Southwestern Energy 10Q 2023 Q3 Quarterly report

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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, 2023

☐ 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: 001-08246

Southwestern Energy Company

(Exact name of registrant as specified in its charter)

Delaware

71-0205415

(State or other jurisdiction of incorporation or organization)

(I.R.S. Employer Identification No.)

10000 Energy Drive

Spring, Texas 77389

(Address of principal executive offices)(Zip Code)

(832) 796-1000

(Registrant’s telephone number, including area code)

Not Applicable

(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, Par Value $0.01

SWN

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						Outstanding as of October 31, 2023
Common Stock, Par Value $0.01						1,101,463,052

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SOUTHWESTERN ENERGY COMPANY

INDEX TO FORM 10-Q

FOR THE QUARTERLY PERIOD ENDED SEPTEMBER 30, 2023


PART I – FINANCIAL INFORMATION			Page

Item 1.	Financial Statements		4
	Consolidated Statements of Operations		4
	Consolidated Statements of Comprehensive Income (Loss)		5
	Consolidated Balance Sheets		6
	Consolidated Statements of Cash Flows		7
	Consolidated Statements of Changes in Equity		8
	Notes to Consolidated Financial Statements		10
		Note 1. Basis of Presentation	10
		Note 2. Acquisitio ns	10
		Note 3. Revenue Recognition	11
		Note 4. Cash and Cash Equivalents	13
		Note 5. Natural Gas and Oil Properties	13
		Note 6. Earnings per Share	14
		Note 7. Derivatives and Risk Management	15
		Note 8. Reclassifications From Accumulated Other Comprehensive Income (Loss)	21
		Note 9. Fair Value Measurements	21
		Note 10. Debt	23
		Note 1 1 . Commitments and Contingencies	26
		Note 1 2 . Income Taxes	27
		Note 13. Pension Plan and Other Postretirement Benefits	28
		Note 14. Long-Term Incentive Compensation	29
		Note 1 5 . Segment Information	33
		Note 1 6 . New Accounting Pronouncements	35

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		35
	Results of Operations		37
	Liquidity and Capital Resources		46
Item 3.	Quantitative and Qualitative Disclosures About Market Risk		52
Item 4.	Controls and Procedures		53

PART II – OTHER INFORMATION

Item 1.	Legal Proceedings		53
Item 1A.	Risk Factors		53
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds		53
Item 3.	Defaults Upon Senior Securities		53
Item 4.	Mine Safety Disclosures		53
Item 5.	Other Information		53
Item 6.	Exhibits		55

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CAUTIONARY STATEMENT ABOUT FORWARD-LOOKING STATEMENTS

This Quarterly Report on Form 10-Q (“Quarterly Report”) includes certain statements that may be deemed to be forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). All statements, other than statements of historical fact or present financial information, that address activities, outcomes and other matters that should or may occur in the future, including, without limitation, statements regarding the financial position, business strategy, production and reserve growth and other plans and objectives for our future operations, are forward-looking statements. Although we believe the expectations expressed in such forward-looking statements are based on reasonable assumptions, such statements are not guarantees of future performance. We have no obligation and make no undertaking to publicly update or revise any forward-looking statements, except as may be required by law.

Forward-looking statements include the items identified in the preceding paragraph, information concerning possible or assumed future results of operations and other statements in this Quarterly Report identified by words such as “anticipate,” “intend,” “plan,” “project,” “estimate,” “continue,” “potential,” “should,” “could,” “may,” “will,” “objective,” “guidance,” “outlook,” “effort,” “expect,” “believe,” “predict,” “budget,” “projection,” “goal,” “forecast,” “model,” “target” or similar words. Statements may be forward-looking even in the absence of these particular words.

You should not place undue reliance on forward-looking statements. They are subject to known and unknown risks, uncertainties and other factors that may affect our operations, markets, products, services and prices and cause our actual results, performance or achievements to be materially different from any future results, performance or achievements expressed or implied by the forward-looking statements. These forward-looking statements are based on management’s current beliefs, based on currently available information, as to the outcome and timing of future events. In addition to any assumptions and other factors referred to specifically in connection with forward-looking statements, risks, uncertainties and factors that could cause our actual results to differ materially from those indicated in any forward-looking statement include, but are not limited to:

•the timing and extent of changes in market conditions and prices for natural gas, oil and natural gas liquids (“NGLs”) (including regional basis differentials) and the impact of reduced demand for our production and products in which our production is a component due to governmental and societal actions taken in response to a pandemic or other world health event;

•our ability to fund our planned capital investments;

•a change in our credit rating or adverse changes in interest rates;

•the extent to which lower commodity prices impact our ability to service or refinance our existing debt;

•the impact of volatility in the financial markets or other global economic factors, including any future development of the LNG market and the impact of a world health event or other disease outbreak;

•geopolitical and business conditions in key regions of the world;

•difficulties in appropriately allocating capital and resources among our strategic opportunities;

•the timing and extent of our success in discovering, developing, producing, replacing and estimating reserves;

•our ability to maintain leases that may expire if production is not established or profitably maintained;

•our ability to meet natural gas delivery commitments and to utilize or monetize our firm transportation commitments;

•our ability to realize the expected benefits from acquisitions, including the Indigo and GEPH Mergers (each as defined below);

•our ability to transport our production to the most favorable markets or at all;

•availability and costs of personnel and of products and services provided by third parties;

•the impact of government regulation, including changes in law, the ability to obtain and maintain permits, any increase in severance or similar taxes, and legislation or regulation relating to hydraulic fracturing or other drilling and completion techniques, climate and over-the-counter derivatives;

•our ability to achieve, reach or otherwise meet initiatives, plans, or ambitions with respect to environmental, social and governance matters;

•the impact of the adverse outcome of any material litigation against us or judicial decisions that affect us or our industry generally;

•the effects of weather or power outages;

•increased competition;

•inflation rates;

•the financial impact of accounting regulations and critical accounting policies;

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•the comparative cost of alternative fuels;

•credit risk relating to the risk of loss as a result of non-performance by our counterparties, including as a result of financial or banking failures;

•our hedging strategy and results;

•our ability to obtain debt or equity financing on satisfactory terms; and

•any other factors listed in the reports we have filed and may file with the Securities and Exchange Commission (“SEC”).

Should one or more of the risks or uncertainties described above or elsewhere in this Quarterly Report occur, or should underlying assumptions prove incorrect, our actual results and plans could differ materially from those expressed in any forward-looking statements. We specifically disclaim all responsibility to update publicly any information contained in a forward-looking statement or any forward-looking statement in its entirety and therefore disclaim any resulting liability for potentially related damages.

Reserve engineering is a process of estimating underground accumulations of natural gas, oil and NGLs that cannot be measured in an exact way. The accuracy of any reserve estimate depends on the quality of available data, the interpretation of such data and price and cost assumptions made by reserve engineers. In addition, the results of drilling, testing and production activities may justify revisions of estimates that were made previously. If significant, such revisions would change the schedule of any further production and our development program. Accordingly, reserve estimates may differ significantly from the quantities of natural gas, oil and NGLs that are ultimately recovered.

All forward-looking statements attributable to us are expressly qualified in their entirety by this cautionary statement.

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PART I – FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

SOUTHWESTERN ENERGY COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)


	For the three months ended September 30,				For the nine months ended September 30,
(in millions, except share/per share amounts)	2023		2022		2023		2022
Operating Revenues:
Gas sales	$	627	$	2,884	$	2,323	$	7,061
Oil sales	94		100		281		349
NGL sales	169		260		523		842
Marketing	553		1,298		1,707		3,371
Other	—		(1)		(4)		(1)
	1,443		4,541		4,830		11,622
Operating Costs and Expenses:
Marketing purchases	545		1,289		1,693		3,366
Operating expenses	444		423		1,280		1,206
General and administrative expenses	46		41		133		120
Merger-related expenses	—		—		—		27


Depreciation, depletion and amortization	338		298		979		861

Taxes, other than income taxes	63		76		189		198
	1,436		2,127		4,274		5,778
Operating Income	7		2,414		556		5,844
Interest Expense:
Interest on debt	61		77		184		218
Other interest charges	3		3		9		10
Interest capitalized	(28)		(30)		(87)		(89)
	36		50		106		139

Gain (Loss) on Derivatives	93		(1,903)		1,811		(6,709)
Loss on Early Extinguishment of Debt	—		—		(19)		(6)
Other Income (Loss), Net	2		—		1		(1)

Income (Loss) Before Income Taxes	66		461		2,243		(1,011)
Provision for Income Taxes:
Current	—		11		—		41
Deferred	21		—		28		—
	21		11		28		41
Net Income (Loss)	$	45	$	450	$	2,215	$	(1,052)


Earnings (Loss) Per Common Share:
Basic	$	0.04	$	0.41	$	2.01	$	(0.94)
Diluted	$	0.04	$	0.40	$	2.01	$	(0.94)

Weighted Average Common Shares Outstanding:
Basic	1,101,231,113		1,110,259,907		1,100,895,642		1,113,705,502
Diluted	1,104,027,634		1,112,522,861		1,102,867,675		1,113,705,502

The accompanying notes are an integral part of these consolidated financial statements.

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SOUTHWESTERN ENERGY COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(Unaudited)


	For the three months ended September 30,				For the nine months ended September 30,
(in millions)	2023		2022		2023		2022
Net income (loss)	$	45	$	450	$	2,215	$	(1,052)

Change in value of pension and other postretirement liabilities:
Amortization of prior service cost and net gain, including gain on settlements and curtailments included in net periodic pension cost (1)	—		—		1		—
Net actuarial loss incurred in period	—		—		(2)		—
Net tax loss attributable to pension termination	—		—		(14)		—
Total change in value of pension and postretirement liabilities	—		—		(15)		—
Comprehensive income (loss)	$	45	$	450	$	2,200	$	(1,052)

(1)Settlement adjustment was less than $1 million for the three and nine months ended September 30, 2022.

The accompanying notes are an integral part of these consolidated financial statements.

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SOUTHWESTERN ENERGY COMPANY AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(Unaudited)


	September 30, 2023		December 31, 2022

ASSETS	(in millions)
Current assets:
Cash and cash equivalents	$	26	$	50
Accounts receivable, net	602		1,401
Derivative assets	336		145
Other current assets	78		68
Total current assets	1,042		1,664
Natural gas and oil properties, using the full cost method, including $2,140 million as of September 30, 2023 and $2,217 million as of December 31, 2022 excluded from amortization	37,349		35,763

Other	555		527
Less: Accumulated depreciation, depletion and amortization	(26,381)		(25,387)
Total property and equipment, net	11,523		10,903
Operating lease assets	163		177
Long-term derivative assets	153		72
Deferred tax assets	—		—
Other long-term assets	92		110
Total long-term assets	408		359
TOTAL ASSETS	$	12,973	$	12,926
LIABILITIES AND EQUITY
Current liabilities:

Accounts payable	$	1,317	$	1,835
Taxes payable	135		136
Interest payable	26		86

Derivative liabilities	219		1,317
Current operating lease liabilities	44		42
Other current liabilities	17		65
Total current liabilities	1,758		3,481
Long-term debt	4,114		4,392
Long-term operating lease liabilities	116		133
Long-term derivative liabilities	186		378

Other long-term liabilities	262		218
Total long-term liabilities	4,678		5,121
Commitments and contingencies (Note 11)
Equity:
Common stock, $0.01 par value; 2,500,000,000 shares authorized; issued 1,163,077,745 shares as of September 30, 2023 and 1,161,545,588 shares as of December 31, 2022	12		12

Additional paid-in capital	7,185		7,172
Accumulated deficit	(324)		(2,539)
Accumulated other comprehensive income (loss)	(9)		6
Common stock in treasury, 61,614,693 shares as of September 30, 2023 and December 31, 2022	(327)		(327)
Total equity	6,537		4,324
TOTAL LIABILITIES AND EQUITY	$	12,973	$	12,926

The accompanying notes are an integral part of these consolidated financial statements.

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SOUTHWESTERN ENERGY COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)


	For the nine months ended September 30,
(in millions)	2023		2022
Cash Flows From Operating Activities:
Net income (loss)	$	2,215	$	(1,052)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization	979		861
Amortization of debt issuance costs	5		8

Deferred income taxes	28		—
(Gain) loss on derivatives, unsettled	(1,562)		2,524
Stock-based compensation	7		4
Loss on early extinguishment of debt	19		6

Other	3		2
Change in assets and liabilities:
Accounts receivable	799		(602)
Accounts payable	(362)		506
Taxes payable	(2)		28
Interest payable	(33)		(22)
Inventories	(15)		(8)
Other assets and liabilities	(42)		(59)
Net cash provided by operating activities	2,039		2,196

Cash Flows From Investing Activities:
Capital investments	(1,833)		(1,623)
Proceeds from sale of property and equipment	123		15



Net cash used in investing activities	(1,710)		(1,608)

Cash Flows From Financing Activities:
Payments on current portion of long-term debt	—		(205)

Payments on long-term debt	(437)		(71)
Payments on revolving credit facility	(3,044)		(10,341)
Borrowings under revolving credit facility	3,182		10,061
Change in bank drafts outstanding	(50)		62
Proceeds from exercise of common stock options	—		7
Purchase of treasury stock	—		(100)
Debt issuance/amendment costs	—		(14)
Cash paid for tax withholding	(4)		(4)



Net cash used in financing activities	(353)		(605)

Decrease in cash and cash equivalents	(24)		(17)
Cash and cash equivalents at beginning of year	50		28
Cash and cash equivalents at end of period	$	26	$	11

The accompanying notes are an integral part of these consolidated financial statements.

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SOUTHWESTERN ENERGY COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY

(Unaudited)


	Common Stock			Additional Paid-In Capital		Accumulated Deficit		Accumulated Other Comprehensive Income (Loss)		Common Stock in Treasury			Total
	Shares Issued	Amount								Shares	Amount

	(in millions, except share amounts)
Balance at December 31, 2022	1,161,545,588	$	12	$	7,172	$	(2,539)	$	6	61,614,693	$	(327)	$	4,324
Comprehensive income:
Net income	—	—		—		1,939		—		—	—		1,939
Other comprehensive loss	—	—		—		—		(15)		—	—		(15)
Total comprehensive income	—	—		—		—		—		—	—		1,924
Stock-based compensation	—	—		2		—		—		—	—		2



Restricted units vested	1,999,039	—		8		—		—		—	—		8


Tax withholding – stock compensation	(662,163)	—		(4)		—		—		—	—		(4)
Balance at March 31, 2023	1,162,882,464	$	12	$	7,178	$	(600)	$	(9)	61,614,693	$	(327)	$	6,254
Comprehensive income:
Net income	—	—		—		231		—		—	—		231
Other comprehensive income	—	—		—		—		—		—	—		—
Total comprehensive income	—	—		—		—		—		—	—		231
Stock-based compensation	—	—		4		—		—		—	—		4

Issuance of restricted stock	188,382	—		—		—		—		—	—		—

Restricted units vested	9,968	—		—		—		—		—	—		—


Tax withholding – stock compensation	(3,069)	—		—		—		—		—	—		—
Balance at June 30, 2023	1,163,077,745	$	12	$	7,182	$	(369)	$	(9)	61,614,693	$	(327)	$	6,489
Comprehensive income:
Net income	—	—		—		45		—		—	—		45
Other comprehensive income	—	—		—		—		—		—	—		—
Total comprehensive income	—	—		—		—		—		—	—		45
Stock-based compensation	—	—		3		—		—		—	—		3






Balance at September 30, 2023	1,163,077,745	$	12	$	7,185	$	(324)	$	(9)	61,614,693	$	(327)	$	6,537

The accompanying notes are an integral part of these consolidated financial statements.

