounts payable	(54)		(109)
Accrued and other current liabilities	(26)		(28)

Regulatory liabilities, deferred income, and other	(262)		(268)

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Notes (Continued)

Nonconsolidated VIEs

We own certain equity-method investments that are VIEs due primarily to our limited participating rights as a minority equity holder. Our maximum exposure to loss is limited to the carrying value of these investments, which totaled $74 million at September 30, 2024.

Note 3 – Acquisitions and Divestitures

Discovery Acquisition

As of December 31, 2023, we owned a 60 percent interest in Discovery, which we accounted for as an equity-method investment. On August 1, 2024, we closed on the acquisition of the remaining 40 percent interest in Discovery, along with certain other assets, for $170 million cash, subject to working capital and post-closing adjustments (Discovery Acquisition). As a result of acquiring this additional interest, we obtained control and now consolidate Discovery. The purpose of this acquisition was to expand our gathering, processing, and transportation presence in the Gulf of Mexico region. Assets acquired, acquisition-related costs incurred, and results of operations realized are included within our Transmission & Gulf of Mexico segment.

During the period from the acquisition date of August 1, 2024 to September 30, 2024, the operations acquired in the Discovery Acquisition contributed Revenues of $46 million and Modified EBITDA (as defined in Note 10 – Segment Disclosures) of $10 million.

We accounted for the Discovery 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 book value of our existing equity-method investment prior to the acquisition date of August 1, 2024, was $381 million. We recognized a $127 million gain on remeasuring our existing equity-method investment to fair value included in Other investing income (loss) – net in our Consolidated Statement of Income for the three and nine months ended September 30, 2024, which is not included in the pro forma Discovery adjustments below. We utilized the income approach to fair value our previous equity-method investment in Discovery.

The following table presents the preliminary allocation of the acquisition date fair value of the major classes of the assets acquired and liabilities assumed at August 1, 2024. 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 property, plant, and equipment, which utilized the cost approach; however, adjustments to those measurements may be made in subsequent periods, up to one year from the acquisition date, as new information related to facts and circumstances as of the acquisition date may be identified.


	(Millions)
Cash and cash equivalents	$	22
Other current assets	19
Property, plant, and equipment – net	941
Other noncurrent assets	39
Total assets acquired	$	1,021

Current liabilities	$	(40)
Noncurrent liabilities	(296)
Total liabilities assumed	$	(336)

Net assets acquired	$	685

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Notes (Continued)

Gulf Coast Storage Acquisition

On January 3, 2024, we closed on the acquisition of 100 percent of a strategic portfolio of natural gas storage facilities and pipelines, located in Louisiana and Mississippi, from Hartree Partners LP (Gulf Coast Storage Acquisition) for $1.95 billion. The purpose of this acquisition was to expand our natural gas storage footprint in the Gulf Coast region. Assets acquired, acquisition-related costs incurred, and results of operations realized are included within our Transmission & Gulf of Mexico segment. The Gulf Coast Storage Acquisition was funded with cash on hand and $100 million of deferred consideration that does not accrue interest and is payable one year from the acquisition date. The obligation is presented within Long-term debt due within one year in our Consolidated Balance Sheet owed by our wholly owned subsidiary Williams Field Services Group, LLC.

During the period from the acquisition date of January 3, 2024 to September 30, 2024, the operations acquired in the Gulf Coast Storage Acquisition contributed Revenues of $171 million and Modified EBITDA of $123 million, which is impacted by acquisition-related costs. Acquisition-related costs for the Gulf Coast Storage Acquisition total $14 million, including $13 million incurred in the nine months ended September 30, 2024 included in Selling, general, and administrative expenses in our Consolidated Statement of Income.

We accounted for the Gulf Coast Storage Acquisition as a business combination. The valuation technique used consisted of the cost approach for property, plant, and equipment.

The following table presents the preliminary allocation of the acquisition date fair value of the major classes of the assets acquired and liabilities assumed at January 3, 2024. 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 property, plant, and equipment; however, adjustments to those measurements may be made in subsequent periods, up to one year from the acquisition date, as new information related to facts and circumstances as of the acquisition date may be identified.


	(Millions)
Cash and cash equivalents	$	46
Other current assets	18
Property, plant, and equipment – net	2,035
Other noncurrent assets	2
Total assets acquired	$	2,101

Current liabilities	$	(11)
Noncurrent liabilities	(107)
Total liabilities assumed	$	(118)

Net assets acquired	$	1,983

DJ Basin Acquisitions

Cureton Acquisition

On November 30, 2023, we closed on the acquisition of 100 percent of Cureton Front Range, LLC (Cureton Acquisition), whose operations are located in the DJ Basin, for $546 million, subject to working capital and post-closing adjustments. The purpose of this acquisition was to expand our gathering and processing footprint and create operational synergies for our operations in the DJ Basin. Assets acquired, acquisition-related costs incurred, and results of operations realized are included within our West segment. The Cureton Acquisition was funded with cash on hand.

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Notes (Continued)

During the period from the acquisition date of November 30, 2023 to December 31, 2023, the operations acquired in the Cureton Acquisition contributed Revenues of $35 million and Modified EBITDA of $7 million.

Acquisition-related costs for the Cureton Acquisition total $7 million, including $1 million incurred in the nine months ended September 30, 2024, included in Selling, general, and administrative expenses in our Consolidated Statement of Income.

We accounted for the Cureton Acquisition as a business combination. The valuation techniques used consisted of the cost approach for property, plant, and equipment and the income approach for valuation of other intangible assets.

The following table presents the preliminary allocation of the acquisition date fair value of the major classes of the assets acquired and liabilities assumed at November 30, 2023. 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 property, plant, and equipment and other intangible assets; however, adjustments to those measurements may be made in subsequent periods, up to one year from the acquisition date, as new information related to facts and circumstances as of the acquisition date may be identified.


	(Millions)
Cash and cash equivalents	$	6
Other current assets	21
Property, plant, and equipment – net	435
Intangible assets – net of accumulated amortization	117
Other noncurrent assets	1
Total identifiable assets acquired	$	580

Current liabilities	$	(29)
Noncurrent liabilities	(14)
Total liabilities assumed	$	(43)

Net identifiable assets acquired	$	537

Goodwill included in Intangible assets – net of accumulated amortization	9
Net assets acquired	$	546

Other intangible assets recognized in the Cureton Acquisition are related to contractual customer relationships from gas gathering and processing 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 24 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 10 years.

RMM Acquisition

As of December 31, 2022, we owned a 50 percent interest in RMM which we accounted for as an equity-method investment. On November 30, 2023, we closed on the acquisition of the remaining 50 percent interest in RMM (RMM Acquisition) for $704 million. As a result of acquiring this additional interest, we obtained control and

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Notes (Continued)

now consolidate RMM. The purpose of this acquisition was to expand our gathering and processing footprint and create operational synergies for our operations in the DJ Basin. Assets acquired and results of operations realized are included within our West segment. Substantially all of the RMM purchase price was not due to the seller until the first quarter of 2025, would not accrue interest until November 2, 2024, and could be repaid early without penalty. It was recorded as a deferred consideration obligation at fair value using an income approach, which resulted in a discount to the contractual amount due which was imputed as interest expense over the term of the obligation. The obligation is presented within Long-term debt due within one year in our Consolidated Balance Sheet as of September 30, 2024, owed by our wholly owned subsidiary Williams Rocky Mountain Midstream Holdings LLC. On November 1, 2024, we paid the remaining $651 million of the RMM purchase price obligation.

During the period from the acquisition date of November 30, 2023 to December 31, 2023, RMM contributed Revenues of $53 million and Modified EBITDA of $12 million.

We accounted for the RMM Acquisition as a business combination. The book value of our existing equity-method investment prior to the acquisition date of November 30, 2023, was $406 million. We recognized a $30 million gain on remeasuring our existing equity-method investment to fair value included in Other investing income (loss) – net in our Consolidated Statement of Income during 2023, which is not included in the pro forma DJ Basin adjustments below. The valuation techniques used consisted of the income approach for our previous equity-method investment in RMM and the valuation of other intangible assets, and the cost approach for property, plant, and equipment.

The following table presents the preliminary allocation of the acquisition date fair value of the major classes of the assets acquired and liabilities assumed at November 30, 2023. The net assets acquired primarily reflect the noncash consideration transferred, which includes the fair value of both our previous equity-method investment and the deferred consideration obligation. 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 property, plant, and equipment and other intangible assets; however, adjustments to those measurements may be made in subsequent periods, up to one year from the acquisition date, as new information related to facts and circumstances as of the acquisition date may be identified.


	(Millions)
Cash and cash equivalents	$	28
Other current assets	4
Investments	20
Property, plant, and equipment – net	1,041
Intangible assets – net of accumulated amortization	63
Other noncurrent assets	12
Total identifiable assets acquired	$	1,168

Current liabilities	$	(44)
Noncurrent liabilities	(103)
Total liabilities assumed	$	(147)

Net identifiable assets acquired	$	1,021

Goodwill included in Intangible assets – net of accumulated amortization	55
Net assets acquired	$	1,076

Goodwill recognized in the RMM Acquisition relates primarily to enhancing and diversifying our basin positions as well as delivering operational synergies, including increasing volumes on our existing processing facilities and increasing revenues on our NGL transportation, fractionation, and storage assets, and is reported within

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Notes (Continued)

our West segment. Substantially all of the goodwill is deductible for tax purposes. Goodwill is included within Intangible assets – net of accumulated amortization in our Consolidated Balance Sheet and represents the excess of the consideration, plus the fair value of any noncontrolling interest or any previously held equity interest, over the fair value of the net assets acquired. It is not subject to amortization but is evaluated annually as of October 1 for impairment or more frequently if impairment indicators are present that would indicate it is more likely than not that the fair value of the reporting unit is less than its carrying amount. As part of the evaluation, we compare our estimate of the fair value of the reporting unit with its carrying value, including goodwill. If the carrying value of the reporting unit exceeds its fair value, an impairment charge is recorded for the difference (not to exceed the carrying value of goodwill). Judgments and assumptions are inherent in our management’s estimates of fair value.

Other intangible assets recognized in the RMM Acquisition are related to contractual customer relationships from gas gathering and processing 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 18 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 10 years.

MountainWest Acquisition

On February 14, 2023, we closed on the acquisition of 100 percent of MountainWest, which includes Federal Energy Regulatory Commission (FERC)-regulated interstate natural gas pipeline systems and natural gas storage capacity (MountainWest Acquisition), for $1.08 billion of cash, funded with available sources of short-term liquidity, and retaining $430 million outstanding principal amount of MountainWest long-term debt. For 2023, $1.024 billion is presented in Purchases of businesses, net of cash acquired in our Consolidated Statement of Cash Flows reflecting the cash purchase price, reduced for post-closing adjustments and the cash acquired as presented in the purchase price allocation. The purpose of the MountainWest Acquisition was to expand our existing transmission and storage infrastructure footprint into major markets in Utah, Wyoming, and Colorado. Assets acquired, acquisition-related costs incurred, and results of operations realized are included within our Transmission & Gulf of Mexico segment.