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	Common Stock			Additional Paid-In Capital		Accumulated Deficit		Accumulated Other Comprehensive Income (Loss)		Common Stock in Treasury			Total
	Shares Issued	Amount								Shares	Amount

	(in millions, except share amounts)
Balance at December 31, 2021	1,158,672,666	$	12	$	7,150	$	(4,388)	$	(25)	44,353,224	$	(202)	$	2,547
Comprehensive loss:
Net loss	—	—		—		(2,675)		—		—	—		(2,675)
Other comprehensive income	—	—		—		—		—		—	—		—
Total comprehensive loss	—	—		—		—		—		—	—		(2,675)
Stock-based compensation	—	—		1		—		—		—	—		1





Performance units vested	2,499,860	—		12		—		—		—	—		12
Tax withholding – stock compensation	(721,070)	—		(4)		—		—		—	—		(4)
Balance at March 31, 2022	1,160,451,456	$	12	$	7,159	$	(7,063)	$	(25)	44,353,224	$	(202)	$	(119)
Comprehensive income:
Net income	—	—		—		1,173		—		—	—		1,173
Other comprehensive income	—	—		—		—		—		—	—		—
Total comprehensive income	—	—		—		—		—		—	—		1,173
Stock-based compensation	—	—		2		—		—		—	—		2
Exercise of stock options	893,312	—		7		—		—		—	—		7
Issuance of restricted stock	115,608	—		—		—		—		—	—		—
Restricted stock units vested	21,981	—		—		—		—		—	—		—
Treasury stock	—	—		—		—		—		2,815,541	(20)		(20)
Issuance of common stock	79	—		—		—		—		—	—		—

Tax withholding – stock compensation	(7,014)	—		—		—		—		—	—		—
Balance at June 30, 2022	1,161,475,422	$	12	$	7,168	$	(5,890)	$	(25)	47,168,765	$	(222)	$	1,043
Comprehensive income:
Net income	—	—		—		450		—		—	—		450
Other comprehensive income	—	—		—		—		—		—	—		—
Total comprehensive income	—	—		—		—		—		—	—		450
Stock-based compensation	—	—		1		—		—		—	—		1



Treasury stock	—	—		—		—		—		10,798,154	(80)		(80)


Balance at September 30, 2022	1,161,475,422	$	12	$	7,169	$	(5,440)	$	(25)	57,966,919	$	(302)	$	1,414

The accompanying notes are an integral part of these consolidated financial statements.

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SOUTHWESTERN ENERGY COMPANY AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

(1) BASIS OF PRESENTATION

Nature of Operations

Southwestern Energy Company (including its subsidiaries, collectively “Southwestern” or the “Company”) is an independent energy company engaged in natural gas, oil and NGLs development, exploration and production (“E&P”). The Company is also focused on creating and capturing additional value through its marketing business (“Marketing”). Southwestern conducts most of its business through subsidiaries and operates principally in two segments: E&P and Marketing.

E&P. Southwestern’s primary business is the development and production of natural gas as well as associated NGLs and oil, with ongoing operations focused on unconventional natural gas and oil reservoirs located in Pennsylvania, West Virginia, Ohio and Louisiana. The Company’s operations in Pennsylvania, West Virginia and Ohio, herein referred to as “Appalachia,” are primarily focused on the Marcellus Shale, the Utica and the Upper Devonian unconventional natural gas and liquids reservoirs. The Company’s operations in Louisiana, herein referred to as “Haynesville,” are primarily focused on the Haynesville and Bossier natural gas reservoirs (“Haynesville and Bossier Shales”). The Company also operates drilling rigs and provides certain oilfield products and services that serve the Company’s E&P operations through vertical integration.

Marketing. Southwestern’s marketing activities capture opportunities that arise through the marketing and transportation of natural gas, oil and NGLs primarily produced in its E&P operations.

Basis of Presentation

The accompanying consolidated financial statements were prepared using accounting principles generally accepted in the United States (“GAAP”) for interim financial information and in accordance with the rules and regulations of the Securities and Exchange Commission. Certain information relating to the Company’s organization and footnote disclosures normally included in financial statements prepared in accordance with GAAP have been appropriately condensed or omitted in this Quarterly Report.

Principles of Consolidation

The consolidated financial statements contained in this report include all normal and recurring material adjustments that, in the opinion of management, are necessary for a fair statement of the financial position, results of operations and cash flows for the interim periods presented herein. It is recommended that these consolidated financial statements be read in conjunction with the consolidated financial statements and the notes thereto included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2022 (“2022 Annual Report”).

The Company’s significant accounting policies, which have been reviewed and approved by the Audit Committee of the Company’s board of directors (the “Board”), are summarized in Note 1 in the Notes to the Consolidated Financial Statements included in the Company’s 2022 Annual Report.

(2) ACQUISITIONS

GEP Haynesville, LLC Merger

On November 3, 2021, Southwestern entered into an Agreement and Plan of Merger with Mustang Acquisition Company, LLC (“Mustang”), GEP Haynesville, LLC (“GEPH”) and GEPH Unitholder Rep, LLC (the “GEPH Merger Agreement”). Pursuant to the terms of the GEPH Merger Agreement, GEPH merged with and into Mustang, a subsidiary of Southwestern, and became a wholly-owned subsidiary of Southwestern (the “GEPH Merger”). The GEPH Merger closed on December 31, 2021 and expanded the Company’s operations in the Haynesville.

Indigo Natural Resources Merger

On June 1, 2021, Southwestern entered into an Agreement and Plan of Merger with Ikon Acquisition Company, LLC (“Ikon”), Indigo Natural Resources LLC (“Indigo”) and Ibis Unitholder Representative LLC (the “Indigo Merger Agreement”). Pursuant to the terms of the Indigo Merger Agreement, Indigo merged with and into Ikon, a subsidiary of Southwestern, and became a wholly-owned subsidiary of Southwestern (the “Indigo Merger”). On August 27, 2021, Southwestern’s stockholders voted to approve the Indigo Merger and the transaction closed on September 1, 2021. The Indigo Merger established Southwestern’s natural gas operations in the Haynesville and Bossier Shales in Louisiana.

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Merger-Related Expenses

The Company did not incur merger-related expenses during the three and nine months ended September 30, 2023 or during the three months ended September 30, 2022. The following table summarizes the merger-related expenses incurred during the nine months ended September 30, 2022:


	For the nine months ended September 30, 2022

(in millions)		Indigo Merger		GEPH Merger		Total
Transition services		$	—	$	18	$	18
Professional fees (bank, legal, consulting)		—		1		1

Contract buyouts, terminations and transfers		1		2		3
Due diligence and environmental		1		1		2
Employee-related		—		1		1
Other		—		2		2
Total merger-related expenses		$	2	$	25	$	27

(3) REVENUE RECOGNITION

Revenues from Contracts with Customers

Natural gas and liquids. Natural gas, oil and NGL sales are recognized when control of the product is transferred to the customer at a designated delivery point. The pricing provisions of the Company’s contracts are primarily tied to a market index with certain adjustments based on factors such as delivery, quality of the product and prevailing supply and demand conditions in the geographic areas in which the Company operates. Under the Company’s sales contracts, the delivery of each unit of natural gas, oil and NGLs represents a separate performance obligation, and revenue is recognized at the point in time when the performance obligations are fulfilled. There is no significant financing component to the Company’s revenues as payment terms are typically within 30 to 60 days of control transfer. Furthermore, consideration from a customer corresponds directly with the value to the customer of the Company’s performance completed to date. As a result, the Company recognizes revenue in the amount for which the Company has a right to invoice and has not disclosed information regarding its remaining performance obligations.

The Company records revenue from its natural gas and liquids production in the amount of its net revenue interest in sales from its properties. Accordingly, natural gas and liquid sales are not recognized for deliveries in excess of the Company’s net revenue interest, while natural gas and liquid sales are recognized for any under-delivered volumes.

Marketing. The Company, through its marketing affiliate, generally markets natural gas, oil and NGLs for its affiliated E&P companies as well as other joint owners who choose to market with the Company. In addition, the Company markets some products purchased from third parties. Marketing revenues for natural gas, oil and NGL sales are recognized when control of the product is transferred to the customer at a designated delivery point. The pricing provisions of the Company’s contracts are primarily tied to market indices with certain adjustments based on factors such as delivery, quality of the product and prevailing supply and demand conditions. Under the Company’s marketing contracts, the delivery of each unit of natural gas, oil and NGLs represents a separate performance obligation, and revenue is recognized at the point in time when the performance obligations are fulfilled. Customers are invoiced and revenues are recorded each month as natural gas, oil and NGLs are delivered, and payment terms are typically within 30 to 60 days of control transfer. Furthermore, consideration from a customer corresponds directly with the value to the customer of the Company’s performance completed to date. As a result, the Company recognizes revenue in the amount for which the Company has a right to invoice and has not disclosed information regarding its remaining performance obligations.

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Disaggregation of Revenues

The Company presents a disaggregation of E&P revenues by product on the consolidated statements of operations net of intersegment revenues. The following table reconciles operating revenues as presented on the consolidated statements of operations to the operating revenues by segment:


(in millions)	E&P		Marketing		Intersegment Revenues		Total
Three months ended September 30, 2023
Gas sales	$	610	$	—	$	17	$	627
Oil sales	93		—		1		94
NGL sales	170		—		(1)		169
Marketing	—		1,379		(826)		553

Total	$	873	$	1,379	$	(809)	$	1,443
(in millions)
Three months ended September 30, 2022
Gas sales	$	2,889	$	—	$	(5)	$	2,884
Oil sales	99		—		1		100
NGL sales	260		—		—		260
Marketing	—		4,436		(3,138)		1,298
Other (1)	(1)		—		—		(1)
Total	$	3,247	$	4,436	$	(3,142)	$	4,541


(in millions)	E&P		Marketing		Intersegment Revenues		Total
Nine months ended September 30, 2023
Gas sales	$	2,281	$	—	$	42	$	2,323
Oil sales	278		—		3		281
NGL sales	524		—		(1)		523
Marketing	—		4,651		(2,944)		1,707
Other (1)	(4)		—		—		(4)
Total	$	3,079	$	4,651	$	(2,900)	$	4,830
(in millions)
Nine months ended September 30, 2022
Gas sales	$	7,064	$	—	$	(3)	$	7,061
Oil sales	345		—		4		349
NGL sales	842		—		—		842
Marketing	—		11,214		(7,843)		3,371
Other (1)	(1)		—		—		(1)
Total	$	8,250	$	11,214	$	(7,842)	$	11,622

(1)For the nine months ended September 30, 2023 and the three and nine months ended September 30, 2022, other E&P revenues consists primarily of losses on purchaser imbalances associated with natural gas and certain NGLs.

Associated E&P revenues are also disaggregated for analysis on a geographic basis by the core areas in which the Company operates, which are Appalachia and Haynesville.


	For the three months ended September 30,				For the nine months ended September 30,
(in millions)	2023		2022		2023		2022
Appalachia	$	500	$	1,874	$	1,891	$	4,971
Haynesville	373		1,373		1,188		3,279

Total	$	873	$	3,247	$	3,079	$	8,250

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Receivables from Contracts with Customers

The following table reconciles the Company’s receivables from contracts with customers to consolidated accounts receivable as presented on the consolidated balance sheet:


(in millions)	September 30, 2023		December 31, 2022
Receivables from contracts with customers	$	512	$	1,313
Other accounts receivable	90		88
Total accounts receivable	$	602	$	1,401

Amounts recognized against the Company’s allowance for doubtful accounts related to receivables arising from contracts with customers were not significant for both the nine months ended September 30, 2023 and year ended December 31, 2022. The Company has no contract assets or contract liabilities associated with its revenues from contracts with customers.

(4) CASH AND CASH EQUIVALENTS

The following table presents a summary of cash and cash equivalents as of September 30, 2023 and December 31, 2022:


(in millions)	September 30, 2023		December 31, 2022
Cash	$	2	$	49
Marketable securities (1)	24		1

Total	$	26	$	50

(1)Typically consists of government stable value money market funds.

(5) NATURAL GAS AND OIL PROPERTIES

The Company utilizes the full cost method of accounting for costs related to the development, exploration and acquisition of natural gas and oil properties. Under this method, all such costs (productive and nonproductive), including salaries, benefits and other internal costs directly attributable to these activities, are capitalized on a country-by-country basis and amortized over the estimated lives of the properties using the units-of-production method. These capitalized costs are subject to a ceiling test that limits such pooled costs, net of applicable deferred taxes, to the aggregate of the present value of future net revenues attributable to proved natural gas, oil and NGL reserves discounted at 10% (standardized measure). Any costs in excess of the ceiling are written off as a non-cash expense. The expense may not be reversed in future periods, even though higher natural gas, oil and NGL prices may subsequently increase the ceiling. Companies using the full cost method are required to use the average quoted price from the first day of each month from the previous 12 months, including the impact of derivatives designated for hedge accounting, to calculate the ceiling value of their reserves. The Company had no hedge positions that were designated for hedge accounting as of September 30, 2023. Prices used to calculate the ceiling value of reserves were as follows:


	September 30, 2023		September 30, 2022
Natural gas (per MMBtu)	$	3.42	$	6.13
Oil (per Bbl)	$	78.54	$	91.71
NGLs (per Bbl)	$	22.24	$	37.33

Using the average quoted prices above, adjusted for market differentials, the Company’s net book value of its United States natural gas and oil properties did not exceed the ceiling amount at September 30, 2023. Decreases in market prices as well as changes in production rates, levels of reserves, evaluation of costs excluded from amortization, future development costs and production costs could result in future non-cash ceiling test impairments to the Company’s natural gas and oil properties. Given the fall in commodity prices during 2023, the Company expects some non-cash impairment of its assets will likely occur as early as the fourth quarter of 2023.

In June 2023, the Company sold non-core natural gas and oil properties in Appalachia for approximately $123 million in cash, subject to customary post-closing adjustments. The cash proceeds were used to pay down the Company’s revolving credit facility and were recorded as a reduction to its natural gas and oil properties.

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(6) EARNINGS PER SHARE

Basic earnings per common share is computed by dividing net income (loss) by the weighted average number of common shares outstanding during the reportable period. The diluted earnings per share calculation adds to the weighted average number of common shares outstanding: the incremental shares that would have been outstanding assuming the exercise of dilutive stock options, the vesting of unvested restricted shares of common stock, restricted stock units and performance units. An antidilutive impact is an increase in earnings per share or a reduction in net loss per share resulting from the conversion, exercise or contingent issuance of certain securities.

During the three months ended September 30, 2022, the Company repurchased approximately 10.8 million shares of its outstanding common stock pursuant to a previously announced share repurchase program at an average price of $7.41 per share for a total cost of approximately $80 million. During the nine months ended September 30, 2022, the Company repurchased approximately 13.6 million shares at an average price of $7.35 per share for a total cost of approximately $100 million. We did not repurchase any shares during the three or nine months ended September 30, 2023.

The following table presents the computation of earnings per share for the three and nine months ended September 30, 2023 and 2022:


	For the three months ended September 30,				For the nine months ended September 30,
(in millions, except share/per share amounts)	2023		2022		2023		2022
Net income (loss)	$	45	$	450	$	2,215	$	(1,052)

Number of common shares:
Weighted average outstanding	1,101,231,113		1,110,259,907		1,100,895,642		1,113,705,502
Issued upon assumed exercise of outstanding stock options	—		—		—		—
Effect of issuance of non-vested restricted common stock	932,868		796,253		839,031		—
Effect of issuance of non-vested restricted units	1,689,617		1,466,701		1,133,002		—
Effect of issuance of non-vested performance units	174,036		—		—		—
Weighted average and dilutive outstanding	1,104,027,634		1,112,522,861		1,102,867,675		1,113,705,502

Earnings (loss) per common share
Basic	$	0.04	$	0.41	$	2.01	$	(0.94)
Diluted	$	0.04	$	0.40	$	2.01	$	(0.94)

The following table presents the common stock shares equivalent excluded from the calculation of diluted earnings per share for the three and nine months ended September 30, 2023 and 2022, as they would have had an antidilutive effect:


	For the three months ended September 30,		For the nine months ended September 30,
	2023	2022	2023	2022
Unexercised stock options	820,138	1,961,128	835,362	2,467,127
Unvested restricted common stock	—	—	54,989	810,025
Restricted units	224,726	790,182	652,089	1,503,049
Performance units	—	—	764,916	474,093
Total	1,044,864	2,751,310	2,307,356	5,254,294

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(7) DERIVATIVES AND RISK MANAGEMENT

The Company is exposed to volatility in market prices and basis differentials for natural gas, oil and NGLs which impacts the predictability of its cash flows related to the sale of those commodities. These risks are managed by the Company’s use of certain derivative financial instruments. As of September 30, 2023 and September 30, 2022, the Company’s derivative financial instruments consisted of fixed price swaps, two-way costless collars, three-way costless collars, basis swaps, options (calls and puts), index swaps and interest rate swaps. A description of the Company’s derivative financial instruments is provided below:


Fixed price swaps			If the Company sells a fixed price swap, the Company receives a fixed price for the contract, and pays a floating market price to the counterparty. If the Company purchases a fixed price swap, the Company receives a floating market price for the contract and pays a fixed price to the counterparty.

Two-way costless collars			Arrangements that contain a fixed floor price (“purchased put option”) and a fixed ceiling price (“sold call option”) based on an index price which, in aggregate, have no net cost. At the contract settlement date, (1) if the index price is higher than the ceiling price, the Company pays the counterparty the difference between the index price and ceiling price, (2) if the index price is between the floor and ceiling prices, no payments are due from either party, and (3) if the index price is below the floor price, the Company will receive the difference between the floor price and the index price.

Three-way costless collars			Arrangements that contain a purchased put option, a sold call option and a sold put option based on an index price that, in aggregate, have no net cost. At the contract settlement date, (1) if the index price is higher than the sold call strike price, the Company pays the counterparty the difference between the index price and sold call strike price, (2) if the index price is between the purchased put strike price and the sold call strike price, no payments are due from either party, (3) if the index price is between the sold put strike price and the purchased put strike price, the Company will receive the difference between the purchased put strike price and the index price, and (4) if the index price is below the sold put strike price, the Company will receive the difference between the purchased put strike price and the sold put strike price.

Basis swaps			Arrangements that guarantee a price differential for natural gas from a specified delivery point. If the Company sells a basis swap, the Company receives a payment from the counterparty if the price differential is greater than the stated terms of the contract and pays the counterparty if the price differential is less than the stated terms of the contract. If the Company purchases a basis swap, the Company pays the counterparty if the price differential is greater than the stated terms of the contract and receives a payment from the counterparty if the price differential is less than the stated terms of the contract.



Options (Calls and Puts)			The Company purchases and sells options in exchange for premiums. If the Company purchases a call option, the Company receives from the counterparty the excess (if any) of the market price over the strike price of the call option at the time of settlement, but if the market price is below the call’s strike price, no payment is due from either party. If the Company sells a call option, the Company pays the counterparty the excess (if any) of the market price over the strike price of the call option at the time of settlement, but if the market price is below the call’s strike price, no payment is due from either party. If the Company purchases a put option, the Company receives from the counterparty the excess (if any) of the strike price over the market price of the put option at the time of settlement, but if the market price is above the put’s strike price, no payment is due from either party. If the Company sells a put option, the Company pays the counterparty the excess (if any) of the strike price over the market price of the put option at the time of settlement, but if the market price is above the put’s strike price, no payment is due from either party.

Index swaps			Natural gas index swaps are used to manage the Company’s exposure to volatility in daily cash market pricing. When the Company sells an index swap, the Company pays an amount equal to the average of the daily index price for a given month at a specified location and receives a first of month index price based on the same location.

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Interest rate swaps			Interest rate swaps are used to fix or float interest rates on existing or anticipated indebtedness. The purpose of these instruments is to manage the Company’s existing or anticipated exposure to unfavorable interest rate changes.

The Company contracts with counterparties for its derivative instruments that it believes are creditworthy at the time the transactions are entered into, and the Company actively monitors the credit ratings and credit default swap rates of these counterparties where applicable. However, there can be no assurance that a counterparty will be able to meet its obligations to the Company. The Company presents its derivatives position on a gross basis and does not net the asset and liability positions.

The following tables provide information about the Company’s financial instruments that are sensitive to changes in commodity prices and that are used to protect the Company’s exposure. None of the financial instruments below are designated for hedge accounting treatment. The tables present the notional amount, the weighted average contract prices and the fair value by expected maturity dates as of September 30, 2023:


Financial Protection on Production
		Weighted Average Price per MMBtu
	Volume (Bcf)	Swaps		Sold Puts		Purchased Puts		Sold Calls		Basis Differential		Fair Value at September 30, 2023 (in millions)
Natural Gas
2023
Fixed price swaps	179	$	3.28	$	—	$	—	$	—	$	—	$	49
Two-way costless collars	32	—		—		2.88		3.29		—		1
Three-way costless collars	47	—		2.08		2.50		2.91		—		(11)
Total	258											$	39
2024
Fixed price swaps	528	$	3.54	$	—	$	—	$	—	$	—	$	82
Two-way costless collars	44	—		—		3.07		3.53		—		(5)
Three-way costless collars	77	—		2.46		3.19		3.99		—		(5)
Total	649											$	72
2025

Two-way costless collars	73	$	—	$	—	$	3.50	$	5.40	$	—	$	11
Three-way costless collars	106	—		2.50		3.75		5.69		—		16
Total	179											$	27





Basis Swaps
2023	71	$	—	$	—	$	—	$	—	$	(0.57)	$	24
2024	46	—		—		—		—		(0.71)		9
2025	9	—		—		—		—		(0.64)		3


Total	126											$	36

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	Volume (MBbls)	Weighted Average Strike Price per Bbl								Fair Value at September 30, 2023 (in millions)
		Swaps		Sold Puts		Purchased Puts		Sold Calls
Oil
2023
Fixed price swaps	733	$	67.34	$	—	$	—	$	—	$	(15)
Two-way costless collars	147	—		—		70.00		80.58		(1)
Three-way costless collars	291	—		34.36		46.05		55.96		(10)
Total	1,171									$	(26)
2024
Fixed price swaps	1,571	$	71.06	$	—	$	—	$	—	$	(15)
Two-way costless collars	512	—		—		70.00		85.63		(2)
Total	2,083									$	(17)
2025
Fixed price swaps	41	$	77.66	$	—	$	—	$	—	$	—





Ethane
2023
Fixed price swaps	2,254	$	10.99	$	—	$	—	$	—	$	(1)


2024
Fixed price swaps	3,429	$	10.84	$	—	$	—	$	—	$	—







Propane
2023
Fixed price swaps	1,782	$	30.44	$	—	$	—	$	—	$	(1)


2024
Fixed price swaps	3,254	$	31.78	$	—	$	—	$	—	$	3


2025
Fixed price swaps	63	$	26.46	$	—	$	—	$	—	$	—

Normal Butane
2023
Fixed price swaps	198	$	40.96	$	—	$	—	$	—	$	1
2024
Fixed price swaps	329	$	40.74	$	—	$	—	$	—	$	1

Natural Gasoline
2023
Fixed price swaps	171	$	63.74	$	—	$	—	$	—	$	(1)
2024
Fixed price swaps	329	$	64.37	$	—	$	—	$	—	$	(1)

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Other Derivative Contracts
	Volume (Bcf)	Weighted Average Strike Price per MMBtu		Fair Value at September 30, 2023 (in millions)





Call Options – Natural Gas (Net)
2023	15	$	2.97	$	(4)
2024	82	6.56		(9)
2025	73	7.00		(14)
2026	73	7.00		(20)

Total	243			$	(47)

At September 30, 2023, the net fair value of the Company’s financial instruments was an $84 million asset, which included net reduction of the asset of $1 million related to non-performance risk. See Note 9 for additional details regarding the Company’s fair value measurements of its derivatives position.

As of September 30, 2023, the Company had no positions designated for hedge accounting treatment. Gains and losses on derivatives that are not designated for hedge accounting treatment, or do not meet hedge accounting requirements, are recorded as a component of gain (loss) on derivatives on the consolidated statements of operations. Accordingly, the gain (loss) on derivatives component of the statement of operations reflects the gains and losses on both settled and unsettled derivatives. Only the settled gains and losses are included in the Company’s realized commodity price calculations.

The balance sheet classification of the assets and liabilities related to derivative financial instruments are summarized below as of September 30, 2023 and December 31, 2022:


Derivative Assets
		Fair Value
(in millions)	Balance Sheet Classification	September 30, 2023		December 31, 2022
Derivatives not designated as hedging instruments:



Fixed price swaps – natural gas	Derivative assets	$	224	$	—

Fixed price swaps – ethane	Derivative assets	2		4
Fixed price swaps – propane	Derivative assets	10		9
Fixed price swaps – normal butane	Derivative assets	2		1
Fixed price swaps – natural gasoline	Derivative assets	—		1
Two-way costless collars – natural gas	Derivative assets	32		47
Two-way costless collars – oil	Derivative assets	1		—

Three-way costless collars – natural gas	Derivative assets	28		18
Three-way costless collars – oil	Derivative assets	—		1
Basis swaps – natural gas	Derivative assets	33		64
Put options – natural gas	Derivative assets	5		—



Fixed price swaps – natural gas	Other long-term assets	25		28
Fixed price swaps – oil	Other long-term assets	—		1
Fixed price swaps – ethane	Other long-term assets	—		1
Fixed price swaps – propane	Other long-term assets	—		1


Two-way costless collars – natural gas	Other long-term assets	43		18

Two-way costless collars – oil	Other long-term assets	1		—
Three-way costless collars – natural gas	Other long-term assets	77		3

Basis swaps – natural gas	Other long-term assets	8		17

Put options – natural gas	Other long-term assets	—		4

Total derivative assets		$	491	$	218

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Derivative Liabilities
		Fair Value
(in millions)	Balance Sheet Classification	September 30, 2023		December 31, 2022
Derivatives not designated as hedging instruments:



Fixed price swaps – natural gas	Derivative liabilities	$	73	$	581
Fixed price swaps – oil	Derivative liabilities	29		20
Fixed price swaps – ethane	Derivative liabilities	3		1
Fixed price swaps – propane	Derivative liabilities	7		—

Fixed price swaps – natural gasoline	Derivative liabilities	2		1
Two-way costless collars – natural gas	Derivative liabilities	31		235
Two-way costless collars – oil	Derivative liabilities	4		—

Three-way costless collars – natural gas	Derivative liabilities	39		311
Three-way costless collars – oil	Derivative liabilities	10		31

Basis swaps – natural gas	Derivative liabilities	5		69
Call options – natural gas	Derivative liabilities	11		70

Put options – natural gas	Derivative liabilities	5		—



Fixed price swaps – natural gas	Long-term derivative liabilities	45		281
Fixed price swaps – oil	Long-term derivative liabilities	1		4

Fixed price swaps – propane	Long-term derivative liabilities	1		—


Two-way costless collars – natural gas	Long-term derivative liabilities	37		56
Two-way costless collars – oil	Long-term derivative liabilities	1		—
Three-way costless collars – natural gas	Long-term derivative liabilities	66		20


Basis swap – natural gas	Long-term derivative liabilities	—		1
Call options – natural gas	Long-term derivative liabilities	36		18

Total derivative liabilities		$	406	$	1,699


Net Derivative Position
	September 30, 2023		December 31, 2022
(in millions)
Net current derivative asset (liability)	$	118	$	(1,174)
Net long-term derivative asset (liability)	(33)		(307)
Non-performance risk adjustment	(1)		3
Net total derivative asset (liability)	$	84	$	(1,478)

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The following tables summarize the before-tax effect of the Company’s derivative instruments on the consolidated statements of operations for the three and nine months ended September 30, 2023 and 2022:


Unsettled Gain (Loss) on Derivatives Recognized in Earnings

	Consolidated Statement of Operations Classification of Gain (Loss) on Derivatives, Unsettled	For the three months ended September 30,				For the nine months ended September 30,
Derivative Instrument		2023		2022		2023		2022

		(in millions)

Fixed price swaps – natural gas	Gain (Loss) on Derivatives	$	28	$	(140)	$	965	$	(1,654)
Fixed price swaps – oil	Gain (Loss) on Derivatives	(29)		73		(7)		39
Fixed price swaps – ethane	Gain (Loss) on Derivatives	(5)		24		(5)		(3)
Fixed price swaps – propane	Gain (Loss) on Derivatives	(37)		67		(8)		74
Fixed price swaps – normal butane	Gain (Loss) on Derivatives	(6)		24		1		24
Fixed price swaps – natural gasoline	Gain (Loss) on Derivatives	(9)		28		(2)		29
Two-way costless collars – natural gas	Gain (Loss) on Derivatives	3		(99)		233		(432)
Two-way costless collars – oil	Gain (Loss) on Derivatives	(4)		—		(3)		—
Two-way costless collars – ethane	Gain (Loss) on Derivatives	—		—		—		1

Three-way costless collars – natural gas	Gain (Loss) on Derivatives	20		(26)		310		(520)
Three-way costless collars – oil	Gain (Loss) on Derivatives	(1)		38		20		10
Three-way costless collars – propane	Gain (Loss) on Derivatives	—		3		—		4
Basis swaps – natural gas	Gain (Loss) on Derivatives	(43)		4		25		12
Call options – natural gas	Gain (Loss) on Derivatives	14		(8)		41		(114)

Put options – natural gas	Gain (Loss) on Derivatives	—		—		(4)		—


Fixed price swap – natural gas storage	Gain (Loss) on Derivatives	—		—		—		1
Interest rate swaps	Gain (Loss) on Derivatives	—		—		—		(2)
Total gain (loss) on unsettled derivatives		$	(69)	$	(12)	$	1,566	$	(2,531)

Settled Gain (Loss) on Derivatives Recognized in Earnings (1)

	Consolidated Statement of Operations Classification of Gain (Loss) on Derivatives, Settled	For the three months ended September 30,				For the nine months ended September 30,
Derivative Instrument		2023		2022		2023		2022

		(in millions)

Fixed price swaps – natural gas	Gain (Loss) on Derivatives	$	112	$	(1,082)	$	227	$	(2,249)
Fixed price swaps – oil	Gain (Loss) on Derivatives	(11)		(30)		(18)		(104)
Fixed price swaps – ethane	Gain (Loss) on Derivatives	(3)		(15)		3		(42)
Fixed price swaps – propane	Gain (Loss) on Derivatives	9		(21)		21		(96)
Fixed price swaps – normal butane	Gain (Loss) on Derivatives	1		(7)		2		(33)
Fixed price swaps – natural gasoline	Gain (Loss) on Derivatives	—		(9)		1		(45)
Two-way costless collars – natural gas	Gain (Loss) on Derivatives	13		(152)		44		(386)

Two-way costless collars – ethane	Gain (Loss) on Derivatives	—		—		—		(1)

Three-way costless collars – natural gas	Gain (Loss) on Derivatives	1		(491)		(15)		(1,008)
Three-way costless collars – oil	Gain (Loss) on Derivatives	(7)		(12)		(20)		(43)
Three-way costless collars – propane	Gain (Loss) on Derivatives	—		(1)		—		(4)
Basis swaps – natural gas	Gain (Loss) on Derivatives	47		40		11		64
Index swaps – natural gas	Gain (Loss) on Derivatives	—		—		—		(1)
Call options – natural gas	Gain (Loss) on Derivatives	—		(109)		(7)		(235)



Purchased fixed price swaps – natural gas	Gain (Loss) on Derivatives	—		—		—		1
Fixed price swaps – natural gas storage	Gain (Loss) on Derivatives	—		—		—		(3)

Total gain (loss) on settled derivatives		$	162	$	(1,889)	$	249	$	(4,185)

Total gain (loss) on derivatives (2)		$	93	$	(1,903)	$	1,811	$	(6,709)

(1)The Company calculates gain (loss) on derivatives, settled, as the summation of gains and losses on positions that settled within the period.

(2)Total gain (loss) on derivatives includes non-performance risk adjustments of $2 million in losses for the three months ended September 30, 2022 and $4 million in losses and $7 million in gains for the nine months ended September 30, 2023 and September 30, 2022, respectively.