During the period from the acquisition date of February 14, 2023 to December 31, 2023, the operations acquired in the MountainWest Acquisition contributed Revenues of $225 million and Modified EBITDA of $122 million, which includes $27 million of transition-related costs.

Acquisition-related costs for the MountainWest Acquisition total $17 million, including $15 million incurred in the nine months ended September 30, 2023, included in Selling, general, and administrative expenses in our Consolidated Statement of Income.

We accounted for the MountainWest Acquisition as a business combination. The valuation techniques used consisted of the cost approach for nonregulated property, plant, and equipment, as well as the market approach for the assumed long-term debt consistent with the valuation technique discussed in Note 7 – Fair Value Measurements and Guarantees. MountainWest’s regulated operations are accounted for pursuant to Accounting Standards Codification Topic 980, “Regulated Operations.” The fair value of assets and liabilities subject to rate making and cost recovery provisions were determined utilizing the income approach. MountainWest’s expected return on rate base is consistent with expected returns of similarly situated assets, resulting in carryover basis of these assets and liabilities equaling their fair value.

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Notes (Continued)

The following table presents the allocation of the acquisition date fair value of the major classes of the assets acquired and liabilities assumed at February 14, 2023. The fair value of accounts receivable acquired equals contractual amounts receivable.


	(Millions)
Cash and cash equivalents	$	23
Trade accounts and other receivables	33
Other current assets	26
Investments	20
Property, plant, and equipment – net	1,019
Other noncurrent assets	33
Total identifiable assets acquired	$	1,154

Current liabilities	$	(47)
Long-term debt	(365)
Other noncurrent liabilities	(95)
Total liabilities assumed	$	(507)

Net identifiable assets acquired	$	647

Goodwill included in Intangible assets – net of accumulated amortization	400
Net assets acquired	$	1,047

Goodwill recognized in the MountainWest Acquisition relates primarily to enhancing and diversifying our basin positions and the long-term value associated with rate regulated businesses and is reported within our Transmission & Gulf of Mexico segment. Substantially all of the goodwill is deductible for tax purposes.

Supplemental Pro Forma

The following pro forma Revenues and Net income (loss) attributable to The Williams Companies, Inc. for the three and nine months ended September 30, 2024 and 2023, are presented as if the Discovery Acquisition and Gulf Coast Storage Acquisition had been completed on January 1, 2023, and the DJ Basin Acquisitions and MountainWest Acquisition had been completed on January 1, 2022. These pro forma amounts are not necessarily indicative of what the actual results would have been if the acquisitions 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 transactions or the potential costs to achieve these cost savings, operating synergies, and revenue enhancements.

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Notes (Continued)


	Three Months Ended September 30, 2024
	As Reported		Pro Forma Discovery (1)								Pro Forma Combined
	(Millions)
Revenues	$	2,653	$	9							$	2,662
Net income (loss) attributable to The Williams Companies, Inc.	706		(1)								705

	Three Months Ended September 30, 2023
	As Reported		Pro Forma Discovery		Pro Forma Gulf Coast Storage		Pro Forma DJ Basin				Pro Forma Combined
	(Millions)
Revenues	$	2,559	$	31	$	51	$	78			$	2,719
Net income (loss) attributable to The Williams Companies, Inc.	654		1		12		5				672

	Nine Months Ended September 30, 2024
	As Reported		Pro Forma Discovery (1)								Pro Forma Combined
	(Millions)
Revenues	$	7,760	$	58							$	7,818
Net income (loss) attributable to The Williams Companies, Inc.	1,739		(5)								1,734

	Nine Months Ended September 30, 2023
	As Reported		Pro Forma Discovery		Pro Forma Gulf Coast Storage		Pro Forma DJ Basin		Pro Forma MountainWest (1)		Pro Forma Combined
	(Millions)
Revenues	$	8,123	$	96	$	145	$	219	$	35	$	8,618
Net income (loss) attributable to The Williams Companies, Inc.	2,041		—		47		13		6		2,107

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

Sale of Aux Sable Interest

On August 1, 2024, we completed the sale of our equity-method investments in Aux Sable Liquid Products Inc., Aux Sable Liquid Products LP, and Aux Sable Midstream LLC (collectively, “Aux Sable”) in our Northeast G&P segment for total consideration of $161 million. As a result of this sale, we recorded a gain of $149 million in the third quarter of 2024. The gain is reflected in Other investing income (loss) – net in our Consolidated Statement of Income.

Sale of Certain Gulf Coast Liquids Pipelines

On September 29, 2023, we completed the sale of various petrochemical and feedstock pipelines and associated contracts in the Gulf Coast region for $348 million. As a result of this sale, we recorded a gain of $130 million primarily in the third quarter of 2023 in our Transmission & Gulf of Mexico segment. The gain is reflected in Gain on sale of business in our Consolidated Statement of Income. The results of operations for this disposal group, excluding the gain noted, were not significant for the reporting periods.

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Notes (Continued)

Note 4 – Revenue Recognition

Revenue by Category

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


	Regulated Interstate Transportation & Storage		Gulf of Mexico Midstream & Storage		Northeast Midstream		West Midstream		Gas & NGL Marketing Services		Other		Eliminations		Total
	(Millions)
Three Months Ended September 30, 2024
Revenues from contracts with customers:
Service revenues:
Regulated interstate natural gas transportation and storage	$	879	$	—	$	—	$	—	$	—	$	—	$	(20)	$	859
Gathering, processing, transportation, fractionation, and storage:
Monetary consideration	—		177		442		422		—		—		(42)		999
Commodity consideration	—		14		1		19		—		—		—		34
Other	3		5		22		4		—		—		(3)		31
Total service revenues	882		196		465		445		—		—		(65)		1,923
Product sales	28		58		26		218		1,005		95		(318)		1,112
Total revenues from contracts with customers	910		254		491		663		1,005		95		(383)		3,035
Other revenues (1)	6		2		11		—		515		8		(1)		541
Other adjustments (2)	—		—		—		—		(1,038)		—		115		(923)
Total revenues	$	916	$	256	$	502	$	663	$	482	$	103	$	(269)	$	2,653

Three Months Ended September 30, 2023
Revenues from contracts with customers:
Service revenues:
Regulated interstate natural gas transportation and storage	$	841	$	—	$	—	$	—	$	—	$	—	$	(18)	$	823
Gathering, processing, transportation, fractionation, and storage:
Monetary consideration	—		121		450		368		—		—		(41)		898
Commodity consideration	—		11		—		34		—		—		—		45
Other	5		2		22		2		—		—		(3)		28
Total service revenues	846		134		472		404		—		—		(62)		1,794
Product sales	35		31		27		112		1,189		117		(244)		1,267
Total revenues from contracts with customers	881		165		499		516		1,189		117		(306)		3,061
Other revenues (1)	5		4		6		17		697		13		(2)		740
Other adjustments (2)	—		—		—		—		(1,328)		—		86		(1,242)
Total revenues	$	886	$	169	$	505	$	533	$	558	$	130	$	(222)	$	2,559

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Notes (Continued)


	Regulated Interstate Transportation & Storage		Gulf of Mexico Midstream & Storage		Northeast Midstream		West Midstream		Gas & NGL Marketing Services		Other		Eliminations		Total
	(Millions)
Nine Months Ended September 30, 2024
Revenues from contracts with customers:
Service revenues:
Regulated interstate natural gas transportation and storage	$	2,605	$	—	$	—	$	—	$	—	$	—	$	(61)	$	2,544
Gathering, processing, transportation, fractionation, and storage:
Monetary consideration	—		480		1,317		1,253		—		—		(117)		2,933
Commodity consideration	—		28		1		53		—		—		—		82
Other	12		20		69		15		—		—		(12)		104
Total service revenues	2,617		528		1,387		1,321		—		—		(190)		5,663
Product sales	75		114		74		657		3,233		289		(884)		3,558
Total revenues from contracts with customers	2,692		642		1,461		1,978		3,233		289		(1,074)		9,221
Other revenues (1)	19		8		33		7		1,685		22		(2)		1,772
Other adjustments (2)	—		—		—		—		(3,575)		—		342		(3,233)
Total revenues	$	2,711	$	650	$	1,494	$	1,985	$	1,343	$	311	$	(734)	$	7,760

Nine Months Ended September 30, 2023
Revenues from contracts with customers:
Service revenues:
Regulated interstate natural gas transportation and storage	$	2,480	$	—	$	—	$	—	$	—	$	—	$	(41)	$	2,439
Gathering, processing, transportation, fractionation, and storage:
Monetary consideration	—		334		1,334		1,070		—		—		(130)		2,608
Commodity consideration	—		29		3		76		—		—		—		108
Other	14		10		67		8		1		—		(11)		89
Total service revenues	2,494		373		1,404		1,154		1		—		(182)		5,244
Product sales	114		91		104		287		3,519		302		(686)		3,731
Total revenues from contracts with customers	2,608		464		1,508		1,441		3,520		302		(868)		8,975
Other revenues (1)	26		11		20		95		3,240		36		(2)		3,426
Other adjustments (2)	—		—		—		—		(4,566)		—		288		(4,278)
Total revenues	$	2,634	$	475	$	1,528	$	1,536	$	2,194	$	338	$	(582)	$	8,123

______________________________

(1)Revenues not derived from contracts with customers primarily consist of physical product sales related to commodity derivative contracts, realized and unrealized gains and losses associated with our commodity derivative contracts, which are reported in Net gain (loss) from commodity derivatives in our Consolidated Statement of Income, management fees that we receive for certain services we provide to operated equity-method investments, and leasing revenues associated with our headquarters building.

(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 or engage in energy trading activities, the resulting revenues are presented net of the related costs of those activities in our Consolidated Statement of Income.

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Notes (Continued)

Contract Assets

The following table presents a reconciliation of our contract assets:


	Three Months Ended September 30,				Nine Months Ended September 30,
	2024		2023		2024		2023
	(Millions)
Balance at beginning of period	$	67	$	56	$	36	$	29
Revenue recognized in excess of amounts invoiced	44		45		125		133
Minimum volume commitments invoiced	(23)		(28)		(73)		(89)
Contract assets acquired	36		—		$	36	—
Balance at end of period	$	124	$	73	$	124	$	73

Contract Liabilities

The following table presents a reconciliation of our contract liabilities:


	Three Months Ended September 30,				Nine Months Ended September 30,
	2024		2023		2024		2023
	(Millions)
Balance at beginning of period	$	1,064	$	1,039	$	1,081	$	1,043
Payments received and deferred	33		40		150		164
Significant financing component	2		3		6		7
Contract liability acquired (disposed) – net	53		(2)		53		3
Recognized in revenue	(66)		(68)		(204)		(205)
Balance at end of period	$	1,086	$	1,012	$	1,086	$	1,012

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 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 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, 2024, 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, 2024, 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)

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, 2024.


	Contract Liabilities		Remaining Performance Obligations
	(Millions)
2024 (three months)	$	55	$	1,052
2025 (one year)	171		4,069
2026 (one year)	142		3,819
2027 (one year)	131		3,438
2028 (one year)	115		2,716
Thereafter	472		15,980
Total	$	1,086	$	31,074

Accounts Receivable

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


	September 30, 2024		December 31, 2023
	(Millions)
Accounts receivable related to revenues from contracts with customers	$	1,096	$	1,292
Receivables from derivatives	155		311
Other accounts receivable	59		52
Trade accounts and other receivables	$	1,310	$	1,655

Note 5 – Provision (Benefit) for Income Taxes

The Provision (benefit) for income taxes from continuing operations includes:


	Three Months Ended September 30,				Nine Months Ended September 30,
	2024		2023		2024		2023
	(Millions)
Current:
Federal	$	11	$	10	$	65	$	10
State	7		7		17		11

	18		17		82		21
Deferred:
Federal	178		169		395		555
State	31		(10)		72		59

	209		159		467		614
Provision (benefit) for income taxes	$	227	$	176	$	549	$	635

The effective income tax rates for the total provision (benefit) for the three and nine months ended September 30, 2024 are greater than the federal statutory rate, primarily due to the effect of state income taxes.

The effective income tax rate for the total provision (benefit) for the three months ended September 30, 2023 is less than the federal statutory rate, primarily due to a decrease in our estimate of the deferred state income tax rate.

The effective income tax rate for the total provision (benefit) for the nine months ended September 30, 2023 is greater than the federal statutory rate, primarily due to the effect of state income taxes.

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Notes (Continued)

Note 6 – Debt and Banking Arrangements

Issuances

Our senior unsecured public debt issuances for 2024 are as follows:


Issue Date	Maturity Date	Amount		Rate
		(Millions)
January 5, 2024	March 15, 2029	$	1,100	4.900%
January 5, 2024	March 15, 2034	1,000		5.150%
August 13, 2024	November 15, 2029	450		4.800%
August 13, 2024	March 15, 2034	300		5.150%
August 13, 2024	November 15, 2054	750		5.800%

Retirements

Our senior unsecured public debt retirements for 2024 are as follows:

Date of Retirement

Maturity Date

Amount

Rate

(Millions)

March 4, 2024

1,000

4.300%

June 24, 2024

1,250

4.550%

Credit Facility


	September 30, 2024
	Stated Capacity		Outstanding
	(Millions)
Long-term credit facility (1)	$	3,750	$	—
Letters of credit under certain bilateral bank agreements			12

________________

Commercial Paper Program

At September 30, 2024, no commercial paper was outstanding under our $3.5 billion commercial paper program.

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Notes (Continued)

Note 7 – 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, accounts payable, and commercial paper approximate fair value because of the short-term nature of these instruments. Therefore, these assets and liabilities are not presented in the following table.


					Fair Value Measurements Using
	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, 2024:
Measured on a recurring basis:
ARO Trust investments	$	295	$	295	$	295	$	—	$	—
Commodity derivative assets (1)	132		132		21		62		49
Commodity derivative liabilities (1)	(319)		(319)		—		(317)		(2)


Additional disclosures:


Long-term debt, including current portion	(27,109)		(27,248)		—		(27,248)		—
Guarantees	(36)		(28)		—		(12)		(16)

Assets (liabilities) at December 31, 2023:
Measured on a recurring basis:
ARO Trust investments	$	269	$	269	$	269	$	—	$	—
Commodity derivative assets (2)	310		310		141		112		57
Commodity derivative liabilities (2)	(285)		(285)		(3)		(278)		(4)
Interest rate derivatives	6		6		—		6		—
Additional disclosures:

Long-term debt, including current portion	(25,713)		(25,553)		—		(25,553)		—
Guarantees	(37)		(28)		—		(12)		(16)

(1)Commodity derivative assets and liabilities exclude $76 million of net cash collateral in Level 1.

(2)Commodity derivative assets and liabilities exclude $2 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 Consolidated Balance Sheet. Both realized and unrealized gains and losses are ultimately recorded as regulatory assets or liabilities.

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Notes (Continued)

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 reported 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 Derivative 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) from commodity derivatives and Net processing commodity expenses in our Consolidated Statement of Income. See Note 8 – Commodity Derivatives for additional information on our derivatives.

Interest rate derivatives: At December 31, 2023, we held forward starting interest rate swap agreements with notional amounts totaling $1.15 billion. During the nine months ended September 30, 2024. we entered into additional agreements totaling $650 million of notional value and terminated agreements totaling $1.75 billion of notional value coinciding with issuances of long-term debt (see Note 6 – Debt and Banking Arrangements). At September 30, 2024, we hold interest rate swap agreements with notional amounts totaling $50 million. The fair value of these derivatives is determined using discounted cash flows considering forward interest rates and the terms of the agreements, corroborated by counterparty valuations, and is classified as a Level 2 measurement. We designated these derivatives as cash flow hedges to reduce interest rate exposure on future debt issuances. Gains and losses on these derivative instruments are reflected as a component of AOCI and, after the termination of the swap agreement, are amortized to earnings over the term of the related debt as a component of Interest expense in our Consolidated Statement of Income. These forward starting interest rate swaps are reported in Derivative assets and Derivative liabilities in our Consolidated Balance Sheet.

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, as well as the deferred consideration obligations associated with the RMM Acquisition and the Gulf Coast Storage Acquisition (see Note 3 – Acquisitions and Divestitures), all 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, Inc., (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 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 and other current liabilities in our Consolidated Balance Sheet. The maximum potential undiscounted liquidity exposure is approximately $22 million at September 30, 2024. Our exposure declines systematically through the remaining term of WilTel’s obligation.

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Notes (Continued)

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.

Note 8 – Commodity 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 7 – Fair Value Measurements and Guarantees for additional fair value information. In our Consolidated Statement of Cash Flows, any cash impacts of settled commodity derivatives are recorded as operating activities.

We enter into commodity 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, 2024, the notional volume of the net long (short) positions for our commodity derivative contracts were as follows:

Commodity

Unit of Measure

Net Long (Short) Position

Index Risk

Natural Gas

MMBtu

643,267,898

Central Hub Risk - Henry Hub

Natural Gas

MMBtu

(81,249,969)

Basis Risk

Natural Gas

MMBtu

(32,352,683)

Central Hub Risk - Mont Belvieu

Natural Gas Liquids

Barrels

(1,108,762)

Basis Risk

Natural Gas Liquids

Barrels

(670,000)

Central Hub Risk - WTI

Crude Oil

Barrels

(240,000)

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Notes (Continued)

Commodity Derivatives Financial Statement Presentation

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


	September 30, 2024				December 31, 2023
Commodity Derivatives Categories	Assets		(Liabilities)		Assets		(Liabilities)
	(Millions)





Current	$	360	$	(365)	$	623	$	(496)
Noncurrent	288		(470)		243		(345)
Total commodity derivatives	$	648	$	(835)	$	866	$	(841)
Counterparty and collateral netting offset	(433)		509		(552)		554
Amounts recognized in our Consolidated Balance Sheet	$	215	$	(326)	$	314	$	(287)

The pre-tax impacts of commodity derivatives, which are not designated as hedging instruments for accounting purposes, are reflected in our Consolidated Statement of Income as follows:


	Gain (Loss)

	Three Months Ended September 30,				Nine Months Ended September 30,
	2024		2023		2024		2023
	(Millions)
Net gain (loss) from commodity derivatives within Total revenues:

Realized	$	(7)	$	(8)	$	74	$	169
Unrealized	12		32		(207)		476
	$	5	$	24	$	(133)	$	645

Net gain (loss) from commodity derivatives within Net processing commodity expenses:
Realized	$	(2)	$	—	$	(7)	$	(3)
Unrealized	1		(9)		(3)		(43)
	$	(1)	$	(9)	$	(10)	$	(46)
Total net gain (loss) from commodity derivatives	$	4	$	15	$	(143)	$	599

Contingent Features

Generally, collateral may be provided in the form of 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. At September 30, 2024, the contractually required collateral in the event of a credit rating downgrade to non-investment grade status was $4 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, 2024, net cash collateral held on deposit in broker margin accounts was $76 million.

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Notes (Continued)

Note 9 – Contingencies

Royalty Matters

Certain of our customers, including Expand Energy Corporation (formerly Chesapeake Energy Corporation or 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, which obligations survived Chesapeake’s bankruptcy proceedings. Prior to its bankruptcy, Chesapeake reached a settlement to resolve substantially all Pennsylvania royalty cases pending. During the pendency of the bankruptcy, that settlement was renegotiated. The settlement applies to both Chesapeake and us and does not require any contribution from us. On August 23, 2021, after referral to the United States District Court for the Southern District of Texas by the bankruptcy court, the court approved the settlement. Two objectors filed an appeal with the United States Court of Appeals for the Fifth Circuit. On June 8, 2023, the Court of Appeals vacated the settlement approval and remanded to the United States District Court for the Southern District of Texas with instructions to dismiss the settlement proceedings for lack of jurisdiction. On August 31, 2023, the bankruptcy court entered an order finding the settlement agreements to be null and void. Certain plaintiffs have filed a notice of dismissal of their claims against Chesapeake that arose prior to February 8, 2021, in the United States District Court for the Middle District of Pennsylvania lawsuits. The notice states that plaintiffs are not releasing their claims against the other defendants, including us, or claims against Chesapeake that arose after February 9, 2021. We continue to believe the claims against us are subject to indemnity obligations owed to us by Chesapeake.

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, 2024, we have accrued liabilities totaling $44 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, 2024, 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.

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Notes (Continued)

Continuing operations

Our interstate gas pipelines are involved in remediation and monitoring 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, 2024, we have accrued liabilities of $12 million for these costs and expect to recover approximately $4 million through rates.

We also accrue environmental remediation costs for natural gas underground storage facilities, primarily related to soil and groundwater contamination. At September 30, 2024, we have accrued liabilities totaling $7 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. At September 30, 2024, we have accrued environmental liabilities of $25 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.

At September 30, 2024, other than as previously disclosed, we are not aware of any material claims against us involving the above-described indemnities. 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 10 – 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

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Notes (Continued)

provided to our oil and gas properties. Intersegment Product sales primarily represent the sale of natural gas and 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:

◦Income (loss) from discontinued operations;

◦Provision (benefit) for income taxes;

◦Interest expense;

◦Equity earnings (losses);

◦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.

Significant noncash items which are components of Modified EBITDA may include unrealized net gain (loss) from commodity derivatives within Total revenues, unrealized net gain (loss) from commodity derivatives within Net processing commodity expenses for our Gas & NGL Marketing Services segment, charges associated with lower of cost or net realizable value adjustments to our inventory within Product sales and Product costs, and impairments of certain assets within Other (income) expense – net within Operating income (loss).