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Total Gain (Loss) on Derivatives Recognized in Earnings
	For the three months ended September 30,				For the nine months ended September 30,
	2023		2022		2023		2022

	(in millions)
Total gain (loss) on unsettled derivatives	$	(69)	$	(12)	$	1,566	$	(2,531)
Total gain (loss) on settled derivatives	162		(1,889)		249		(4,185)
Non-performance risk adjustment	—		(2)		(4)		7
Total gain (loss) on derivatives	$	93	$	(1,903)	$	1,811	$	(6,709)

(8) RECLASSIFICATIONS FROM ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)

The following tables detail the components of accumulated other comprehensive income (loss) for the nine months ended September 30, 2023:


(in millions)	Pension and Other Postretirement		Foreign Currency		Total
Beginning balance December 31, 2022	$	20	$	(14)	$	6
Other comprehensive income before reclassifications	1		—		1
Amounts reclassified from other comprehensive income (1)	(16)		—		(16)
Net current-period other comprehensive loss	(15)		—		(15)
Ending balance September 30, 2023	$	5	$	(14)	$	(9)

(1)Includes a $2 million actuarial loss and a $14 million net tax loss attributable to the pension plan termination.

(9) FAIR VALUE MEASUREMENTS

The carrying amounts and estimated fair values of the Company’s financial instruments as of September 30, 2023 and December 31, 2022 were as follows:


	September 30, 2023				December 31, 2022
(in millions)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Cash and cash equivalents	$	26	$	26	$	50	$	50
2022 revolving credit facility due April 2027	388		388		250		250

Senior notes (1)	3,743		3,424		4,164		3,847
Derivative instruments, net	84		84		(1,478)		(1,478)

(1)Excludes unamortized debt issuance costs and debt discounts.

The fair value hierarchy prioritizes the inputs to valuation techniques used to measure fair value. As presented in the tables below, this hierarchy consists of three broad levels:

Level 1 valuations - Consist of unadjusted quoted prices in active markets for identical assets and liabilities and have the highest priority.

Level 2 valuations - Consist of quoted market information for the calculation of fair market value.

Level 3 valuations - Consist of internal estimates and have the lowest priority.

The carrying values of cash and cash equivalents, including marketable securities, accounts receivable, other current assets, accounts payable and other current liabilities on the consolidated balance sheets approximate fair value because of their short-term nature. For debt and derivative instruments, the following methods and assumptions were used to estimate fair value:

Debt: The fair values of the Company’s senior notes are based on the market value of the Company’s publicly traded debt as determined based on the market prices of the Company’s senior notes. The fair values of the Company’s senior notes are considered to be a Level 1 measurement as these are actively traded in the market. The carrying value of the borrowings under the Company’s 2022 credit facility (as defined in Note 10 below), to the extent utilized, approximates fair value because the interest rates are variable and reflective of market rates. The Company considers the fair value of its 2022 credit facility to be a Level 1 measurement on the fair value hierarchy.

Derivative Instruments: The Company measures the fair value of its derivative instruments based upon a pricing model that utilizes market-based inputs, including, but not limited to, the contractual price of the underlying position, current market

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prices, natural gas and liquids forward curves, discount rates for a similar duration of each outstanding position, volatility factors and non-performance risk. Non-performance risk considers the effect of the Company’s credit standing on the fair value of derivative liabilities and the effect of counterparty credit standing on the fair value of derivative assets. Both inputs to the model are based on published credit default swap rates and the duration of each outstanding derivative position. The Company’s net derivative position was a net asset as of September 30, 2023 and a net liability as of December 31, 2022. As of September 30, 2023 and December 31, 2022, the impact of the non-performance risk on the fair value of the Company’s net derivative position resulted in a reduction to the net asset of $1 million and a reduction to the net liability of $3 million, respectively.

The Company has classified its derivative instruments into levels depending upon the data utilized to determine their fair values. The Company’s fixed price swaps (Level 2) are estimated using third-party discounted cash flow calculations using the New York Mercantile Exchange (“NYMEX”) futures index for natural gas and oil derivatives and Oil Price Information Service (“OPIS”) for ethane and propane derivatives. The Company utilizes discounted cash flow models for valuing its interest rate derivatives (Level 2). The net derivative values attributable to the Company’s interest rate derivative contracts as of September 30, 2023 and December 31, 2022 are based on (i) the contracted notional amounts, (ii) active market-quoted yield curves and (iii) the applicable credit-adjusted risk-free rate yield curve. The Company had no interest rate swaps as of September 30, 2023 or December 31, 2022.

The Company’s call and put options, two-way costless collars and three-way costless collars (Level 2) are valued using the Black-Scholes model, an industry standard option valuation model that takes into account inputs such as contract terms, including maturity, and market parameters, including assumptions of the NYMEX and OPIS futures index, interest rates, volatility and credit worthiness. Inputs to the Black-Scholes model, including the volatility input, are obtained from a third-party pricing source, with independent verification of the most significant inputs on a monthly basis. An increase (decrease) in volatility would result in an increase (decrease) in fair value measurement, respectively.

The Company’s basis swaps (Level 2) are estimated using third-party calculations based upon forward commodity price curves.

Assets and liabilities measured at fair value on a recurring basis are summarized below:


	September 30, 2023
	Fair Value Measurements Using:
(in millions)	Quoted Prices in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Assets (Liabilities) at Fair Value
Assets

Fixed price swaps	$	—	$	263	$	—	$	263
Two-way costless collars	—		77		—		77
Three-way costless collars	—		105		—		105
Basis swaps	—		41		—		41

Put options	—		5		—		5


Liabilities

Fixed price swaps	—		(161)		—		(161)
Two-way costless collars	—		(73)		—		(73)
Three-way costless collars	—		(115)		—		(115)
Basis swaps	—		(5)		—		(5)
Call options	—		(47)		—		(47)
Put options	—		(5)		—		(5)



Total (1)	$	—	$	85	$	—	$	85

(1)Excludes a net reduction to the asset fair value of $1 million related to estimated non-performance risk.

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	December 31, 2022
	Fair Value Measurements Using:
(in millions)	Quoted Prices in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Assets (Liabilities) at Fair Value
Assets

Fixed price swaps	$	—	$	46	$	—	$	46
Two-way costless collars	—		65		—		65
Three-way costless collars	—		22		—		22
Basis swaps	—		81		—		81


Purchase Put - Natural Gas	—		4		—		4
Liabilities

Fixed price swaps	—		(888)		—		(888)
Two-way costless collars	—		(291)		—		(291)
Three-way costless collars	—		(362)		—		(362)
Basis swaps	—		(70)		—		(70)
Call options	—		(88)		—		(88)




Total (1)	$	—	$	(1,481)	$	—	$	(1,481)

(1)Excludes a net reduction to the liability fair value of $3 million related to estimated non-performance risk.

See Note 13 for a discussion of the fair value measurement of the Company’s pension plan assets.

(10) DEBT

The components of debt as of September 30, 2023 and December 31, 2022 consisted of the following:


	September 30, 2023
(in millions)	Debt Instrument		Unamortized Issuance Expense			Unamortized Debt Premium/Discount		Total





Variable rate (7.16% at September 30, 2023) 2022 revolving credit facility, due April 2027	$	388	$	—	(1)	$	—	$	388
4.95% Senior Notes due January 2025 (2)	389		(1)			—		388



8.375% Senior Notes due September 2028	304		(3)			—		301
5.375% Senior Notes due February 2029	700		(5)			19		714
5.375% Senior Notes due March 2030	1,200		(13)			—		1,187
4.75% Senior Notes due February 2032	1,150		(14)			—		1,136


Total debt	$	4,131	$	(36)		$	19	$	4,114

	December 31, 2022
(in millions)	Debt Instrument		Unamortized Issuance Expense			Unamortized Debt Premium/Discount		Total






Variable rate (6.15% at December 31, 2022) 2022 revolving credit facility, due April 2027	$	250	$	—	(1)	$	—	$	250
4.95% Senior Notes due January 2025 (2)	389		(1)			—		388

7.75% Senior Notes due October 2027	421		(3)			—		418
8.375% Senior Notes due September 2028	304		(3)			—		301
5.375% Senior Notes due February 2029	700		(5)			22		717
5.375% Senior Notes due March 2030	1,200		(16)			—		1,184
4.75% Senior Notes due February 2032	1,150		(16)			—		1,134


Total debt	$	4,414	$	(44)		$	22	$	4,392

(1)At September 30, 2023 and December 31, 2022, unamortized issuance expense of $16 million and $19 million, respectively, associated with the 2022 credit facility (as defined below) was classified as other long-term assets on the consolidated balance sheets.

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(2)Effective in July 2018, the interest rate was 6.20% for the 2025 Notes, reflecting a net downgrade in the Company’s bond ratings since the initial offering. On April 7, 2020, S&P downgraded the Company’s bond rating to BB-, which had the effect of increasing the interest rate on the 2025 Notes to 6.45% following the July 23, 2020 interest payment date. The first coupon payment to the bondholders at the higher interest rate was paid in January 2021. On September 1, 2021, S&P upgraded the Company’s bond rating to BB, and on January 6, 2022, S&P further upgraded the Company’s bond rating to BB+, which decreased the interest rate on the 2025 Notes to 5.95% beginning with coupon payments paid after January 2022. On May 31, 2022, Moody’s upgraded the Company’s bond rating to Ba1, which decreased the interest rate on the 2025 Notes from 5.95% to 5.70% for coupon payments paid after July 2022.

The following is a summary of scheduled debt maturities by year as of September 30, 2023:


(in millions)
2023	$	—
2024	—
2025	389
2026	—
2027	388
Thereafter	3,354
	$	4,131

Credit Facilities

2022 Credit Facility

On April 8, 2022, the Company entered into an Amended and Restated Credit Agreement that replaces its previous credit facility with a group of banks, that as amended, has a maturity date of April 2027 (the “2022 credit facility”). As of September 30, 2023, the 2022 credit facility has an aggregate maximum revolving credit amount and borrowing base of $3.5 billion and elected five-year revolving commitments of $2.0 billion (the “Five-Year Tranche”). The borrowing base is subject to redetermination at least twice a year, which typically occurs in April and October, and is secured by substantially all of the assets owned by the Company and its subsidiaries. On October 4, 2023, the Company’s borrowing base was reaffirmed at $3.5 billion and the Five-Year Tranche was reaffirmed at $2.0 billion and has a maturity date of April 8, 2027.

Effective August 4, 2022, the Company elected to temporarily increase commitments under the 2022 credit facility by $500 million (the “Short-Term Tranche”) as a temporary working capital liquidity resource. The Company had no borrowings under the Short-Term Tranche which expired on April 30, 2023 and was not renewed.

The Company may utilize the 2022 credit facility in the form of loans and letters of credit. Loans under the Five-Year Tranche of the 2022 credit facility are subject to varying rates of interest based on whether the loan is a Secured Overnight Financing Rate (“SOFR”) loan or an alternate base rate loan. Term SOFR loans bear interest at term SOFR plus an applicable rate ranging from 1.75% to 2.75% based on the Company’s utilization of the Five-Year Tranche of the 2022 credit facility, plus a 0.10% credit spread adjustment. Base rate loans bear interest at a base rate per year equal to the greatest of: (i) the prime rate; (ii) the federal funds effective rate plus 0.50%; and (iii) the adjusted term SOFR rate for a one-month interest period plus 1.00%, plus an applicable margin ranging from 0.75% to 1.75%, depending on the percentage of the commitments utilized. Commitment fees on unused commitment amounts under the Five-Year Tranche of the 2022 credit facility range between 0.375% to 0.50%, depending on the percentage of the commitments utilized.

The 2022 credit facility contains customary representations and warranties and covenants including, among others, the following:

•A prohibition against incurring debt, subject to permitted exceptions;

•A restriction on creating liens on assets, subject to permitted exceptions;

•Restrictions on mergers and asset dispositions;

•Restrictions on use of proceeds, investments, declaring dividends, repurchasing junior debt, transactions with affiliates, or change of principal business; and

•Maintenance of the following financial covenants, commencing with the fiscal quarter ended March 31, 2022:

1.Minimum current ratio of not less than 1.00 to 1.00, whereby current ratio is defined as the Company’s consolidated current assets (including unused commitments under the credit agreement, but excluding non-cash

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derivative assets) to consolidated current liabilities (excluding non-cash derivative obligations and current maturities of long-term debt).

2.Maximum total net leverage ratio of not greater than, with respect to the prior four fiscal quarters ending on or after March 31, 2022, 4.00 to 1.00. Total net leverage ratio is defined as total debt less cash on hand (up to the lesser of 10% of credit limit or $150 million) divided by consolidated EBITDAX for the last four consecutive quarters. EBITDAX, as defined in the credit agreement governing the Company’s 2022 credit facility, excludes the effects of interest expense, depreciation, depletion and amortization, income tax, any non-cash impacts from impairments, certain non-cash hedging activities, stock-based compensation expense, non-cash gains or losses on asset sales, unamortized issuance cost, unamortized debt discount and certain restructuring costs.

The 2022 credit facility contains customary events of default that include, among other things, the failure to comply with the financial covenants described above, non-payment of principal, interest or fees, violation of covenants, inaccuracy of representations and warranties, bankruptcy and insolvency events, material judgments and cross-defaults to material indebtedness. If an event of default occurs and is continuing, all amounts outstanding under the 2022 credit facility may become immediately due and payable. As of September 30, 2023, the Company was in compliance with all of the covenants of the credit agreement in all material respects.

Currently, each United States domestic subsidiary of the Company for which the Company owns 100% of its equity guarantees the 2022 credit facility. Pursuant to requirements under the indentures governing its senior notes, each subsidiary that becomes a guarantor of the 2022 credit facility also must become a guarantor of each of the Company’s senior notes.

Certain features of the facility depend on whether Southwestern has obtained any of the following ratings:

•An unsecured long-term debt credit rating (an “Index Debt Rating”) of BBB- or higher with S&P;

•An Index Debt Rating of Baa3 or higher with Moody’s; or

•An Index Debt Rating of BBB- or higher with Fitch (each of the foregoing an “Investment Grade Rating”).

Upon receiving one Investment Grade Rating from either S&P or Moody’s and delivering a certification to the administrative agent (the period beginning at such time, an “Interim Investment Grade Period”), amongst other changes, the following occurs:

•The Guarantors may be released from their guarantees;

•The collateral under the facility will be released;

•The facility will no longer be subject to a borrowing base; and

•Certain title and collateral-related covenants will no longer be applicable.

During the Interim Investment Grade Period, the Company will be required to maintain compliance with the existing financial covenants as well as a PV-9 coverage ratio of the net present value, discounted at 9% per annum, of the estimated future net revenues expected in the proved reserves to the Company’s total indebtedness as of such date of not less than 1.50 to 1.00 (“PV-9 Coverage Ratio”). In addition, during an Interim Investment Grade Period or Investment Grade Period (as defined below), term SOFR loans will bear interest at term SOFR plus an applicable rate ranging from 1.25% to 1.875%, depending on the Company’s Index Debt Rating (as defined in the 2022 credit facility), plus an additional 0.10% credit spread adjustment. Base rate loans will bear interest at the base rate described above plus an applicable rate ranging from 0.25% to 0.875%, depending on the Company’s Index Debt Rating. During an Interim Investment Grade Period or Investment Grade Period (defined below), the commitment fee on unused commitment amounts under the facility will range from 0.15% to 0.275%, depending on the Company’s Index Debt Rating.

The Interim Investment Grade Period will end, and the facility will revert to its characteristics prior to the Interim Investment Grade Period, including being guaranteed by the Guarantors, being secured by collateral and being subject to a borrowing base, having applicable margins and commitment fee determined based on percentage of commitments utilized, as well as limited to compliance with the leverage ratio and current ratio financial covenants but not the PV-9 Coverage Ratio if both of the following are achieved during the Interim Investment Grade Period:

•An Index Debt Rating from Moody’s that is Ba2 or lower; and

•An Index Debt Rating from S&P that is BB or lower.

Upon receiving two Investment Grade Ratings from S&P, Moody’s, or Fitch (such period following, an “Investment Grade Period”), certain restrictive covenants fall away or become more permissive. Upon Investment Grade Period, the leverage ratio and current ratio financial covenants and PV-9 Coverage Ratio will no longer be effective, and the Company will be required to

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maintain compliance with a total indebtedness to capitalization ratio, which is the ratio of the Company’s total indebtedness to the sum of total indebtedness plus stockholders’ equity, not to exceed 65%.

As of September 30, 2023, the Company had no outstanding letters of credit and $388 million in borrowings outstanding under the 2022 credit facility. The Company currently does not anticipate being required to supply a materially greater amount of letters of credit under its existing contracts.

Senior Notes

In January 2015, the Company completed a public offering of $1.0 billion aggregate principal amount of its 4.95% Senior Notes due 2025 (the “2025 Notes”). The interest rate on the 2025 Notes is determined based upon the public bond ratings from Moody’s and S&P. Downgrades on the 2025 Notes from either rating agency increase interest costs by 25 basis points per downgrade level and upgrades decrease interest costs by 25 basis points per upgrade level, up to the stated coupon rate, on the following semi-annual bond interest payment. Effective in July 2018, the interest rate for the 2025 Notes was 6.20%, reflecting a net downgrade in the Company’s bond ratings since their issuance. On April 7, 2020, S&P downgraded the Company’s bond rating to BB-, which had the effect of increasing the interest rate on the 2025 Notes to 6.45% following the July 23, 2020 interest payment due date. The first coupon payment to the 2025 Notes bondholders at the higher interest rate was paid in January 2021. On September 1, 2021, S&P upgraded the Company’s bond rating to BB, and on January 6, 2022, S&P further upgraded the Company’s bond rating to BB+, which decreased the interest rate on the 2025 Notes to 5.95% beginning with coupon payments paid after January 2022. On May 31, 2022, Moody’s upgraded the Company’s bond rating to Ba1, which decreased the interest rate on the 2025 Notes from 5.95% to 5.70% for coupon payments paid after July 2022.

During the nine months ended September 30, 2022, the Company redeemed the remaining outstanding principal balance of $201 million of its 4.10% Senior Notes due 2022, $46 million of its 8.375% Senior Notes due 2028 and $19 million of its 7.75% Senior Notes due 2027 for a total of $272 million, and recognized a $6 million loss on debt extinguishment.

On February 26, 2023, the Company redeemed all of its outstanding 7.75% Senior Notes due 2027 (the “2027 Notes”) at a redemption price equal to 103.875% of the outstanding principal amount plus accrued interest of $13 million for a total payment of $450 million. The Company recognized a $19 million loss on the extinguishment of debt, which included the write-off of $3 million in related unamortized debt discounts and debt issuance costs. The Company funded the redemption of the 2027 Notes using approximately $316 million of cash on hand and approximately $134 million of borrowings under the 2022 credit facility.

(11) COMMITMENTS AND CONTINGENCIES

Operating Commitments and Contingencies

As of September 30, 2023, the Company’s contractual obligations for demand and similar charges under firm transportation and gathering agreements to guarantee access capacity on natural gas and liquids pipelines and gathering systems totaled approximately $9.7 billion, $1.2 billion of which related to access capacity on future pipeline and gathering infrastructure projects that still require the granting of regulatory approvals and additional construction efforts. As of September 30, 2023, the Company also had guarantee obligations of up to $825 million of that total amount. As of September 30, 2023, future payments under non-cancelable firm transportation and gathering agreements were as follows:


	Payments Due by Period
(in millions)	Total		Less than 1 Year		1 to 3 Years		3 to 5 Years		5 to 8 Years		More than 8 Years
Infrastructure currently in service	$	8,454	$	955	$	1,979	$	1,768	$	1,796	$	1,956
Pending regulatory approval and/or construction (1)	1,239		46		187		217		322		467
Total transportation charges	$	9,693	$	1,001	$	2,166	$	1,985	$	2,118	$	2,423

(1)Based on estimated in-service dates as of September 30, 2023.

Environmental Risk

The Company is subject to laws and regulations relating to the protection of the environment. Environmental and cleanup related costs of a non-capital nature are accrued when it is both probable that a liability has been incurred and when the amount can be reasonably estimated. Management believes any future remediation or other compliance related costs will not have a material effect on the financial position, results of operations or cash flows of the Company.

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Litigation

The Company is subject to various litigation, claims and proceedings, most of which have arisen in the ordinary course of business, such as for alleged breaches of contract, miscalculation of royalties, employment matters, traffic accidents, pollution, contamination, encroachment on others’ property or nuisance. The Company accrues for litigation, claims and proceedings when a liability is both probable and the amount can be reasonably estimated. As of September 30, 2023, the Company does not currently have any material amounts accrued related to litigation matters, including the case discussed below. For any matters not accrued for, it is not possible at this time to estimate the amount of any additional loss, or range of loss, that is reasonably possible, but, based on the nature of the claims, management believes that current litigation, claims and proceedings, individually or in aggregate and after taking into account insurance, are not likely to have a material adverse impact on the Company’s financial position, results of operations or cash flows, for the period in which the effect of that outcome becomes reasonably estimable. Many of these matters are in early stages, so the allegations and the damage theories have not been fully developed, and are all subject to inherent uncertainties; therefore, management’s view may change in the future.

Bryant Litigation

As discussed in Note 2, on September 1, 2021, the Company completed its merger with Indigo, resulting in the assumption of Indigo’s existing litigation.

On June 12, 2018, a collection of 51 individuals and entities filed a lawsuit against fifteen oil and gas company defendants, including Indigo, in Louisiana state court claiming damages arising out of current and historical development and production activity on certain acreage located in DeSoto Parish, Louisiana. The plaintiffs, who claim to own the properties at issue, assert that Indigo’s actions and the actions of other current operators conducting development and production activity, combined with the improper plugging and abandoning of legacy wells by former operators, have caused environmental contamination to their properties. Among other things, the plaintiffs contend that the defendants’ conduct resulted in the migration of natural gas, along with oilfield contaminants, into the Carrizo-Wilcox aquifer system underlying certain portions of DeSoto Parish. The plaintiffs assert claims based in tort, breach of contract and for violations of the Louisiana Civil and Mineral Codes, and they seek injunctive relief and monetary damages in an unspecified amount, including punitive damages.

On September 13, 2018, Indigo filed a variety of exceptions in response to the plaintiffs’ petition in this matter. Since the initial filing, supplemental petitions have been filed joining additional individuals and entities as plaintiffs in the matter. On September 29, 2020, plaintiffs filed their fourth supplemental and amending petition in response to the court’s order ruling that plaintiffs’ claims were improperly vague and failed to identify with reasonable specificity the defendants’ allegedly wrongful conduct. Indigo and the majority of the other defendants filed several exceptions to plaintiffs’ fourth amended petition challenging the sufficiency of plaintiffs’ allegations and seeking dismissal of certain claims. On February 18, 2021, plaintiffs filed a fifth supplemental and amending petition, which seeks to augment the claims of select plaintiffs. On October 11, 2021, a sixth supplemental petition was filed which seeks to add the Company as a party to the litigation which the Company has opposed. Plaintiffs later filed seventh and eighth supplemental petitions naming additional defendants. Fact discovery for the case is ongoing.

The presence of natural gas in a localized area of the Carrizo-Wilcox aquifer system in DeSoto Parish is currently the subject of a regulatory investigation by the Louisiana Office of Conservation (“Conservation”), and the Company is cooperating and coordinating with Conservation in that investigation. The Conservation matter number is EMER18-003.

The Company does not currently expect this matter to have a material impact on its financial position, results of operations, cash flows or liquidity.

Indemnifications

The Company has provided certain indemnifications to various third parties, including in relation to asset and entity dispositions, securities offerings and other financings. In the case of asset dispositions, these indemnifications typically relate to disputes, litigation or tax matters existing at the date of disposition. The Company likewise obtains indemnification for future matters when it sells assets, although there is no assurance the buyer will be capable of performing those obligations. In the case of equity offerings, these indemnifications typically relate to claims asserted against underwriters in connection with an offering. No material liabilities have been recognized in connection with these indemnifications.

(12) INCOME TAXES

The Company’s effective tax rate was approximately 33% and 1% for the three and nine months ended September 30, 2023, respectively, primarily as a result of the release of valuation allowances against the Company’s U.S. deferred tax assets throughout 2023. A valuation allowance for deferred tax assets, including net operating losses (“NOLs”), is recognized when it is more likely than not that some or all of the benefit from the deferred tax assets will not be realized. To assess that likelihood,

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the Company uses estimates and judgment regarding future taxable income and considers the tax consequences in the jurisdiction where such taxable income is generated, to determine whether a valuation allowance is required. Such evidence can include current financial position, results of operations, both actual and forecasted, the reversal of deferred tax liabilities and tax planning strategies as well as the current and forecasted business economics of the oil and gas industry.

For the year ended December 31, 2022, the Company maintained a full valuation allowance against its deferred tax assets based on its conclusion, considering all available evidence (both positive and negative), that it was more likely than not that the deferred tax assets would not be realized. A significant item of objective negative evidence considered was the cumulative pre-tax loss incurred over the three-year period ended December 31, 2022, primarily due to impairments of proved oil and gas properties recognized in 2020. As of the first quarter of 2023, the Company sustained a three-year cumulative level of profitability. Based on this factor and other positive evidence such as forecasted income, the Company concluded that $523 million of its federal and state deferred tax assets were more likely than not to be realized and plan to release this portion of the valuation allowance in 2023. Accordingly, during the nine months ended September 30, 2023, the Company recognized $520 million of deferred income tax expense related to recording its tax provision which was partially offset by $492 million of tax benefit attributable to the release of the valuation allowance. The remaining valuation allowance will be released during the fourth quarter of 2023. The Company expects to keep a valuation allowance of $66 million related to NOLs in jurisdictions in which it no longer operates and against the portion of its federal and state deferred tax assets such as capital losses and interest carryovers, which may expire before being fully utilized due to the application of the limitations under Section 382 and the ordering in which such attributes may be applied.

Due to the issuance of common stock associated with the Indigo Merger, the Company incurred a cumulative ownership change and as such, the Company’s NOLs prior to the acquisition are subject to an annual limitation under Internal Revenue Code Section 382 of approximately $48 million. The ownership changes and resulting annual limitation will result in the expiration of NOLs or other tax attributes otherwise available. At September 30, 2023, the Company had approximately $4 billion of federal NOL carryovers, of which approximately $3 billion expire between 2035 and 2037 and $1 billion have an indefinite carryforward life. The Company currently estimates that approximately $2 billion of these federal NOLs will expire before they are able to be used and accordingly, no value has been ascribed to these NOLs on the Company’s balance sheet. If a subsequent ownership change were to occur as a result of future transactions in the Company’s common stock, the Company’s use of remaining U.S. tax attributes may be further limited.

(13) PENSION PLAN AND OTHER POSTRETIREMENT BENEFITS

Prior to January 1, 2021, substantially all of the Company’s employees were covered by the defined benefit pension plan, a cash balance plan that provided benefits based upon a fixed percentage of an employee’s annual compensation (the “Plan”). As part of an ongoing effort to reduce costs, the Company elected to freeze the Plan effective January 1, 2021. Employees that were participants in the Plan prior to January 1, 2021 continued to receive the interest component of the Plan but no longer received the service component. On September 13, 2021, the Compensation Committee of the Board approved terminating the Plan, effective December 31, 2021. This decision, among other benefits, will provide Plan participants quicker access to, and greater flexibility in, the management of participants’ respective benefits due under the Plan.

The Company commenced the Plan termination process, and, on April 6, 2022, the Internal Revenue Service issued a favorable determination letter, concurring that the Plan met all of the qualification requirements under the Internal Revenue Code. In December 2022, the Company distributed approximately $38 million of the Plan’s assets to participants in the form of lump sum payments in connection with a limited distribution window provided to all active and former employee participants as part of the Plan termination process.

In March 2023, the Company entered into a group annuity contract with a qualified insurance company relating to the Plan. Under the group annuity contract, the Company purchased an irrevocable nonparticipating single premium group annuity contract from the insurer and transferred to the insurer the future benefit obligations and annuity administration for remaining retirees and beneficiaries under the Plan.

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Upon issuance of the group annuity contract, the pension benefit obligations and annuity administration for the remaining participants was irrevocably transferred from the Plan to the insurer. By transferring these obligations through the payment to the insurer in March 2023, the Company has no remaining obligations under the Plan or any other U.S. tax-qualified defined benefit pension plan. The purchase of the group annuity contract was funded directly by the assets of the Plan. The Company recognized a pre-tax non-cash pension settlement charge of approximately $2 million during the nine months ended September 30, 2023 as a result of the settlement of the Plan.

The Company transferred the remaining residual Plan assets balance of approximately $14 million to a qualified replacement plan in September 2023 and expects to close the Plan during the fourth quarter of 2023.

The postretirement benefit plan provides contributory health care and life insurance benefits. Employees become eligible for these benefits if they meet age and service requirements. Generally, the benefits paid are a stated percentage of medical expenses reduced by deductibles and other coverages.

Substantially all of the Company’s employees continue to be covered by the postretirement benefit plans. The Company accounts for its defined benefit pension and other postretirement plans by recognizing the funded status of each defined pension benefit plan and other postretirement benefit plan on the Company’s balance sheet. In the event a plan is overfunded, the Company recognizes an asset. Conversely, if a plan is underfunded, the Company recognizes a liability.

Net periodic pension costs include the following components for the three and nine months ended September 30, 2023 and 2022:



	Consolidated Statements of Operations Classification of Net Periodic Benefit Cost	For the three months ended September 30,				For the nine months ended September 30,
(in millions)		2023		2022		2023		2022
Service cost	General and administrative expenses	$	—	$	—	$	—	$	—
Interest cost	Other Income (Loss), Net	—		1		—		3
Expected return on plan assets	Other Income (Loss), Net	—		—		—		—
Amortization of prior service cost	Other Income (Loss), Net	—		—		(1)		(1)

Settlement loss	Other Income (Loss), Net	—		—		2		—
Net periodic benefit cost		$	—	$	1	$	1	$	2

The Company’s other postretirement benefit plan had a net periodic benefit cost of less than $1 million for both the three months ended September 30, 2023 and September 30, 2022, and approximately $1 million for both the nine months ended September 30, 2023 and September 30, 2022.

The Company did not make any contributions to the Plan during 2023 and recognized no residual pension assets related to its pension benefits as of September 30, 2023 as the assets were transferred to a qualified replacement plan. The Company recognized a pension asset of approximately $15 million related to its pension benefits as of December 31, 2022. The Company recognized liabilities of approximately $10 million and $9 million related to its other postretirement benefits as of September 30, 2023 and December 31, 2022, respectively.

The Company maintains a non-qualified deferred compensation supplemental retirement savings plan (“Non-Qualified Plan”) for certain key employees who may elect to defer and contribute a portion of their compensation, as permitted by the Non-Qualified Plan. Shares of the Company’s common stock purchased under the terms of the Non-Qualified Plan are included in treasury stock and totaled 1,455 shares at September 30, 2023 and 1,743 shares at December 31, 2022.

(14) LONG-TERM INCENTIVE COMPENSATION

The Company’s long-term incentive compensation plans consist of a combination of stock-based awards that derive their value directly or indirectly from the Company’s common stock price, and cash-based awards that are fixed in amount but subject to meeting annual performance thresholds.