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,
	2024		2023		2024		2023
	(Millions)
Modified EBITDA by segment:
Transmission & Gulf of Mexico	$	811	$	881	$	2,448	$	2,327
Northeast G&P	476		454		1,461		1,439
West	323		315		968		931
Gas & NGL Marketing Services	11		43		(14)		678
Total reportable segments	1,621		1,693		4,863		5,375
Modified EBITDA of other business activities	58		81		181		196
	1,679		1,774		5,044		5,571
Accretion expense associated with asset retirement obligations for nonregulated operations	(17)		(14)		(56)		(43)
Depreciation and amortization expenses	(566)		(521)		(1,654)		(1,542)

Equity earnings (losses)	147		127		431		434

Other investing income (loss) – net	290		24		332		45
Proportional Modified EBITDA of equity-method investments	(227)		(215)		(693)		(693)
Interest expense	(338)		(314)		(1,026)		(914)
(Provision) benefit for income taxes	(227)		(176)		(549)		(635)
Income (loss) from discontinued operations	—		(1)		—		(88)
Net income (loss)	$	741	$	684	$	1,829	$	2,135

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Notes (Continued)

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, 2024
Segment revenues:
Service revenues
External	$	1,049	$	473	$	385	$	—	$	4	$	—	$	1,911
Internal	23		2		41		—		—		(66)		—
Total service revenues	1,072		475		426		—		4		(66)		1,911
Total service revenues – commodity consideration	14		1		19		—		—		—		34
Product sales
External	30		8		47		585		33		—		703
Internal	54		18		171		(104)		62		(201)		—
Total product sales	84		26		218		481		95		(201)		703
Net gain (loss) from commodity derivatives
Realized	—		—		—		(8)		1		—		(7)
Unrealized	—		—		—		9		3		—		12
Total net gain (loss) from commodity derivatives (2)	—		—		—		1		4		—		5
Total revenues	$	1,170	$	502	$	663	$	482	$	103	$	(267)	$	2,653





Three Months Ended September 30, 2023
Segment revenues:
Service revenues
External	$	953	$	473	$	340	$	—	$	4	$	—	$	1,770
Internal	25		5		34		—		—		(64)		—
Total service revenues	978		478		374		—		4		(64)		1,770
Total service revenues – commodity consideration	11		—		34		—		—		—		45
Product sales
External	35		13		14		619		39		—		720
Internal	28		14		98		(63)		79		(156)		—
Total product sales	63		27		112		556		118		(156)		720
Net gain (loss) from commodity derivatives
Realized	1		—		13		(31)		9		—		(8)
Unrealized	—		—		—		33		(1)		—		32
Total net gain (loss) from commodity derivatives (2)	1		—		13		2		8		—		24
Total revenues	$	1,053	$	505	$	533	$	558	$	130	$	(220)	$	2,559

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Notes (Continued)


	Transmission & Gulf of Mexico		Northeast G&P		West		Gas & NGL Marketing Services (1)		Other		Eliminations		Total
	(Millions)
Nine Months Ended September 30, 2024
Segment revenues:
Service revenues
External	$	3,077	$	1,410	$	1,154	$	—	$	12	$	—	$	5,653
Internal	67		9		116		—		—		(192)		—
Total service revenues	3,144		1,419		1,270		—		12		(192)		5,653
Total service revenues – commodity consideration	28		1		53		—		—		—		82
Product sales
External	85		15		153		1,800		105		—		2,158
Internal	100		59		504		(309)		184		(538)		—
Total product sales	185		74		657		1,491		289		(538)		2,158
Net gain (loss) from commodity derivatives
Realized	—		—		5		40		29		—		74
Unrealized	—		—		—		(188)		(19)		—		(207)
Total net gain (loss) from commodity derivatives (2)	—		—		5		(148)		10		—		(133)
Total revenues	$	3,357	$	1,494	$	1,985	$	1,343	$	311	$	(730)	$	7,760





Nine Months Ended September 30, 2023
Segment revenues:
Service revenues
External	$	2,801	$	1,396	$	1,002	$	1	$	12	$	—	$	5,212
Internal	73		25		86		—		—		(184)		—
Total service revenues	2,874		1,421		1,088		1		12		(184)		5,212
Total service revenues – commodity consideration	29		3		76		—		—		—		108
Product sales
External	116		32		43		1,882		85		—		2,158
Internal	81		72		244		(224)		218		(391)		—
Total product sales	197		104		287		1,658		303		(391)		2,158
Net gain (loss) from commodity derivatives
Realized	2		—		85		41		41		—		169
Unrealized	—		—		—		494		(18)		—		476
Total net gain (loss) from commodity derivatives (2)	2		—		85		535		23		—		645
Total revenues	$	3,102	$	1,528	$	1,536	$	2,194	$	338	$	(575)	$	8,123

______________

(1) As we are acting as agent for natural gas marketing customers or engage in energy trading activities, the resulting revenues are presented net of the related costs of those activities.

(2) We record transactions that qualify as commodity 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 from commodity derivatives held for energy trading purposes are presented on a net basis in revenue.

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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 business activities:

•Transmission & Gulf of Mexico is comprised of our interstate natural gas pipelines, Transco, Northwest Pipeline, and MountainWest, and their related natural gas storage facilities, 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 50 percent equity-method investment in Gulfstream, and Discovery, a former 60 percent equity-method investment in which we acquired the remaining ownership interest in August 2024 (see Note 3 – Acquisitions and Divestitures). Transmission & Gulf of Mexico also includes natural gas storage facilities and pipelines providing services in north Texas, and also in Louisiana and Mississippi related to the January 2024 Gulf Coast Storage Acquisition (see Note 3 – Acquisitions and Divestitures).

•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 Northeast JV which operates in West Virginia, Ohio, and Pennsylvania, a 66 percent interest in Cardinal 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.

•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, the Mid-Continent region which includes the Anadarko and Permian basins, and the DJ Basin of Colorado which includes RMM, a former 50 percent equity-method investment in which we acquired the remaining ownership interest in November 2023 (see Note 3 – Acquisitions and Divestitures). This segment also includes our NGL storage facilities, an undivided 50 percent interest in an NGL fractionator near Conway, Kansas, and a 50 percent equity-method investment in OPPL.

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Management’s Discussion and Analysis (Continued)

•Gas & NGL Marketing Services is comprised of our NGL and natural gas marketing and trading operations, which includes risk management and transactions related to the storage and transportation of natural gas and NGLs on strategically positioned assets.

Unless indicated otherwise, the following discussion and analysis of results of operations and financial condition and liquidity relates to our current continuing operations and should be read in conjunction with the consolidated financial statements and notes thereto of this Form 10-Q and our Annual Report on Form 10-K for the year ended December 31, 2023 dated February 21, 2024.

Dividends

In September 2024, we paid a regular quarterly dividend of $0.4750 per share.

Overview of Nine Months Ended September 30, 2024

Net income (loss) attributable to The Williams Companies, Inc. for the nine months ended September 30, 2024, decreased $302 million compared to the nine months ended September 30, 2023. Further discussion of our results is found in this report in the Results of Operations.

Recent Developments

Transco FERC Rate Case Filing

On August 30, 2024, Transco filed a general rate case with the FERC for an overall increase in rates. In September 2024, with the exception of certain rates that reflected a rate decrease, the FERC accepted and suspended our general rate filing to be effective March 1, 2025, subject to refund and the outcome of hearing procedures established by the FERC. The specific rates that reflected a rate decrease were accepted, without suspension, to be effective October 1, 2024, as requested by Transco, and will not be subject to refund. The impact of the rates reflecting a rate decrease is expected to reduce revenues by approximately $1 million per month beginning October 1, 2024.

Expansion Project Updates

Transmission & Gulf of Mexico

Regional Energy Access

In January 2023, we received approval from 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 placed approximately half of the project into service in the fourth quarter of 2023 and placed the remainder of the project into service in August 2024. The project increased capacity by 829 Mdth/d.

On July 30, 2024, the D.C. Circuit Court of Appeals granted petitions for review of the FERC orders approving the project, vacating such orders and remanding the matter to the FERC for appropriate action. The court’s decision will not be effective until the court has issued its mandate, which is not expected to occur until November 2024 at the earliest. To enable us to continue operating the project facilities and capacity until the FERC issues an order on remand from the court’s decision, on September 6, 2024, we filed an application with the FERC for a temporary certificate.

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Management’s Discussion and Analysis (Continued)

Acquisitions and Divestitures

Discovery Acquisition

As of December 31, 2023, we owned a 60 percent interest in Discovery, which we accounted for as an equity-method investment. On August 1, 2024, we closed on the acquisition of the remaining 40 percent interest in Discovery, along with certain other assets, for $170 million cash, subject to working capital and post-closing adjustments. As a result of acquiring this additional interest, we obtained control and now consolidate Discovery. We recognized a $127 million gain on remeasuring our existing equity-method investment to fair value included in Other investing income (loss) – net in our Consolidated Statement of Income in the third quarter of 2024. The purpose of this acquisition was to expand our gathering, processing, and transportation presence in the Gulf of Mexico region. Discovery continues to be reported within our Transmission & Gulf of Mexico segment (see Note 3 – Acquisitions and Divestitures).

Sale of Aux Sable Interest

Also on August 1, 2024, we completed the sale of our equity-method investments in Aux Sable in our Northeast G&P segment for total consideration of $161 million. As a result of this sale, we recorded a gain of $149 million included in Other investing income (loss) – net in our Consolidated Statement of Income in the third quarter of 2024 (see Note 3 – Acquisitions and Divestitures).

Gulf Coast Storage Acquisition

On January 3, 2024, we closed on the acquisition of 100 percent of a strategic portfolio of natural gas storage facilities and pipelines, located in Louisiana and Mississippi, from Hartree Partners LP for $1.95 billion. The purpose of this acquisition, which is reported in the Transmission & Gulf of Mexico segment, was to expand our natural gas storage footprint in the Gulf Coast region. The Gulf Coast Storage Acquisition was funded with cash on hand and $100 million of deferred consideration (see Note 3 – Acquisitions and Divestitures).

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 2024 includes a continued focus on earnings and cash flow growth.

In 2024, our operating results are expected to benefit from the recent Gulf Coast Storage and DJ Basin acquisitions. We also anticipate increases resulting from Transmission & Gulf of Mexico expansion projects, including the Regional Energy Access project, and annual inflation-based rate increases across our gathering and processing business. These increases are partially offset by lower expected Gas & NGL Marketing Services results, the absence of realized hedge gains captured in 2023 in the West, and a decrease in expected volumes primarily in the Appalachian and Haynesville basins associated with a lower expected commodity price environment.

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 2024 are expected to range from $1.45 billion to $1.75 billion, excluding acquisitions. Growth capital spending in 2024 primarily includes Transco expansions, all of which are fully contracted with firm transportation agreements, projects supporting growth in the Haynesville Basin,

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Management’s Discussion and Analysis (Continued)

and projects supporting the Northeast G&P business. We also expect to invest capital in our Other business ventures. 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 reduce emissions, and meet legal, regulatory, and/or contractual commitments.

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

•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 increases from inflation or 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;

•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, 2023, as filed with the SEC on February 21, 2024, as may be supplemented by disclosure 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

Deepwater Shenandoah Project

In June 2021, we reached an agreement with two third-parties to provide offshore natural gas gathering and transportation services as well as onshore natural gas processing services. The project expands our existing Gulf of Mexico offshore infrastructure via a 5-mile offshore lateral pipeline from the Shenandoah platform to Discovery’s existing Keathley Canyon Connector pipeline, adds onshore processing facilities at Larose, Louisiana to handle the expected rich Shenandoah production, and the natural gas liquids will be fractionated and marketed at Discovery’s Paradis plant in Louisiana. We plan to place the project into service in the second quarter of 2025.

Deepwater Whale Project

In August 2021, we reached an agreement with two third-parties to provide offshore natural gas gathering and crude oil transportation services as well as onshore natural gas processing services. The project expands our existing Western Gulf of Mexico offshore infrastructure via a 26-mile gas lateral pipeline from the Whale platform to the existing Perdido gas pipeline and adds a new 125-mile oil pipeline from the Whale platform to our existing junction platform. We plan to place the project into service in the fourth quarter of 2024.

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Management’s Discussion and Analysis (Continued)

Southside Reliability Enhancement

In July 2023, we received approval from 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 Virginia and North Carolina to delivery points in North Carolina. We placed a portion of the project into service in November 2024. We plan to place the remainder of the project into service by year-end 2024, 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 January 2024, we received approval from the FERC for the project, which involves an expansion of Transco’s existing natural gas transmission system to provide 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 first 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 November 2023, we received approval from 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 Mississippi and Alabama to a delivery point in Alabama. We plan to place the project into service in the second 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 November 2023, we received approval from 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.

Alabama Georgia Connector

In March 2024, we received approval from the FERC for the project, which involves an expansion of Transco’s existing natural gas transmission system to provide incremental firm transportation capacity from our Station 85 pooling point in Alabama to customers in Georgia. 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 64 Mdth/d.

Southeast Supply Enhancement

In October 2024, we filed a certificate 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 Virginia to delivery points in Virginia, North Carolina, South Carolina, Georgia, and Alabama. We plan to place the project into service as early as the fourth quarter of 2027, assuming timely receipt of all necessary regulatory approvals. The project is expected to increase capacity by 1,597 Mdth/d.

Gillis West

We plan to file our prior notice application for the project with the FERC in the first quarter of 2025, which involves an expansion of Transco’s existing natural gas transmission system to provide incremental firm transportation capacity from receipt points in Louisiana to delivery points in Texas. We plan to place the project

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Management’s Discussion and Analysis (Continued)

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 115 Mdth/d.

Overthrust Westbound Compression Expansion

In October 2024, we received approval from the FERC for the project, which involves an expansion of MountainWest’s existing natural gas transmission system to provide incremental firm transportation capacity from multiple receipt points in Wamsutter, Wyoming to a delivery point in Opal, Wyoming. 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 325 Mdth/d.

West

Louisiana Energy Gateway

In August 2024, we began construction activities on 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 the second half of 2025.

Haynesville Gathering Expansion

In February 2023, we announced our agreement with a third party to facilitate natural gas production growth in the Haynesville basin. We plan to construct a greenfield gathering system in support of the third party’s 26,000-acre dedication. The system, once constructed, will provide natural gas gathering services to the third party. The third party has also agreed to a long-term capacity commitment on our Louisiana Energy Gateway project. This project is expected to go into service in third quarter 2025.

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Management’s Discussion and Analysis (Continued)

Results of Operations

Consolidated Overview

The following table and discussion is a summary of our consolidated results of operations for the three and nine months ended September 30, 2024, compared to the three and nine months ended September 30, 2023, and should be read in conjunction with the results of operations by segment, as discussed in further detail following this consolidated overview discussion.



	Three Months Ended September 30,				Change*			Nine Months Ended September 30,				Change*
	2024		2023		$	%		2024		2023		$	%
	(Dollars in millions)							(Dollars in millions)
Revenues:
Service revenues	$	1,911	$	1,770	+141	+8	%	$	5,653	$	5,212	+441	+8	%

Product sales and service revenues – commodity consideration	737		765		-28	-4	%	2,240		2,266		-26	-1	%
Net gain (loss) from commodity derivatives	5		24		-19	-79	%	(133)		645		-778	NM
Total revenues	2,653		2,559					7,760		8,123
Costs and expenses:
Product costs and net processing commodity expenses	524		515		-9	-2	%	1,496		1,587		+91	+6	%

Operating and maintenance expenses	580		522		-58	-11	%	1,613		1,466		-147	-10	%
Depreciation and amortization expenses	566		521		-45	-9	%	1,654		1,542		-112	-7	%
Selling, general, and administrative expenses	170		146		-24	-16	%	520		483		-37	-8	%


Gain on sale of business	—		(130)		-130	-100	%	—		(130)		-130	-100	%

Other (income) expense – net	(25)		(9)		+16	+178	%	(69)		(49)		+20	+41	%
Total costs and expenses	1,815		1,565					5,214		4,899
Operating income (loss)	838		994					2,546		3,224
Equity earnings (losses)	147		127		+20	+16	%	431		434		-3	-1	%

Other investing income (loss) – net	290		24		+266	NM		332		45		+287	NM
Interest expense	(338)		(314)		-24	-8	%	(1,026)		(914)		-112	-12	%

Other income (expense) – net	31		30		+1	+3	%	95		69		+26	+38	%
Income (loss) before income taxes	968		861					2,378		2,858
Less: Provision (benefit) for income taxes	227		176		-51	-29	%	549		635		+86	+14	%
Income (loss) from continuing operations	741		685					1,829		2,223
Income (loss) from discontinued operations	—		(1)		+1	+100	%	—		(88)		+88	+100	%
Net income (loss)	741		684					1,829		2,135
Less: Net income attributable to noncontrolling interests	35		30		-5	-17	%	90		94		+4	+4	%
Net income (loss) attributable to The Williams Companies, Inc.	$	706	$	654	+52	+8	%	$	1,739	$	2,041	-302	-15	%

_______

* + = 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)

Three months ended September 30, 2024 vs. three months ended September 30, 2023

Service revenues increased primarily due to higher volumes from the November 2023 DJ Basin Acquisitions at our West segment and the January 2024 Gulf Coast Storage and the August 2024 Discovery Acquisitions at our Transmission & Gulf of Mexico segment (see Note 3 – Acquisitions and Divestitures), and higher revenues associated with an expansion project at our Transmission & Gulf of Mexico segment; partially offset by lower gathering volumes at our West and Northeast G&P segments.

The net sum of Product sales and service revenues – commodity consideration, Product costs and net processing commodity expenses, and net realized gains and losses on commodity derivatives related to sales of product and shrink gas purchases for our processing plants for our reportable segments comprise our Commodity Margins. Service revenues - commodity consideration represent payments we receive in the form of commodities for processing services provided. Most of these commodity volumes are sold during the month processed and are offset within Product costs and net processing commodity expenses. The sum of Product sales and net realized gains and losses on commodity derivatives related to our upstream operations comprise Net realized product sales.

The Product sales and service revenues – commodity consideration decrease primarily consists of:

•Lower product sales from our upstream operations at Other;

•Lower equity NGL sales and commodity consideration revenues associated with our NGL production activity primarily at our West segment;

•Lower system management gas sales primarily at our Transmission & Gulf of Mexico segment; partially offset by

•Higher marketing sales activities primarily at our West segment; partially offset by lower marketing activities related to NGLs at our Gas & NGL Marketing Services segment.

As we are acting as agent for natural gas marketing customers, our natural gas marketing product sales are presented net of the related costs of those activities within our Gas & NGL Marketing Services segment.

Net gain (loss) from commodity derivatives includes realized and unrealized gains and losses from derivative instruments reflected within Total revenues primarily in our Gas & NGL Marketing Services and West segments, and at Other (see Note 8 – Commodity Derivatives).

We 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 capacity portfolios 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 transportation and storage capacity contracts, which are not recognized until the underlying transaction occurs.

The Product costs and net processing commodity expenses increase primarily consists of:

•Higher marketing activities primarily at our West segment; partially offset by lower marketing activities primarily related to NGLs at our Gas & NGL Marketing Services segment; partially offset by

•Lower shrink natural gas purchases and commodity consideration costs associated with our equity NGL production activities primarily at our West segment;

•Lower system management gas purchases primarily at our Transmission & Gulf of Mexico segment.

Operating and maintenance expenses increased primarily due to employee-related costs, including the impact of a change in a payroll policy; and operating costs of the assets acquired at our West and Transmission & Gulf of Mexico segments.

Table of Contents

Management’s Discussion and Analysis (Continued)

Depreciation and amortization expenses increased primarily related to assets acquired at our West and Transmission & Gulf of Mexico segments.

Selling, general, and administrative expenses increased primarily due to employee-related costs, including the impact of a change in a payroll policy.

Gain on sale of business reflects a gain from the sale of certain liquids pipelines in our Transmission & Gulf of Mexico segment in 2023 (see Note 3 – Acquisitions and Divestitures).

Other (income) expense – net within Operating income (loss) includes lower project feasibility costs at our Transmission & Gulf of Mexico segment.

Equity earnings (losses) changed favorably primarily due to the absence of our share of a loss contingency accrual in 2023 at Aux Sable, partially offset by the impacts of the sale of our interests in Aux Sable and the consolidations of RMM and Discovery following our acquisitions of the remaining ownership interests (see Note 3 – Acquisitions and Divestitures).

Other investing income (loss) – net includes a $149 million gain on the sale of our interests in Aux Sable and a $127 million gain on remeasurement of our existing equity-method investment associated with the purchase of the remaining interest in Discovery.

The increase in Interest expense was primarily due to our 2023 and 2024 debt issuances, and imputed interest on deferred consideration obligations related to our DJ Basin and Gulf Coast Storage Acquisitions, partially offset by 2023 and 2024 debt retirements (see Note 6 – Debt and Banking Arrangements).

Provision (benefit) for income taxes changed unfavorably primarily due to higher pre-tax income and the absence of a benefit associated with decreases in our estimate of the state deferred income tax rate in 2023. See Note 5 – Provision (Benefit) for Income Taxes for a discussion of the effective tax rate compared to the federal statutory rate for both periods.