Stock-Based Compensation

The Company’s stock-based compensation is classified as either equity awards or liability awards in accordance with GAAP. The fair value of an equity-classified award is determined at the grant date and is amortized to general and administrative expense on a straight-line basis over the vesting period of the award. A portion of this general and administrative expense is capitalized into natural gas and oil properties, included in property and equipment. The fair value of a liability-classified award is determined on a quarterly basis beginning at the grant date until final vesting. Changes in the fair value of liability-classified awards are recorded to general and administrative expense and capitalized expense over the vesting period of

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the award. Generally, stock options granted to employees and directors vest ratably over three years from the grant date and expire 10 years from the date of grant. However, the Company has not granted stock options since 2017. The Company issues shares of restricted stock and restricted stock units to employees and directors which generally vest over three years.

Restricted stock, restricted stock units and stock options granted under the Southwestern Energy Company 2022 Incentive Plan (the “2022 Plan”) immediately vest upon death, disability or retirement (subject to a minimum of three years of service). To the extent no provision is made in connection with a “change in control” (as defined in the 2022 Plan) for the assumption of awards previously granted under the 2022 Plan or there is no substitution of such awards for new awards, then (i) outstanding time-based awards will become fully vested, and (ii) each outstanding performance-based award will vest with respect to the number of shares of common stock underlying such award or the amount of cash underlying the award eligible to vest based on performance during the performance period that includes the date of the change in control, prorated for the number of days which have elapsed during the performance period prior to the change in control. To the extent an award is assumed or substituted in connection with the change in control, if a participant is terminated by the Company without “cause” or the participant resigns for “good reason” (each as defined in the 2022 Plan) within 12 months following a change in control, then (i) each time-based award will become fully vested, and (ii) each outstanding performance-based award will vest based on performance during the performance period that includes the date of the change in control, prorated for the number of days which have elapsed during the performance period prior to such termination.

The Company issues performance unit awards to employees which historically have vested at or over three years. The performance units granted in 2021, 2022 and 2023 cliff-vest at the end of three years.

The Company recognized the following amounts in total related to long-term incentive compensation costs for the three and nine months ended September 30, 2023 and 2022:


	For the three months ended September 30,				For the nine months ended September 30,
(in millions)	2023		2022		2023		2022
Long-term incentive compensation – expensed	$	7	$	6	$	18	$	24
Long-term incentive compensation – capitalized	$	4	$	4	$	11	$	15

Equity-Classified Awards

The Company recognized the following amounts in employee equity-classified stock-based compensation costs for the three and nine months ended September 30, 2023 and 2022:


	For the three months ended September 30,				For the nine months ended September 30,
(in millions)	2023		2022		2023		2022
Equity-classified awards – expensed	$	2	$	1	$	7	$	4
Equity-classified awards – capitalized	$	1	$	—	$	2	$	—

Equity-Classified Stock Options

The following table summarizes equity-classified stock option activity for the nine months ended September 30, 2023 and provides information for options outstanding and options exercisable as of September 30, 2023:


	Number of Options	Weighted Average Exercise Price
	(in thousands)
Outstanding at December 31, 2022	997	$	8.59
Granted	—	$	—
Exercised	—	$	—
Forfeited or expired	(177)	$	8.60
Outstanding at September 30, 2023	820	$	8.59
Exercisable at September 30, 2023	820	$	8.59

Equity-Classified Restricted Stock

As of September 30, 2023, there was less than $1 million of total unrecognized compensation cost related to the Company’s unvested equity-classified restricted stock grants. This cost is expected to be recognized over a weighted-average period of 0.6 years. The following table summarizes equity-classified restricted stock activity for the nine months ended September 30, 2023 and provides information for unvested shares as of September 30, 2023:

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	Number of Shares	Weighted Average Fair Value
	(in thousands)
Unvested shares at December 31, 2022	211	$	5.81
Granted	336	$	5.34
Vested	(378)	$	5.71
Forfeited	—	$	—
Unvested shares at September 30, 2023	169	$	5.09

Equity-Classified Restricted Stock Units

As of September 30, 2023, there was $8 million of total unrecognized compensation cost related to the Company’s unvested equity-classified restricted stock units. This cost is expected to be recognized over a weighted-average period of 1.6 years. The following table summarizes equity-classified restricted stock units for the nine months ended September 30, 2023 and provides information for unvested units as of September 30, 2023.


	Number of Shares	Weighted Average Fair Value
	(in thousands)
Unvested units at December 31, 2022	1,645	$	4.44
Granted	1,539	$	4.83
Vested	(555)	$	4.42
Forfeited	(1)	$	3.05
Unvested units at September 30, 2023	2,628	$	4.67

Equity-Classified Performance Units

In each year beginning with 2018, the Company granted performance units that vest at the end of, or over, a three-year period and are payable in either cash or shares. The performance units granted from 2020 through 2021 were accounted for as liability-classified awards as further described below. In 2022 and 2023, two types of performance units were granted. The first type of awards were liability-classified given the awards are payable only in cash as prescribed under the compensation agreements. The second type of awards granted during 2022 and 2023 have been accounted for as equity-classified awards given the intention to settle these awards in stock. The equity-classified awards were recognized at their fair value as of the grant date and are amortized throughout the vesting period. The 2022 and 2023 performance unit awards include a market condition based on relative TSR (as defined below). The fair values of the market conditions were calculated by Monte Carlo models as of the grant date. As of September 30, 2023, there was $7 million of total unrecognized compensation costs related to the Company’s unvested equity-classified performance units. This cost is expected to be recognized over a weighted-average period of 2.1 years.


	Number of Shares	Weighted Average Fair Value
	(in thousands)
Unvested units at December 31, 2022	817	$	6.04
Granted	940	$	6.12
Vested	—	$	—
Forfeited	—	$	—
Unvested units at September 30, 2023	1,757	$	6.08

Liability-Classified Awards

The Company recognized the following amounts in employee liability-classified stock-based compensation costs for the three and nine months ended September 30, 2023:


	For the three months ended September 30,				For the nine months ended September 30,
(in millions)	2023		2022		2023		2022
Liability-classified stock-based compensation cost – expensed	$	2	$	3	$	3	$	15
Liability-classified stock-based compensation cost – capitalized	$	1	$	2	$	2	$	10

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Liability-Classified Restricted Stock Units

In the first quarter of each year beginning with 2018, the Company granted restricted stock units that vest over a period of four years and are payable in either cash or shares at the option of the Compensation Committee of the Company’s Board. The liability-classified awards granted in 2021 vest over a period of three years. The Company has accounted for these as liability-classified awards, and accordingly changes in the market value of the instruments will be recorded to general and administrative expense and capitalized expense over the vesting period of the award. As of September 30, 2023, there was $3 million of total unrecognized compensation cost related to liability-classified restricted stock units that is expected to be recognized over a weighted-average period of 0.4 years. The amount of unrecognized compensation cost for liability-classified awards will fluctuate over time as they are marked to market.


	Number of Units	Weighted Average Fair Value
	(in thousands)
Unvested units at December 31, 2022	3,950	$	4.81
Granted	—	$	—
Vested	(2,206)	$	4.84
Forfeited	(3)	$	5.57
Unvested units at September 30, 2023	1,741	$	4.61

Liability-Classified Performance Units

In each year beginning with 2018, the Company granted performance units that vest at the end of, or over, a three-year period and are payable in either cash or shares. The performance units granted in 2020 vest over a three-year period and are payable in cash as prescribed under the compensation agreements and have been accounted for as liability-classified awards. The Company granted two types of performance units in 2021 that vest over a three-year period. One type is payable in cash as prescribed under the compensation agreements and the other type is payable in either cash or stock at the option of the Compensation Committee of the Company’s Board. Both award types have been accounted for as liability-classified awards. The Company granted two types of performance units in 2022 and 2023 that vest over a three-year period. For both 2022 and 2023, one type of award is payable in cash as prescribed under the compensation agreements and has been liability-classified while the other type is equity-classified as further discussed above. Changes in the fair market value of the instruments for liability-classified awards will be recorded to general and administrative expense and capitalized expense over the vesting period of the awards.

The performance units granted in 2020 include a performance condition based on return on average capital employed and a market condition based on relative total shareholder return (“TSR”). In 2021, of the two types of performance units granted, the first type of award includes a performance condition based on return on capital employed and a performance condition based on reinvestment rate, and the second type of award includes one market condition based on relative TSR. The liability-classified performance units granted in 2022 and 2023 include performance conditions based on return on capital employed and reinvestment rate. The fair values of all market conditions discussed above are calculated by Monte Carlo models on a quarterly basis.

As of September 30, 2023, there was $7 million of total unrecognized compensation cost related to liability-classified performance units. This cost is expected to be recognized over a weighted-average period of 2.1 years. The amount of unrecognized compensation cost for liability-classified awards will fluctuate over time as they are marked to market. The final value of the performance unit awards is contingent upon the Company’s actual performance against these performance measures.


	Number of Units	Weighted Average Fair Value
	(in thousands)
Unvested units at December 31, 2022	10,982	$	2.25
Granted	5,136	$	4.83
Vested	(3,966)	$	6.13
Forfeited	—	$	—
Unvested units at September 30, 2023	12,152	$	1.15

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Cash-Based Compensation

The Company recognized the following amounts in performance cash award compensation costs for the three and nine months ended September 30, 2023 and 2022:


	For the three months ended September 30,				For the nine months ended September 30,
(in millions)	2023		2022		2023		2022
Performance cash awards – expensed	$	3	$	2	$	8	$	5
Performance cash awards – capitalized	$	2	$	2	$	7	$	5

Performance Cash Awards

From 2020 through 2022 the Company granted performance cash awards that vest over a four-year period and are payable in cash on an annual basis. In 2023, the Company granted performance cash awards that vest over a three-year period and are payable in cash on an annual basis. The value of each unit of the award equals one dollar. The Company recognizes the cost of these awards as general and administrative expense and capitalized expense over the vesting period of the awards. The performance cash awards granted from 2020 through 2023 include a performance condition determined annually by the Company. For all years, the performance measure is a targeted discretionary cash flow amount. If the Company, in its sole discretion, determines that the threshold was not met, the amount for that vesting period will not vest and will be cancelled. As of September 30, 2023, there was $38 million of total unrecognized compensation cost related to performance cash awards. This cost is expected to be recognized over a weighted-average period of 2.2 years. The final value of the performance cash awards is contingent upon the Company’s actual performance against these performance measures.


	Number of Units	Weighted Average Fair Value
	(in thousands)
Unvested units at December 31, 2022	39,994	$	1.00
Granted	27,493	$	1.00
Vested	(13,250)	$	1.00
Forfeited	(3,761)	$	1.00
Unvested units at September 30, 2023	50,476	$	1.00

(15) SEGMENT INFORMATION

The Company’s reportable business segments have been identified based on the differences in products or services provided. The Company’s E&P segment is comprised of gas and oil properties which are managed as a whole rather than through discrete operating segments. Operational information for the Company’s E&P segment is tracked by geographic area; however, financial performance and allocation of resources are assessed at the segment level without regard to geographic area. Revenues for the E&P segment are derived from the production and sale of natural gas and liquids. The Marketing segment generates revenue through the marketing of both Company and third-party produced natural gas and liquids volumes.

Summarized financial information for the Company’s reportable segments is shown in the following table. The accounting policies of the segments are the same as those described in Note 1 of the Notes to Consolidated Financial Statements included in Item 8 of the 2022 Annual Report. Management evaluates the performance of its segments based on operating income, defined as operating revenues less operating costs. Income before income taxes, for the purpose of reconciling the operating income amount shown below to consolidated income before income taxes, is the sum of operating income, interest expense, gain (loss) on derivatives, gain on early extinguishment of debt and other income (loss). The “Other” column includes items not related to the Company’s reportable segments, including real estate and corporate items. Corporate general and administrative costs, depreciation expense and taxes, other than income taxes, are allocated to the segments.

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	Exploration and Production			Marketing		Other		Total

Three months ended September 30, 2023	(in millions)
Revenues from external customers	$	890		$	553	$	—	$	1,443
Intersegment revenues	(17)			826		—		809
Depreciation, depletion and amortization expense	337			1		—		338

Operating income (loss)	(18)			25		—		7
Interest expense (1)	36			—		—		36
Gain on derivatives	93			—		—		93

Other income, net	1			—		1		2
Provision for income taxes (1)	21			—		—		21
Assets	12,350		(2)	483		140		12,973
Capital investments (3)	452			—		2		454

Three months ended September 30, 2022
Revenues from external customers	$	3,243		$	1,298	$	—	$	4,541
Intersegment revenues	4			3,138		—		3,142
Depreciation, depletion and amortization expense	297			1		—		298

Operating income	2,386			28		—		2,414
Interest expense (1)	50			—		—		50
Loss on derivatives	(1,903)			—		—		(1,903)


Provision for income taxes (1)	11			—		—		11
Assets	11,359		(2)	1,633		112		13,104
Capital investments (3)	540			—		3		543


	Exploration and Production			Marketing		Other		Total

Nine months ended September 30, 2023	(in millions)
Revenues from external customers	$	3,123		$	1,707	$	—	$	4,830
Intersegment revenues	(44)			2,944		—		2,900
Depreciation, depletion and amortization expense	975			4		—		979

Operating income	490			66		—		556
Interest expense (1)	106			—		—		106
Gain on derivatives	1,811			—		—		1,811
Loss on extinguishment of debt	—			—		(19)		(19)
Other income, net	—			—		1		1
Provision for income taxes (1)	28			—		—		28
Assets	12,350		(2)	483		140		12,973
Capital investments (3)	1,709			—		5		1,714

Nine months ended September 30, 2022
Revenues from external customers	$	8,251		$	3,371	$	—	$	11,622
Intersegment revenues	(1)			7,843		—		7,842
Depreciation, depletion and amortization expense	857			4		—		861

Operating income	5,784		(4)	60		—		5,844
Interest expense (1)	139			—		—		139
Loss on derivatives	(6,707)			—		(2)		(6,709)
Loss on early extinguishment of debt	—			—		(6)		(6)
Other loss, net	—			(1)		—		(1)
Provision for income taxes (1)	41			—		—		41
Assets	11,359		(2)	1,633		112		13,104
Capital investments (3)	1,669			—		3		1,672

(1)Interest expense and provision for income taxes by segment is an allocation of corporate amounts as they are incurred at the corporate level.

(2)E&P assets includes office, technology, water infrastructure, drilling rigs and other ancillary equipment not directly related to natural gas and oil properties. This also includes deferred tax assets which are an allocation of corporate amounts as they are incurred at the corporate level.

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(3)Capital investments include decreases of $94 million and $33 million for the three months ended September 30, 2023 and September 30, 2022, respectively, and a decrease of $122 million and an increase of $44 million for the nine months ended September 30, 2023 and September 30, 2022, respectively, relating to the change in accrued expenditures between periods.

(4)The E&P segment operating income includes $27 million of merger-related expenses related to the Indigo and GEPH Mergers for the nine months ended September 30, 2022.

The following table presents the breakout of other assets, which represent corporate assets not allocated to segments and assets for non-reportable segments as of September 30, 2023 and 2022:


	As of September 30,
(in millions)	2023			2022
Cash and cash equivalents	$	26		$	11
Accounts receivable	1			1


Prepayments	10			8
Other current assets	2			—
Property, plant and equipment	21			10
Unamortized debt expense	16			21
Right-of-use lease assets	51			58
Non-qualified retirement plan	3			3

Other long-term assets	10		(1)	—
	$	140		$	112

(1)Consists primarily of costs associated with the development of the Company’s enterprise resource technology.

(16) NEW ACCOUNTING PRONOUNCEMENTS

New Accounting Standards Implemented in this Report

None.

New Accounting Standards Not Yet Adopted in this Report

None that are expected to have a material impact.

ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following updates information as to Southwestern Energy Company’s financial condition provided in our Annual Report on Form 10-K for the year ended December 31, 2022 (the “2022 Annual Report”) and analyzes the changes in the results of operations between the three and nine month periods ended September 30, 2023 and 2022. For definitions of commonly used natural gas and oil terms used in this Quarterly Report, please refer to the “Glossary of Certain Industry Terms” provided in our 2022 Annual Report.

The following discussion contains forward-looking statements that involve risks and uncertainties. Our actual results could differ materially from those anticipated in forward-looking statements for many reasons, including the risks described in “Cautionary Statement About Forward-Looking Statements” in the forepart of this Quarterly Report and in Item 1A, “Risk Factors” in Part I and elsewhere in our 2022 Annual Report. You should read the following discussion with our consolidated financial statements and the related notes included in this Quarterly Report.

OVERVIEW

Background

We are an independent energy company engaged in natural gas, oil and NGLs development, exploration and production, which we refer to as “E&P.” We are also focused on creating and capturing additional value through our marketing business, which we call “Marketing”. We conduct most of our businesses through subsidiaries, and we currently operate exclusively in the Appalachian and Haynesville natural gas basins in the lower 48 United States.

E&P. Our primary business is the development and production of natural gas as well as associated NGLs and oil, with our ongoing operations focused on the development of unconventional natural gas reservoirs located in Pennsylvania, West Virginia, Ohio and Louisiana. Our operations in Pennsylvania, West Virginia and Ohio, which we refer to as “Appalachia,” are focused on the Marcellus Shale, the Utica and the Upper Devonian unconventional natural gas and liquids reservoirs. Our operations in Louisiana, which we refer to as “Haynesville,” are primarily focused on the Haynesville and Bossier natural gas

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reservoirs. We also have drilling rigs located in Appalachia and Haynesville, and we provide certain oilfield products and services, principally serving our E&P operations through vertical integration. Over the past three years, we have completed three strategic acquisitions which have added scale to our operations:

•On November 13, 2020, we closed on the Montage Merger, which increased our footprint in West Virginia and Pennsylvania and expanded our operations into Ohio.

•On September 1, 2021, we closed on the Indigo Merger, which established our natural gas operations in the Haynesville and Bossier Shales in Louisiana.

•On December 31, 2021, we closed on the GEPH Merger, which expanded our operations in the Haynesville.

The Indigo Merger and GEPH Merger extended our E&P asset portfolio beyond Appalachia into the Haynesville and Bossier formations, giving us additional exposure to the LNG corridor and other markets on the U.S. Gulf Coast. These mergers progressed our ability to lower our enterprise business risk, expand our economic inventory, opportunity set and business optionality and capture operating synergies and cost structure savings.

Marketing. Our marketing activities capture opportunities that arise through the marketing and transportation of natural gas, oil and NGLs primarily produced in our E&P operations.

Recent Financial and Operating Results

Significant third quarter 2023 operating and financial results include:

Total Company

•Net income of $45 million, or $0.04 per diluted share, decreased compared to net income of $450 million, or $0.40 per diluted share, for the same period in 2022. Net income decreased due to lower operating income of $2,407 million primarily associated with lower realized pricing and production, and a higher income tax provision of $10 million. The decrease in net income from the third quarter of 2022 to the third quarter of 2023 was partially offset by a positive change in our net derivative position of approximately $2 billion due to an increase in our settled derivative position of approximately $2,051 million, partially offset by a lower mark to market position on our unsettled derivatives of approximately $55 million, as a result of changes in commodity pricing. Further offsetting the decrease in net income from the third quarter of 2022 to the third quarter of 2023 was decreased interest expense of $14 million as a result from our debt reduction in the prior periods.

•Operating income of $7 million decreased compared to operating income of $2,414 million for the same period in 2022 on a consolidated basis. Operating income decreased as a $3,098 million decrease in operating revenues was only partially offset by decreased operating costs of $691 million primarily associated with lower realized pricing and production.

•Net cash provided by operating activities of $477 million decreased as compared to $797 million for the same period in 2022. The decrease was primarily attributable to the impact of lower commodity pricing on revenues of $2,246 million, lower production of $129 million, and a higher provision for income taxes of $10 million, and was partially offset by an increase in our settled derivative positions of $2,051 million and lower interest expense of $14 million.

•Total capital investment of $454 million in the third quarter of 2023 decreased 16% from $543 million for the same period in 2022 primarily due to lower activity levels associated with lower commodity pricing period over period.

E&P

•E&P operating loss of $18 million in the third quarter of 2023 decreased from operating income of $2,386 million in the third quarter of 2022 for a total decrease of $2,404 million, primarily due to a $2,374 million decrease in E&P operating revenues resulting from a $5.28 per Mcfe decrease in our realized weighted average price per Mcfe (excluding derivatives) and an 18 Bcfe decrease in production volumes combined with a $30 million increase in E&P operating costs and expenses.

•Total net production of 425 Bcfe, which was comprised of 86% natural gas and 14% oil and NGLs, decreased 4% from 443 Bcfe in the same period in 2022, primarily due to a 5% decrease in our natural gas production.

•Excluding the effect of derivatives, our realized natural gas price of $1.66 per Mcf decreased 78%, our realized oil price of $71.09 per barrel decreased 16% and our realized NGL price of $20.53 per barrel decreased 38%, as compared to the same period in 2022. Excluding the effect of derivatives, our total weighted average realized price of $2.05 per Mcfe decreased 72% from the same period in 2022.

•E&P segment invested $452 million in capital; drilling 24 wells, completing 25 wells and placing 23 wells to sales.

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Outlook

Our primary focus in 2023 is to generally maintain our productive capacity and improve the safety and efficiency of our operations to further our ability to generate free cash flow, further reduce debt and return capital to shareholders (subject to market and business conditions).

As we continue to develop our core positions in the Appalachian and Haynesville natural gas basins in the U.S., we will concentrate on:

•Creating Sustainable Value. We seek to create value for our stakeholders by allocating capital that is focused on earning economic returns and optimizing the value of our assets; delivering sustainable free cash flow through the cycle; upgrading the quality and depth of our drilling inventory; improving the cost of capital efficiency of our operations; and converting resources to proved reserves.

•Protecting Financial Strength. We intend to protect our financial strength by lowering our leverage ratio and total debt; maintaining a strong liquidity position and extended debt maturity profile; lowering our weighted average cost of capital; and deploying hedges to balance revenue protection with commodity upside exposure.

•Progressing Execution. We are focused on operating effectively and efficiently with health, safety and environmental (“HSE”) matters and environmental, social and governance (“ESG”) matters as core values; leveraging our data analytics, operating execution, strategic sourcing, vertical integration and large-scale asset development expertise to drive cost and capital efficiencies; further enhancing well performance, optimizing well costs and reducing base production declines; and growing margins and securing flow assurance through commercial and marketing arrangements.

•Capturing the Tangible Benefits of Scale. We strive to enhance our enterprise returns by leveraging the scale gained from our past strategic transactions to deliver operating synergies, drive cost savings, expand our economic inventory, lower our enterprise risk profile, and expand our opportunity set and optionality.

We remain committed to achieving these objectives while maintaining our commitment to being environmentally conscious and proactive and to using best practices in social stewardship and corporate governance. We believe that we and our industry will continue to face challenges due to evolving environmental standards and expectations of both regulators and investors, the uncertainty of natural gas, oil and NGL prices in the United States, changes in laws, regulations and investor sentiment, and other key factors described in the 2022 Annual Report. As such, we intend to protect our financial strength by reducing our debt while continuing to extend the weighted average years to maturity of our debt, and by maintaining a derivative program designed to reduce our exposure to commodity price volatility.

RESULTS OF OPERATIONS

The following discussion of our results of operations for our segments is presented before intersegment eliminations. We evaluate our segments as if they were stand-alone operations and accordingly discuss their results prior to any intersegment eliminations. Interest expense, gain (loss) on derivatives, gain (loss) on early extinguishment of debt and income taxes are discussed on a consolidated basis.

E&P


	For the three months ended September 30,				For the nine months ended September 30,
(in millions)	2023		2022		2023		2022
Revenues	$	873	$	3,247	$	3,079	$	8,250
Operating costs and expenses (1)	891		861		2,589		2,466
Operating income (loss)	$	(18)	$	2,386	$	490	$	5,784

Gain (loss) on derivatives, settled	$	162	$	(1,889)	$	249	$	(4,185)

(1)Includes $27 million in merger-related expenses related to our Indigo and GEPH Mergers for the nine months ended September 30, 2022.

Operating Income (Loss)

•E&P segment operating loss decreased $2,404 million for the three months ended September 30, 2023, compared to the same period in 2022. The decrease was primarily due to a $2,374 million decrease in E&P operating revenues resulting from a 72% decrease in our realized weighted average price per Mcfe (excluding derivatives) and a 4% decrease in production volumes combined with a $30 million increase in E&P operating costs and expenses.

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•E&P segment operating income decreased $5,294 million for the nine months ended September 30, 2023, compared to the same period in 2022. This was primarily due to a $5,171 million decrease in E&P operating revenues resulting from a 61% decrease in our realized weighted average price per Mcfe (excluding derivatives) and a 4% decrease in production volumes combined with a $123 million increase in E&P operating costs and expenses.

Revenues

The following illustrates the effects on sales revenues associated with changes in commodity prices and production volumes:


	Three months ended September 30,
(in millions except percentages)	Natural Gas			Oil			NGLs			Total
2022 sales revenues (1)	$	2,889		$	99		$	260		$	3,248
Changes associated with prices	(2,123)			(18)			(105)			(2,246)
Changes associated with production volumes	(156)			12			15			(129)
2023 sales revenues (2)	$	610		$	93		$	170		$	873
Decrease from 2022	(79		%)	(6		%)	(35		%)	(73		%)


	Nine months ended September 30,
(in millions except percentages)	Natural Gas			Oil			NGLs			Total
2022 sales revenues (1)	$	7,064		$	345		$	842		$	8,251
Changes associated with prices	(4,402)			(100)			(403)			(4,905)
Changes associated with production volumes	(381)			33			85			(263)
2023 sales revenues (2)	$	2,281		$	278		$	524		$	3,083
Decrease from 2022	(68		%)	(19		%)	(38		%)	(63		%)

(1)Excludes $1 million in other operating revenues for the three and nine months ended September 30, 2022 primarily related to gas balancing losses.

(2)Excludes $4 million in other operating revenues for the nine months ended September 30, 2023 primarily related to gas balancing losses.

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Production Volumes


	For the three months ended September 30,				Increase/(Decrease)	For the nine months ended September 30,				Increase/(Decrease)
Production volumes:	2023		2022			2023		2022
Natural Gas (Bcf)
Appalachia	205		213		(4)%	597		637		(6)%
Haynesville	163		176		(7)%	489		511		(4)%

Total	368		389		(5)%	1,086		1,148		(5)%

Oil (MBbls)
Appalachia	1,303		1,169		11%	4,146		3,786		10%
Haynesville	6		4		50%	21		15		40%
Other	1		—		100%	2		5		(60)%
Total	1,310		1,173		12%	4,169		3,806		10%

NGL (MBbls)
Appalachia	8,226		7,787		6%	24,707		22,444		10%
Haynesville	2		—		100%	7		—		100%
Other	—		1		(100)%	1		1		—%
Total	8,228		7,788		6%	24,715		22,445		10%

Production volumes by area: (Bcfe)
Appalachia	262		267		(2)%	770		795		(3)%
Haynesville	163		176		(7)%	489		511		(4)%

Total	425		443		(4)%	1,259		1,306		(4)%

Production volumes by formation: (Bcfe)
Marcellus Shale	232		226		3%	680		669		2%
Utica Shale	30		41		(27)%	90		126		(29)%
Haynesville Shale	95		107		(11)%	290		317		(9)%
Bossier Shale	68		69		(1)%	199		194		3%

Total	425		443		(4)%	1,259		1,306		(4)%

Production percentage:
Natural gas	86	%	88	%		86	%	88	%
Oil	2	%	2	%		2	%	2	%
NGL	12	%	10	%		12	%	10	%

•E&P production volumes decreased by 18 Bcfe and 47 Bcfe for the three and nine months ended September 30, 2023, respectively, compared to the same periods in 2022. Lower natural gas production is attributable to our moderation of activity related to the decrease in near-term natural gas prices and the impact of inflation.

•Oil and NGL production increased 6% and 10% for the three and nine months ended September 30, 2023, respectively, as compared to the same period in 2022, primarily due to a higher allocation of capital investment to liquids-rich areas.

Commodity Prices

The price we expect to receive for our production is a critical factor in determining the capital investments we make to develop our properties. Commodity prices fluctuate due to a variety of factors we can neither control nor predict, including increased supplies of natural gas, oil or NGLs due to greater development activities, weather conditions, political and economic events, and competition from other energy sources. These factors impact supply and demand, which in turn determine the sales prices for our production. In addition to these factors, the prices we realize for our production are affected by our derivative activities as well as locational differences in market prices, including basis differentials. We will continue to evaluate the commodity price environments and adjust the pace of our activity in order to maintain appropriate liquidity and financial flexibility.

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	For the three months ended September 30,						Increase/(Decrease)	For the nine months ended September 30,				Increase/(Decrease)
	2023			2022				2023		2022
Natural Gas Price:
NYMEX Henry Hub Price ($/MMBtu) (1)	$	2.55		$	8.20		(69)%	$	2.69	$	6.77	(60)%
Discount to NYMEX (2)	(0.89)			(0.78)			14%	(0.59)		(0.62)		(5)%
Average realized gas price, excluding derivatives ($/Mcf)	$	1.66		$	7.42		(78)%	$	2.10	$	6.15	(66)%
Gain on settled financial basis derivatives ($/Mcf)	0.13			0.10				0.01		0.06
Gain (loss) on settled commodity derivatives ($/Mcf)	0.34			(4.71)				0.23		(3.38)
Average realized gas price, including derivatives ($/Mcf)	$	2.13		$	2.81		(24)%	$	2.34	$	2.83	(17)%

Oil Price:
WTI oil price ($/Bbl) (3)	$	82.26		$	91.56		(10)%	$	77.39	$	98.09	(21)%
Discount to WTI (4)	(11.17)			(7.22)			55%	(10.79)		(7.39)		46%
Average oil price, excluding derivatives ($/Bbl)	$	71.09		$	84.34		(16)%	$	66.60	$	90.70	(27)%
Loss on settled derivatives ($/Bbl)	(14.49)			(35.28)				(9.39)		(38.41)
Average oil price, including derivatives ($/Bbl)	$	56.60		$	49.06		15%	$	57.21	$	52.29	9%

NGL Price:
Average realized NGL price, excluding derivatives ($/Bbl)	$	20.53		$	33.33		(38)%	$	21.19	$	37.50	(43)%
Gain (loss) on settled derivatives ($/Bbl)	0.88			(6.78)				1.09		(9.86)
Average realized NGL price, including derivatives ($/Bbl)	$	21.41		$	26.55		(19)%	$	22.28	$	27.64	(19)%
Percentage of WTI, excluding derivatives	25		%	36		%		27%		38%

Total Weighted Average Realized Price:
Excluding derivatives ($/Mcfe)	$	2.05		$	7.33		(72)%	$	2.45	$	6.32	(61)%
Including derivatives ($/Mcfe)	$	2.43		$	3.06		(21)%	$	2.65	$	3.11	(15)%

(1)Based on last day settlement prices from monthly futures contracts.

(2)This discount includes a basis differential, a heating content adjustment, physical basis sales, third-party transportation and fuel charges, and excludes financial basis derivatives.

(3)Based on the average daily settlement price of the nearby month futures contract over the period.

(4)This discount primarily includes location and quality adjustments.

We receive a sales price for our natural gas at a discount to average monthly NYMEX settlement prices based on heating content of the gas, locational basis differentials and transportation and fuel charges. Additionally, we receive a sales price for our oil and NGLs at a difference to average monthly West Texas Intermediate (“WTI”) settlement and Mont Belvieu NGL composite prices, respectively, due to a number of factors including product quality, composition and types of NGLs sold, locational basis differentials and transportation and fuel charges.

We regularly enter into various derivatives and other financial arrangements with respect to a portion of our projected natural gas, oil and NGL production in order to support certain desired levels of cash flow and to minimize the impact of price fluctuations, including fluctuations in locational market differentials. We refer you to Item 3, Quantitative and Qualitative Disclosures About Market Risk, and Note 7 to the consolidated financial statements, included in this Quarterly Report.