Nine months ended September 30, 2024 vs. nine months ended September 30, 2023

Service revenues increased primarily due to higher volumes from the November 2023 DJ Basin Acquisitions at our West segment and the January 2024 Gulf Coast Storage, February 2023 MountainWest and August 2024 Discovery Acquisitions at our Transmission & Gulf of Mexico segment, and higher revenues associated with an expansion project at our Transmission & Gulf of Mexico segment, partially offset by lower gathering volumes at our West and Northeast G&P segments and the September 2023 sale of certain liquids pipelines at our Transmission & Gulf of Mexico segment.

The Product sales and service revenues – commodity consideration decrease primarily consists of:

•Lower system management gas sales primarily at our Transmission & Gulf of Mexico segment;

•Lower equity NGL sales and commodity consideration revenues associated with our NGL production activity primarily at our West segment;

•Lower product sales from upstream operations at Other; partially offset by

•Higher marketing sales activities primarily at our West segment; partially offset by lower marketing sales activities primarily related to NGLs at our Gas & NGL Marketing Services segment. Net natural gas marketing sales were impacted by lower net prices, higher storage costs, and a favorable change in lower of cost or net realizable inventory adjustments.

Table of Contents

Management’s Discussion and Analysis (Continued)

The Product costs and net processing commodity expenses decrease primarily consists of:

•Lower shrink natural gas purchases and commodity consideration costs associated with our equity NGL production activities primarily at our West segment;

•Lower system management gas purchases primarily at our Transmission & Gulf of Mexico segment; partially offset by

•Higher marketing activities primarily at our West segment; partially offset by lower marketing activities primarily related to NGLs at our Gas & NGL Marketing Services segment.

Operating and maintenance expenses increased primarily due to operating costs of the assets acquired at our West and Transmission & Gulf of Mexico segments; as well as unfavorable changes in employee-related costs, including the impact of a change in a payroll policy; and our net imbalance liability due to changes in pricing.

Depreciation and amortization expenses increased primarily related to the assets acquired at our West and Transmission & Gulf of Mexico segments. The increase is partially offset by lower amortization of intangibles related to our 2021 Sequent Acquisition.

Selling, general, and administrative expenses increased primarily due to employee-related costs, including the impact of a change in a payroll policy.

Gain on sale of business reflects a gain from the sale of certain liquids pipelines in our Transmission & Gulf of Mexico segment in 2023, as previously discussed.

Other (income) expense – net within Operating income (loss) includes lower project feasibility costs at our Transmission & Gulf of Mexico segment.

Equity earnings (losses) changed unfavorably primarily due to the impacts of the consolidation of RMM and Discovery and the sale of our interests in Aux Sable, partially offset by the absence of our share of a loss contingency accrual in 2023 at Aux Sable, as previously discussed, and favorable results at OPPL.

Other investing income (loss) – net includes gains on the sale of our interests in Aux Sable and associated with the purchase of the remaining interest in Discovery, as previously discussed.

The favorable change in Other income (expense) – net below Operating income (loss) includes an increase in equity allowance for funds used during construction (equity AFUDC) at our Transmission & Gulf of Mexico segment.

Provision (benefit) for income taxes changed favorably primarily due to lower pre-tax income.

Income (loss) from discontinued operations in 2023 includes a pre-tax charge of $116 million to increase the accrued liability associated with our Alaska refinery contamination litigation, partially offset by the related income tax effect.

Table of Contents

Management’s Discussion and Analysis (Continued)

Period-Over-Period Operating Results – Segments

We evaluate segment operating performance based upon Modified EBITDA. Note 10 – Segment Disclosures 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,
	2024		2023		2024		2023
	(Millions)
Service revenues	$	1,072	$	978	$	3,144	$	2,874


Product sales and service revenues – commodity consideration (1)	98		74		213		226


Net realized gain (loss) from commodity derivatives (1)	—		1		—		2



Segment revenues	1,170		1,053		3,357		3,102



Product costs and net processing commodity expenses (1)	(87)		(68)		(188)		(203)
Other segment costs and expenses	(313)		(286)		(857)		(855)



Gain on sale of business	—		130		—		130
Proportional Modified EBITDA of equity-method investments	41		52		136		153
Transmission & Gulf of Mexico Modified EBITDA	$	811	$	881	$	2,448	$	2,327

Commodity margins	$	11	$	7	$	25	$	25

_______________

(1)Included as a component of Commodity margins.

Three months ended September 30, 2024 vs. three months ended September 30, 2023

Transmission & Gulf of Mexico Modified EBITDA decreased primarily due to the absence of a Gain on sale of business and higher Other segment costs and expenses, partially offset by higher Service revenues.

Service revenues increased primarily due to:

•A $57 million increase due to the acquisition of Gulf Coast Storage assets in January 2024 primarily in storage revenues (see Note 3 – Acquisitions and Divestitures);

•A $36 million increase in Transco’s revenues associated with the Regional Energy Access expansion project placed partially in-service in the fourth quarter of 2023 and full in-service in August 2024;

•A $13 million increase primarily in gathering and transportation revenues at Discovery due to the acquisition in August 2024 (see Note 3 – Acquisitions and Divestitures); partially offset by

•A $14 million decrease due to the sale of certain liquids pipelines in the Gulf Coast region in September 2023 primarily in transportation revenues (see Note 3 – Acquisitions and Divestitures);

•A $6 million decrease in the Eastern Gulf region primarily due to weather-related events and ongoing producer operational issues at Gulfstar One in the Gunflint field, partially offset by higher primarily production handling volumes from a new well at Gulfstar One in the Pickerel field.

Table of Contents

Management’s Discussion and Analysis (Continued)

Other segment costs and expenses increased primarily due to:

•Higher operating expenses and administrative costs including higher operating costs related to our Gulf Coast Storage and Discovery Acquisitions and higher employee-related costs, including the impact of a change in a payroll policy; partially offset by lower operating costs related to the sale of certain liquids pipelines in the Gulf Coast region; partially offset by

•Lower project feasibility costs.

Gain on sale of business reflects a gain recognized on the sale of certain liquids pipelines in the Gulf Coast region in September 2023 (see Note 3 – Acquisitions and Divestitures).

Proportional Modified EBITDA of equity-method investments decreased due to lower proportional results as Discovery was consolidated following our acquisition of the remaining ownership interest in August 2024.

Nine months ended September 30, 2024 vs. nine months ended September 30, 2023

Transmission & Gulf of Mexico Modified EBITDA increased primarily due to higher Service revenues, partially offset by the absence of a Gain on sale of business.

Service revenues increased primarily due to:

•A $165 million increase due to the acquisition of Gulf Coast Storage assets primarily in storage revenues;

•A $76 million increase in Transco’s revenues associated with the Regional Energy Access expansion project;

•A $37 million increase in primarily transportation and storage revenues at MountainWest primarily due to the acquisition in February 2023 (see Note 3 – Acquisitions and Divestitures);

•A $16 million increase in NorTex’s revenues primarily associated with higher storage rates;

•A $13 million increase primarily in gathering and transportation revenues at Discovery due to the acquisition; partially offset by

•A $39 million decrease due to the sale of certain liquids pipelines in the Gulf Coast region primarily in transportation revenues;

•A $19 million decrease in the Eastern Gulf region primarily due to shut-ins for weather-related events and producer operational issues at Gulfstar One in the Gunflint and Tubular Bells fields, partially offset by higher primarily production handling volumes from a new well at Gulfstar One in the Pickerel field.

Other segment costs and expenses increased primarily due to:

•Higher operating expenses and administrative costs including higher operating, acquisition and transition costs related to our Gulf Coast Storage, Discovery, and MountainWest Acquisitions; higher employee-related costs, including the impact of a change in a payroll policy; partially offset by significantly lower acquisition and transition costs related to our MountainWest Acquisition and lower operating costs related to the sale of certain liquids pipelines in the Gulf Coast region; partially offset by

•Lower project feasibility costs;

•A favorable change in equity AFUDC primarily as a result of increased capital expenditures at Transco;

•A favorable change in the deferral of ARO-related depreciation at Transco.

Table of Contents

Management’s Discussion and Analysis (Continued)

Gain on sale of business reflects a gain recognized on the sale of certain liquids pipelines in the Gulf Coast region in 2023, as previously discussed.

Proportional Modified EBITDA of equity-method investments decreased due to lower proportional results as Discovery was consolidated, as previously discussed.

Northeast G&P



	Three Months Ended September 30,				Nine Months Ended September 30,
	2024		2023		2024		2023
	(Millions)
Service revenues	$	475	$	478	$	1,419	$	1,421
Product sales and service revenues – commodity consideration (1)	27		27		75		107
Segment revenues	502		505		1,494		1,528

Product costs and net processing commodity expenses (1)	(19)		(20)		(56)		(96)
Other segment costs and expenses	(156)		(150)		(436)		(414)

Proportional Modified EBITDA of equity-method investments	149		119		459		421
Northeast G&P Modified EBITDA	$	476	$	454	$	1,461	$	1,439

Commodity margins	$	8	$	7	$	19	$	11

(1)Included as a component of Commodity margins.

Three months ended September 30, 2024 vs. three months ended September 30, 2023

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

Service revenues decreased primarily due to:

•A $20 million decrease in gathering revenues at Susquehanna Supply Hub primarily related to lower volumes partially offset by escalated rates; partially offset by

•An $11 million increase in revenues at the Northeast JV primarily related to higher gathering and processing volumes and rates.

Other segment costs and expenses increased primarily due to higher employee-related costs, including the impact of a change in a payroll policy.

Proportional Modified EBITDA of equity-method investments increased at Aux Sable Liquid Products LP primarily due to the absence of our $31 million share of a loss contingency accrual related to our 14 percent ownership in the third quarter of 2023, partially offset by the sale of our investment in Aux Sable Liquid Products LP in the third quarter of 2024. Additionally, Appalachia Midstream Investments increased primarily driven by higher gathering rates partially offset by lower volumes and higher expenses.

Nine months ended September 30, 2024 vs. nine months ended September 30, 2023

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

Table of Contents

Management’s Discussion and Analysis (Continued)

Service revenues decreased primarily due to:

•A $15 million decrease in gathering revenues in the Utica Shale region primarily related to lower volumes at Flint and Cardinal partially offset by escalated rates;

•A $9 million decrease in gathering revenues at Susquehanna Supply Hub primarily related to lower volumes partially offset by escalated rates; partially offset by

•A $12 million increase in joint venture operating fees primarily related to assuming operatorship of Blue Racer effective January 1, 2024 (which is significantly offset by higher Other segment costs and expenses discussed below).

Other segment costs and expenses increased primarily due to higher employee-related costs, including the impact of a change in a payroll policy, as well as increased support costs related to assuming operatorship of Blue Racer effective January 1, 2024 (substantially offset by higher Service revenues discussed above).

Proportional Modified EBITDA of equity-method investments increased at Aux Sable Liquid Products LP primarily due to the absence of our $31 million share of a loss contingency accrual related to our 14 percent ownership in the third quarter of 2023, as well as the terms of the new product marketing agreement, partially offset by the sale of our investment in Aux Sable Liquid Products LP in the third quarter of 2024. Additionally, Appalachia Midstream Investments increased primarily driven by higher gathering rates partially offset by lower volumes at the Bradford Supply Hub and higher expenses.

West



	Three Months Ended September 30,				Nine Months Ended September 30,
	2024		2023		2024		2023
	(Millions)
Service revenues	$	426	$	374	$	1,270	$	1,088
Product sales and service revenues – commodity consideration (1)	237		146		710		363

Net realized gain (loss) from commodity derivatives relating to service revenues	—		12		10		80
Net realized gain (loss) from commodity derivatives relating to product sales (1)	—		1		(5)		5
Net realized gain (loss) from commodity derivatives	—		13		5		85

Segment revenues	663		533		1,985		1,536

Product costs and net processing commodity expenses (1)	(210)		(126)		(636)		(353)
Other segment costs and expenses	(165)		(137)		(477)		(373)


Proportional Modified EBITDA of equity-method investments	35		45		96		121
West Modified EBITDA	$	323	$	315	$	968	$	931

Commodity margins	$	27	$	21	$	69	$	15

________________

(1) Included as a component of Commodity margins.

Table of Contents

Management’s Discussion and Analysis (Continued)

Three months ended September 30, 2024 vs. three months ended September 30, 2023

West Modified EBITDA increased primarily due to higher Service revenues and Commodity margins, partially offset by higher Other segment costs and expenses, an unfavorable change in Net realized gain (loss) from commodity derivatives relating to service revenues, and lower Proportional Modified EBITDA of equity-method investments.

Service revenues increased primarily due to:

•A $76 million increase in the DJ Basin region associated with the DJ Basin Acquisitions in November 2023 (see Note 3 – Acquisitions and Divestitures);

•A $7 million increase in our other NGL operations primarily associated with higher transportation revenue due to higher volumes; partially offset by

•A $16 million decrease in the Haynesville Shale region primarily associated with lower gathering volumes from decreased producer activity;

•An $8 million decrease in the Barnett Shale region primarily due to lower gathering volumes as well as lower gathering rates driven by unfavorable commodity pricing;

•A $7 million decrease in the Eagle Ford Shale region primarily due to lower MVC revenues.

Net realized gain (loss) from commodity derivatives relating to service revenues is unfavorable due to the absence of realized hedge positions in third-quarter 2024.

Commodity margins increased $6 million primarily driven by higher marketing margins associated with the DJ Basin Acquisitions.

Other segment costs and expenses increased primarily due to higher operating expenses including those resulting from the DJ Basin Acquisitions and the impact of a change in a payroll policy.

Proportional Modified EBITDA of equity-method investments decreased primarily due to lower proportional results as RMM was consolidated following our acquisition of the remaining ownership interest on November 30, 2023, partially offset by higher volumes at OPPL.

Nine months ended September 30, 2024 vs. nine months ended September 30, 2023

West Modified EBITDA increased primarily due higher Service revenues and Commodity margins, partially offset by higher Other segment costs and expenses, an unfavorable change in Net realized gain (loss) from commodity derivatives relating to service revenues, and lower Proportional Modified EBITDA of equity-method investments.

Service revenues increased primarily due to:

•A $216 million increase in the DJ Basin region associated with the DJ Basin Acquisitions in November 2023, as previously discussed;

•A $27 million increase in our other NGL operations associated with higher transportation and fractionation revenue due to higher volumes and higher storage fees primarily due to a new contract;

•A $17 million increase in the Wamsutter region primarily associated with higher gathering volumes from increased producer activity as well as higher volumes associated with the absence of weather-related events in first-quarter 2023; partially offset by

•A $32 million decrease in the Haynesville Shale region primarily due to lower gathering volumes from decreased producer activity, partially offset by higher gathering rates;

Table of Contents

Management’s Discussion and Analysis (Continued)

•A $25 million decrease in the Eagle Ford Shale region primarily due to lower MVC revenues as well as lower gathering volumes;

•A $22 million decrease in the Barnett Shale region primarily due to lower gathering rates driven by unfavorable commodity pricing and lower gathering volumes.

Net realized gain (loss) from commodity derivatives relating to service revenues reflects an unfavorable change in settled commodity prices relative to our natural gas hedge positions.

Commodity margins increased $54 million primarily due to $30 million higher margins associated with the DJ Basin Acquisitions. Margins also increased $19 million from our equity NGLs due to lower net realized prices for natural gas purchases and lower volumes of natural gas purchased both associated with our equity NGL production activities; partially offset by lower volumes of equity NGL sold and lower net realized NGL sales prices.

Other segment costs and expenses increased primarily due to higher operating and employee-related expenses including those resulting from the DJ Basin Acquisitions, the impact of a change in a payroll policy, the absence of favorable contract settlements in first-quarter 2023, and an unfavorable change in our net imbalance liability due to changes in pricing.

Proportional Modified EBITDA of equity-method investments decreased primarily due to lower proportional results as RMM was consolidated on November 30, 2023 as previously discussed, partially offset by higher volumes at OPPL.

Gas & NGL Marketing Services



	Three Months Ended September 30,				Nine Months Ended September 30,
	2024		2023		2024		2023
	(Millions)
Service revenues	$	—	$	—	$	—	$	1
Product sales (1)	481		556		1,491		1,658

Net realized gain (loss) from commodity derivative instruments (1)	(8)		(31)		40		41
Net unrealized gain (loss) from commodity derivative instruments	9		33		(188)		494
Net gain (loss) from commodity derivatives	1		2		(148)		535

Segment revenues	482		558		1,343		2,194
Net unrealized gain (loss) from commodity derivative instruments within Net processing commodity expenses	1		(9)		(3)		(43)
Product costs (1)	(450)		(487)		(1,269)		(1,398)
Other segment costs and expenses	(22)		(19)		(85)		(75)
Gas & NGL Marketing Services Modified EBITDA	$	11	$	43	$	(14)	$	678

Commodity margins	$	23	$	38	$	262	$	301

________________

(1) Included as a component of Commodity margins.

Three months ended September 30, 2024 vs. three months ended September 30, 2023

Gas & NGL Marketing Services Modified EBITDA decreased primarily due to an unfavorable change in Net unrealized gain (loss) from commodity derivative instruments and lower Commodity margins.

Table of Contents

Management’s Discussion and Analysis (Continued)

Commodity margins decreased $15 million primarily due to a $17 million decrease in our NGL marketing margins including an unfavorable change in net realized gains and losses on sale of inventory in 2024 compared to 2023 driven by unfavorable changes in non-ethane prices.

Net unrealized gain (loss) from commodity derivative instruments within Segment revenues and Net processing commodity expenses relates to derivative contracts that are not designated as hedges for accounting purposes. The change from 2023 is primarily due to a change in forward commodity prices relative to our hedge positions in 2024 compared to 2023.

Nine months ended September 30, 2024 vs. nine months ended September 30, 2023

Gas & NGL Marketing Services Modified EBITDA decreased primarily due to an unfavorable change in Net unrealized gain (loss) from commodity derivative instruments and lower Commodity margins.

Commodity margins decreased $39 million primarily due to:

•A $27 million decrease in our natural gas marketing margins including $19 million of lower natural gas storage marketing margins primarily driven by less favorable realized derivative gains and higher storage fees, partially offset by a favorable change of $13 million in lower cost or net realizable value inventory adjustment. The decrease in our natural gas marketing margins also includes $8 million of lower natural gas transportation capacity marketing margins due to less favorable net realized pricing spreads;

•A $12 million decrease in our NGL marketing margins including an unfavorable change in net realized gains and losses on sale of inventory in 2024 compared to 2023 driven by unfavorable changes in non-ethane prices.

The change in Net unrealized gain (loss) from commodity derivative instruments within Segment revenues and Net processing commodity expenses from 2023 is primarily due to a change in forward commodity prices relative to our hedge positions in 2024 compared to 2023.

Other



	Three Months Ended September 30,				Nine Months Ended September 30,
	2024		2023		2024		2023
	(Millions)
Service revenues	$	4	$	4	$	12	$	12
Product sales (1)	95		118		289		303

Net realized gain (loss) from derivative instruments (1)	1		9		29		41
Net unrealized gain (loss) from derivative instruments	3		(1)		(19)		(18)
Net gain (loss) from commodity derivatives	4		8		10		23

Segment revenues	103		130		311		338

Other segment costs and expenses	(47)		(48)		(132)		(140)

Proportional Modified EBITDA of equity-method investments	2		(1)		2		(2)
Modified EBITDA of other business activities	$	58	$	81	$	181	$	196

Net realized product sales	$	96	$	127	$	318	$	344

________________

(1) Included as a component of Net realized product sales.

Table of Contents

Management’s Discussion and Analysis (Continued)

Three months ended September 30, 2024 vs. three months ended September 30, 2023

Modified EBITDA of other business activities decreased primarily due to:

•A $31 million decrease in Net realized product sales from our upstream operations primarily due to lower net realized commodity prices and lower production volumes.

Nine months ended September 30, 2024 vs. nine months ended September 30, 2023

Modified EBITDA of other business activities decreased primarily due to:

•A $26 million decrease in Net realized product sales from our upstream operations primarily due to lower net realized commodity prices and lower volumes associated with our South Mansfield production in the Haynesville Shale region, partially offset by higher production volumes associated with our Wamsutter region production.

Table of Contents

Management’s Discussion and Analysis (Continued)

Management’s Discussion and Analysis of Financial Condition and Liquidity

Outlook

Our growth capital and investment expenditures in 2024 are expected to range from $1.45 billion to $1.75 billion, excluding acquisitions. Growth capital spending in 2024 primarily includes Transco expansions, all of which are fully contracted with firm transportation agreements, projects supporting growth in the Haynesville Basin, and projects supporting the Northeast G&P business. We also expect to invest capital in our Other business ventures. 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 reduce emissions, and meet legal, regulatory, and/or contractual commitments. We intend to fund substantially all planned 2024 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.

On November 1, 2024, we paid the remaining $651 million of the RMM purchase price obligation (see Note 3 – Acquisitions and Divestitures).

On August 1, 2024, we completed the Discovery Acquisition for $170 million. Also, on August 1, 2024, we completed the sale of certain equity-method investments for $161 million (see Note 3 – Acquisitions and Divestitures).

On January 3, 2024, we completed the Gulf Coast Storage Acquisition for $1.95 billion (see Note 3 – Acquisitions and Divestitures).

Our long-term debt activity during the first nine months of 2024 included issuing $3.6 billion of new debt and retiring $2.25 billion of existing debt (see Note 6 – Debt and Banking Arrangements).

As of September 30, 2024, we have approximately $2.284 billion of long-term debt due within one year. Our potential sources of liquidity available to address these maturities include cash on hand, proceeds from refinancing, our credit facility, or our commercial paper program, as well as proceeds from asset monetizations.

Liquidity

Based on our forecasted levels of cash flow from operations and other sources of liquidity, we expect to have sufficient liquidity to manage our businesses in 2024. 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
			Gas & NGL Marketing Services payments for transportation and storage capacity and gas supply
			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

Table of Contents

Management’s Discussion and Analysis (Continued)

As of September 30, 2024, we have approximately $24.8 billion of long-term debt due after one year. Our potential sources of liquidity available to address these maturities include cash generated from operations, proceeds from refinancing, 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, 2024, we had a working capital deficit of $2.021 billion, including cash and cash equivalents and long-term debt due within one year. Our available liquidity is as follows:


Available Liquidity	September 30, 2024
	(Millions)
Cash and cash equivalents	$	762
Capacity available under our $3.75 billion credit facility, less amounts outstanding under our $3.5 billion commercial paper program (1)	3,750
	$	4,512

__________

(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, 2024. Through September 30, 2024, the highest amount outstanding under our commercial paper program and credit facility during 2024 was $730 million. We expect to be in compliance with the financial covenants associated with our credit facility for the September 30, 2024, reporting period.

Dividends

We increased our regular quarterly cash dividend to common stockholders by approximately 6.1 percent from the $0.4475 per share paid in each quarter of 2023, to $0.4750 per share paid in the first three quarters of 2024.

Registrations

In February 2024, we filed a shelf registration statement as a well-known seasoned issuer.

Distributions from Equity-Method Investees

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

Credit Ratings

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

Rating Agency

Outlook

Senior Unsecured
Debt Rating

S&P Global Ratings

Positive

BBB

Moody’s Investors Service

Stable

Baa2

Fitch Ratings

Stable

BBB

In April 2024, S&P Global Ratings changed its Outlook from Stable to Positive.

Table of Contents

Management’s Discussion and Analysis (Continued)

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.

Sources (Uses) of Cash

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


	Cash Flow	Nine Months Ended September 30,
	Category	2024		2023
		(Millions)
Sources of cash and cash equivalents:
Net cash provided (used) by operating activities	Operating	$	3,756	$	4,125
Proceeds from long-term debt	Financing	3,594		2,754

Proceeds from sale of business (Note 3)	Investing	—		348

Proceeds from dispositions of equity-method investments (Note 3)	Investing	161		—


Uses of cash and cash equivalents:
Payments of long-term debt	Financing	(2,286)		(21)
Purchases of businesses, net of cash acquired (Note 3)	Investing	(1,995)		(1,024)
Common dividends paid	Financing	(1,737)		(1,635)
Capital expenditures	Investing	(1,805)		(1,845)

Dividends and distributions paid to noncontrolling interests	Financing	(178)		(174)
Proceeds from (payments of) commercial paper – net	Financing	(723)		(352)
Purchases of and contributions to equity-method investments	Investing	(101)		(80)
Purchases of treasury stock	Financing	—		(130)

Other sources / (uses) – net	Financing and Investing	(74)		(44)
Increase (decrease) in cash and cash equivalents		$	(1,388)	$	1,922

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, Net unrealized (gain) loss from commodity derivative instruments, Gain on sale of business, Gain on disposition of equity-method investments, Gain on consolidation of equity-method investments, Inventory write-downs, and Amortization of stock-based awards.

Our Net cash provided (used) by operating activities for the nine months ended September 30, 2024, decreased from the same period in 2023 primarily due to unfavorable changes in margin requirements and net operating working capital, partially offset by higher operating income (excluding non-cash items previously discussed).

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Item 3. Quantitative and Qualitative Disclosures About Market Risk

Interest Rate Risk

Our current interest rate risk exposure is related primarily to our debt portfolio. Our debt portfolio is primarily comprised of fixed rate debt, which mitigates the impact of fluctuations in interest rates. Any borrowings under our credit facility and any issuances under our commercial paper program could be at a variable interest rate and could expose us to the risk of increasing interest rates. The maturity of our long-term debt portfolio is partially influenced by the expected lives of our operating assets. We may utilize interest rate derivative instruments to hedge interest rate risk associated with future debt issuances (see Note 6 – Debt and Banking Arrangements).

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 and to lock in NGL margin on a portion of our commodity-exposed gathering and processing volumes. These economic hedges are not designated for hedge accounting treatment.

The maturities of our commodity derivative contracts at September 30, 2024, were as follows:


	Total Fair Value		Maturity
Fair Value Measurements of Assets (Liabilities) Using (1)			2024		2025 - 2026		2027 - 2028+
	(Millions)
Level 1 (2)	$	21	$	9	$	22	$	(10)
Level 2	(255)		(8)		(104)		(143)
Level 3	47		2		14		31
Fair value of contracts outstanding at September 30, 2024	$	(187)	$	3	$	(68)	$	(122)

_______________

(1)See Note 7 – Fair Value Measurements and Guarantees for discussion of valuation techniques by level within the fair value hierarchy. See Note 8 – Commodity Derivatives for the amount of change in fair value recognized in our Consolidated Statement of Income.

(2)Commodity derivative assets and liabilities exclude $76 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.

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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.

The VaR associated with our integrated natural gas trading operations was $4 million at September 30, 2024 and $9 million at December 31, 2023. We had the following VaRs for the period shown:


	Nine Months Ended September 30, 2024

	(Millions)
Average	$	3
High	$	15
Low	$	1

Our non-trading portfolio primarily consists of commodity derivatives that hedge our upstream business and certain gathering and processing contracts. The VaR associated with these commodity derivatives was $5 million at September 30, 2024 and $3 million at December 31, 2023. We had the following VaRs for the period shown:


	Nine Months Ended September 30, 2024

	(Millions)
Average	$	4
High	$	8
Low	$	3

Item 4. Controls and Procedures

Disclosure 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 Exchange Act) (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 errors or mistakes. 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.

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As disclosed in Note 3 – Acquisitions and Divestitures, we acquired Hartree as part of the Gulf Coast Storage Acquisition on January 3, 2024. Hartree’s total revenues constituted approximately 2 percent of total revenues as shown in our consolidated financial statements for the nine months ended September 30, 2024. Hartree’s total assets constituted approximately 4 percent of total assets as shown in our consolidated financial statements as of September 30, 2024. We also acquired Cureton on November 30, 2023, and its total revenues constituted approximately 3 percent of total revenues as shown in our consolidated financial statements for the nine months ended September 30, 2024. Cureton’s total assets constituted approximately 1 percent of total assets as shown in our consolidated financial statements as of September 30, 2024. We excluded Hartree’s and Cureton’s disclosure controls and procedures that are subsumed by their internal control over financial reporting from the scope of management’s assessment of the effectiveness of our disclosure controls and procedures. This exclusion is in accordance with the guidance issued by the Staff of the Securities and Exchange Commission that an assessment of recent business combinations may be omitted from management’s assessment of internal control over financial reporting for one year following the acquisition.

Changes in Internal Control Over Financial Reporting

There have been no changes during the third quarter of 2024 that have materially affected, or are reasonably likely to materially affect, our Internal Control over Financial Reporting.

PART II. OTHER INFORMATION

Item 1. Legal Proceedings

Environmental

Certain reportable legal proceedings involving governmental authorities under federal, state, and local laws regulating the discharge of materials into the environment are described below. While it is not possible for us to predict the final outcome of the proceedings that are still pending, we do not anticipate a material effect on our consolidated financial position if we receive an unfavorable outcome in any one or more of such proceedings. Our threshold for disclosing material environmental legal proceedings involving a governmental authority where potential monetary sanctions are involved is $1 million.

Other environmental matters called for by this Item are described under the caption “Environmental Matters” in Note 9 – Contingencies included under Part II, Item 8 Financial Statements of this report, which information is incorporated by reference into this Item.

Other litigation

The additional information called for by this Item is provided in Note 9 – Contingencies included under Part II, Item 8 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, 2023, as filed with the SEC on February 21, 2024, 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, Use of Proceeds, and Issuer Purchases of Equity Securities


ISSUER PURCHASES OF EQUITY SECURITIES
Period	Total Number of Shares Purchased	Average Price Paid Per Share		Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs(1)	Maximum Number (or Approximate Dollar Value) of Shares that May Yet Be Purchased Under the Plans or Programs
July 1 - July 31, 2024	—	$	—	—	$	1,360,938,325
August 1 - August 31, 2024	—	$	—	—	$	1,360,938,325
September 1 - September 30, 2024	—	$	—	—	$	1,360,938,325
Total	—			—

(1)In September 2021, our Board of Directors authorized a share repurchase program with a maximum dollar limit of $1.5 billion. Repurchases may be made from time to time in the open market, by block purchases, in privately negotiated transactions, or in such other manner as determined by our management. Our management will also determine the timing and amount of any repurchases based on market conditions and other factors. The share repurchase program does not obligate us to acquire any particular amount of common stock, and it may be suspended or discontinued at any time. This share repurchase program does not have an expiration date.

Item 5. Other Information

During the three months ended September 30, 2024, no director or officer of the Company adopted or terminated a “Rule 10b5-1 trading arrangement” or “non-Rule 10b5-1 trading arrangement,” as each term is defined in Item 408(a) of Regulation S-K.

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Item 6. Exhibits


Exhibit No.		Description

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 (filed on October 31, 2022, as Exhibit 3.4 to The Williams Companies, Inc.’s current report on Form 10-Q (File No. 001-04174) and incorporated herein by reference).
31.1*	—	Certification of Chief Executive Officer pursuant to Rules 13a-14(a) and 15d-14(a) promulgated under the Securities Exchange Act of 1934, as amended, and Item 601(b)(31) of Regulation S‑K, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2*	—	Certification of Chief Financial Officer pursuant to Rules 13a-14(a) and 15d-14(a) promulgated under the Securities Exchange Act of 1934, as amended, and Item 601(b)(31) of Regulation S-K, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32**	—	Certification of Chief Executive Officer and Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
101.INS*	—	XBRL Instance Document. The instance document does not appear in the interactive data file because its XBRL tags are embedded within the inline XBRL document.
101.SCH*	—	XBRL Taxonomy Extension Schema.
101.CAL*	—	XBRL Taxonomy Extension Calculation Linkbase.
101.DEF*	—	XBRL Taxonomy Extension Definition Linkbase.
101.LAB*	—	XBRL Taxonomy Extension Label Linkbase.
101.PRE*	—	XBRL Taxonomy Extension Presentation Linkbase.
104*	—	Cover Page Interactive Data File. The cover page interactive data file does not appear in the interactive data file because its XBRL tags are embedded within the inline XBRL document (contained in Exhibit 101).

* Filed herewith.

** Furnished herewith.

SIGNATURE

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


			THE WILLIAMS COMPANIES, INC.
			(Registrant)

			/s/ Mary A. Hausman
			Mary A. Hausman
			Vice President, Chief Accounting Officer and Controller (Duly Authorized Officer and Principal Accounting Officer)

November 6, 2024

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The Williams Companies, Inc. (WMB) 10-Q2024 Q3 Quarterly report

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