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The tables below present the amount of our future natural gas production in which the impact of basis volatility has been limited through derivatives and physical sales arrangements as of September 30, 2023:


	Volume (Bcf)	Basis Differential
Basis Swaps – Natural Gas
2023	71	$	(0.57)
2024	46	(0.71)
2025	9	(0.64)


Total	126

Physical NYMEX Sales Arrangements – Natural Gas (1)
2023	223	$	(0.16)
2024	740	(0.16)
2025	509	(0.10)
2026	366	(0.04)
2027	328	(0.03)
2028	303	(0.02)
2029	252	(0.01)
2030	105	(0.01)


Total	2,826

(1)Based on last day settlement prices from monthly futures contracts.

In addition to protecting basis, the table below presents the amount of our future production in which price is financially protected as of September 30, 2023:


	Remaining 2023	Full Year 2024	Full Year 2025
Natural gas (Bcf)	258	649	179
Oil (MBbls)	1,171	2,083	41
Ethane (MBbls)	2,254	3,429	—
Propane (MBbls)	1,782	3,254	63
Normal butane (MBbls)	198	329	—
Natural gasoline (MBbls)	171	329	—
Total financial protection on future production (Bcfe)	291	706	180

We refer you to Note 7 of the consolidated financial statements included in this Quarterly Report for additional details about our derivative instruments.

Operating Costs and Expenses


	For the three months ended September 30,				Increase/(Decrease)	For the nine months ended September 30,				Increase/(Decrease)
(in millions except percentages)	2023		2022			2023		2022
Lease operating expenses	$	449	$	451	—%	$	1,304	$	1,277	2%
General & administrative expenses	42		37		14%	121		107		13%
Merger-related expenses	—		—		—%	—		27		(100)%

Taxes, other than income taxes	63		76		(17)%	189		198		(5)%
Full cost pool amortization	332		293		13%	964		845		14%
Non-full cost pool DD&A	5		4		25%	11		12		(8)%

Total operating costs	$	891	$	861	3%	$	2,589	$	2,466	5%

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	For the three months ended September 30,				Increase/	For the nine months ended September 30,					Increase/
Average unit costs per Mcfe:	2023		2022		(Decrease)	2023		2022			(Decrease)
Lease operating expenses (1)	$	1.06	$	1.02	4%	$	1.04	$	0.98		6%
General & administrative expenses	$	0.10	$	0.08	25%	$	0.10	$	0.08	(2)	25%
Taxes, other than income taxes	$	0.15	$	0.17	(12)%	$	0.15	$	0.15		—%
Full cost pool amortization	$	0.78	$	0.66	18%	$	0.77	$	0.65		18%

(1)Includes post-production costs such as gathering, processing, fractionation and compression.

(2)Excludes $27 million in merger-related expenses related to the Indigo and GEPH Mergers for the nine months ended September 30, 2022.

Lease Operating Expenses

•Lease operating expenses per Mcfe increased $0.04 and $0.06 for the three and nine months ended September 30, 2023, respectively, compared to the same periods in 2022, primarily due to the impacts of inflation and lower production volumes.

General and Administrative Expenses

•General and administrative expenses increased $5 million or $0.02 per Mcfe and $14 million or $0.02 per Mcfe for the three and nine months ended September 30, 2023, respectively, compared to the same periods in 2022, primarily due to costs associated with the development of our enterprise resource technology and lower production volumes.

Merger-Related Expenses

•We focused on building scale and geographic diversification throughout 2021. As a result of this strategy, we merged with Indigo in September 2021 and GEPH in December 2021 which resulted in merger-related expenses during 2022. We did not incur any merger-related expenses for the three months ended September 30, 2022. The table below presents the charges incurred for our merger-related activities for the nine months ended September 30, 2022:


	For the nine months ended September 30, 2022
(in millions)		Indigo Merger		GEPH Merger		Total
Transition services		$	—	$	18	$	18
Professional fees (advisory, bank, legal, consulting)		—		1		1

Contract buyouts, terminations and transfers		1		2		3
Due diligence and environmental		1		1		2
Employee-related		—		1		1
Other		—		2		2
Total merger-related expenses		$	2	$	25	$	27

We refer you to Note 2 of the consolidated financial statements included in this Quarterly Report for additional details about the Indigo and GEPH Mergers. We had no merger-related expenses for the three or nine months ended September 30, 2023.

Taxes, Other than Income Taxes

•On a per Mcfe basis, taxes, other than income taxes may vary from period to period due to changes in ad valorem and severance taxes that result from the mix of our production volumes, fluctuations in commodity prices and changes in the tax rates enacted by the respective states we operate in.

•Taxes, other than income taxes, per Mcfe decreased $0.02 for the three months ended September 30, 2023, compared to the same period in 2022, primarily due to the impact of lower commodity pricing on our severance taxes in West Virginia, which are calculated as a fixed percentage of revenue net of allowable production expenses.

•Taxes, other than income taxes, per Mcfe remained flat for the nine months ended September 30, 2023, compared to the same period in 2022, primarily due to increases in ad valorem taxes offset by the impact of lower commodity pricing on our severance taxes in West Virginia.

Full Cost Pool Amortization

•Our full cost pool amortization rate increased $0.12 per Mcfe for the three and nine months ended September 30, 2023, as compared to the same periods in 2022, primarily as a result of increases in development costs as a result of inflation.

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•The amortization rate is impacted by the timing and amount of reserve additions and the future development costs associated with those additions, revisions of previous reserve estimates due to both price and well performance, write-downs that result from non-cash full cost ceiling impairments, proceeds from the sale of properties that reduce the full cost pool and the levels of costs subject to amortization. We cannot predict our future full cost pool amortization rate with accuracy due to the variability of each of the factors discussed above, as well as other factors, including but not limited to the uncertainty of the amount of future reserve changes.

•Unevaluated costs excluded from amortization were $2,140 million and $2,217 million at September 30, 2023 and December 31, 2022, respectively. The unevaluated costs excluded from amortization decreased as the impact of $164 million of unevaluated capital invested during the period was more than offset by the evaluation of previously unevaluated properties totaling $241 million.

Marketing


	For the three months ended September 30,						Increase/ (Decrease)	For the nine months ended September 30,						Increase/ (Decrease)
(in millions except volumes and percentages)	2023			2022				2023			2022
Marketing revenues	$	1,379		$	4,436		(69)%	$	4,651		$	11,214		(59)%

Marketing purchases	1,349			4,403			(69)%	4,569			11,137			(59)%
Operating costs and expenses	5			5			—%	16			17			(6)%


Operating income	$	25		$	28		(11)%	$	66		$	60		10%

Volumes marketed (Bcfe)	590			579			2%	1,715			1,694			1%

Percent natural gas production marketed from affiliated E&P operations	90		%	96		%		92		%	94		%
Affiliated E&P oil and NGL production marketed	90		%	89		%		89		%	87		%

Operating Income

•Operating income for our Marketing segment decreased $3 million for the three months ended September 30, 2023, compared to the same period in 2022, primarily due to a $3 million decrease in the marketing margin (discussed below).

•Operating income for our Marketing segment increased $6 million for the nine months ended September 30, 2023, compared to the same period in 2022, primarily due to a $5 million increase in the marketing margin and a $1 million decrease in operating costs and expenses (discussed below).

•The margin generated from marketing activities was $30 million and $33 million for the three months ended September 30, 2023 and 2022, respectively, and $82 million and $77 million for the nine months ended September 30, 2023 and 2022, respectively. The marketing margin decreased for the three months ended September 30, 2023, compared to the same period in 2022, due to lower realized prices. The marketing margin increased for the nine months ended September 30, 2023, compared to the same period in 2022, primarily from utilizing existing transportation capacity to take advantage of low in-basin pricing on the purchase and sale of third-party natural gas.

Marketing margins are driven primarily by volumes marketed and may fluctuate depending on the prices paid for commodities, related cost of transportation and the ultimate disposition of those commodities. Increases and decreases in revenues due to changes in commodity prices and volumes marketed are largely offset by corresponding changes in purchase expenses. Efforts to optimize the cost of our transportation can result in greater expenses and therefore lower marketing margins.

Revenues

•Revenues from our marketing activities decreased $3,057 million for the three months ended September 30, 2023, as compared to the same period in 2022. The decrease was primarily due to a 69% decrease in the price received for volumes marketed and partially offset by an 11 Bcfe increase in the volumes marketed for the three months ended September 30, 2023, compared to the same period in 2022.

•Revenues from our marketing activities decreased $6,563 million for the nine months ended September 30, 2023, as compared to the same period in 2022. The decrease was primarily due to a 59% decrease in the price received for volumes marketed partially offset by a 21 Bcfe increase in the volumes marketed for the nine months ended September 30, 2023, as compared to the same period in 2022.

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Operating Costs and Expenses

•Operating costs and expenses for the marketing segment decreased $1 million for the nine months ended September 30, 2023, as compared to the same period in 2022, as a result of lower personnel-related costs.

Consolidated

Interest Expense


	For the three months ended September 30,				Increase/(Decrease)	For the nine months ended September 30,				Increase/(Decrease)
(in millions except percentages)	2023		2022			2023		2022
Gross interest expense:
Senior notes	$	51	$	59	(14)%	$	158	$	177	(11)%
Credit arrangements	10		18		(44)%	26		41		(37)%
Amortization of debt costs	3		3		—%	9		10		(10)%
Total gross interest expense	64		80		(20)%	193		228		(15)%
Less: capitalization	(28)		(30)		(7)%	(87)		(89)		(2)%
Net interest expense	$	36	$	50	(28)%	$	106	$	139	(24)%

•Interest expense decreased for the three and nine months ended September 30, 2023, compared to the same periods in 2022, due to lower revolver borrowings and the effects of our debt repurchase activity in 2022 and the full redemption of our 7.75% Senior Notes due 2027 during the first quarter of 2023.

•Capitalized interest decreased for the three and nine months ended September 30, 2023, as compared to the same periods in 2022 due to the evaluation of natural gas and oil properties over the past twelve months.

•Capitalized interest as a percentage of gross interest expense increased for the three and nine months ended September 30, 2023, compared to the same periods in 2022, primarily related to a smaller percentage change in our unevaluated natural gas and oil properties balance as compared to the larger percentage decrease in our gross interest expense over the same periods.

•We refer you to Note 10 to the consolidated financial statements included in this Quarterly Report for additional details about our debt and our financing activities.

Gain (Loss) on Derivatives


	For the three months ended September 30,				For the nine months ended September 30,

(in millions)	2023		2022		2023		2022
Gain (loss) on unsettled derivatives	$	(69)	$	(12)	$	1,566	$	(2,531)
Gain (loss) on settled derivatives	162		(1,889)		249		(4,185)
Non-performance risk adjustment	—		(2)		(4)		7
Gain (loss) on derivatives	$	93	$	(1,903)	$	1,811	$	(6,709)

We refer you to Note 7 to the consolidated financial statements included in this Quarterly Report for additional details about our gain (loss) on derivatives.

Gain/Loss on Early Extinguishment of Debt

During the nine months ended September 30, 2023, we redeemed all of the outstanding 7.75% Senior Notes due 2027 at a redemption price equal to 103.875% of the principal amount thereof plus accrued and unpaid interest of $13 million for a total payment of $450 million. We recognized a $19 million loss on the extinguishment of debt, which included the write off of $3 million in related unamortized debt discounts and debt issuance costs.

For the nine months ended September 30, 2022, we recorded a loss on early debt extinguishment of $6 million as a result of our repurchase of $65 million in aggregate principal amount of our outstanding senior notes for $71 million. During the nine months ended September 30, 2022, we also fully redeemed our 4.10% Senior Notes due March 2022 with an aggregate principal amount retired of $201 million.

See Note 10 to the consolidated financial statements of this Quarterly Report for more information on our long-term debt.

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Income Taxes


	For the three months ended September 30,						For the nine months ended September 30,
(in millions except percentages)	2023			2022			2023			2022
Income tax expense	$	21		$	11		$	28		$	41
Effective tax rate	33		%	2		%	1		%	(4)		%

Our effective tax rate was approximately 33% and 1% for the three and nine months ended September 30, 2023, respectively, primarily as a result of the release of the valuation allowances against our U.S. deferred tax assets. A valuation allowance for deferred tax assets, including NOLs, is recognized when it is more likely than not that some or all of the benefit from the deferred tax assets will not be realized. To assess that likelihood, we used estimates and judgment regarding future taxable income and considered the tax consequences in the jurisdiction where such taxable income is generated, to determine whether a valuation allowance is required. Such evidence can include current financial position, results of operations, both actual and forecasted, the reversal of deferred tax liabilities and tax planning strategies as well as the current and forecasted business economics of the oil and gas industry.

For the year ended December 31, 2022, the Company maintained a full valuation allowance against its deferred tax assets based on its conclusion, considering all available evidence (both positive and negative), that it was more likely than not that the deferred tax assets would not be realized. A significant item of objective negative evidence considered was the cumulative pre-tax loss incurred over the three-year period ended December 31, 2022, primarily due to impairments of proved oil and gas properties recognized in 2020. As of the first quarter of 2023, the Company has sustained a three-year cumulative level of profitability. Based on this factor and other positive evidence such as forecasted income, the Company concluded that $523 million of its federal and state deferred tax assets were more likely than not to be realized and plan to release this portion of the valuation allowance in 2023. Accordingly, during the nine months ended September 30, 2023, the Company recognized $520 million of deferred income tax expense related to recording its tax provision which was partially offset by $492 million of tax benefit attributable to the release of the valuation allowance. The remaining valuation allowance will be released during the fourth quarter of 2023. The Company expects to keep a valuation allowance of $66 million related to NOLs in jurisdictions in which it no longer operates and against the portion of our federal and state deferred tax assets such as capital losses and interest carryovers, which may expire before being fully utilized due to the application of the limitations under Section 382 and the ordering in which such attributes may be applied.

Due to the issuance of common stock associated with the Indigo Merger, we incurred a cumulative ownership change and as such, our NOLs prior to the acquisition are subject to an annual limitation under Internal Revenue Code Section 382 of approximately $48 million. The ownership changes and resulting annual limitation will result in the expiration of NOLs or other tax attributes otherwise available. At September 30, 2023, we had approximately $4 billion of federal NOL carryovers, of which approximately $3 billion have an expiration date between 2035 and 2037 and $1 billion have an indefinite carryforward life. We currently estimate that approximately $2 billion of these federal NOLs will expire before they are able to be used and accordingly, no value has been ascribed to these NOLs on our balance sheet. If a subsequent ownership change were to occur as a result of future transactions in our common stock, our use of remaining U.S. tax attributes may be further limited.

The Inflation Reduction Act of 2022 (the “IRA”) was enacted on August 16, 2022 and may impact how the U.S. taxes certain large corporations. The IRA imposes a 15% alternative minimum tax on the “adjusted financial statement income” of certain large corporations (generally, corporations reporting at least $1 billion average adjusted pre-tax net income on their consolidated financial statements) for tax years beginning after December 31, 2022. This alternative minimum tax requires complex computations to be performed that were not previously required in U.S. tax law, significant judgments to be made in interpretation of the provisions of the IRA, significant estimates in calculations, and the preparation and analysis of information not previously relevant or regularly produced. The U.S. Treasury Department, the Internal Revenue Service, and other standard-setting bodies are expected to issue guidance on how the alternative minimum tax provisions of the IRA will be applied or otherwise administered that may differ from our interpretations. As we complete our analysis of the IRA, collect and prepare necessary data, and interpret any additional guidance, we may make adjustments to provisional amounts that we have recorded that may materially impact our provision for income taxes in the period in which adjustments are made. We do not expect to be impacted by the alternative minimum tax during 2023 and will continue to monitor updates to the IRA and the impact it will have on our consolidated financial statements.

New Accounting Standards Implemented in this Report

Refer to Note 16 to the consolidated financial statements of this Quarterly Report for a discussion of new accounting standards that have been implemented.

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New Accounting Standards Not Yet Implemented in this Report

Refer to Note 16 to the consolidated financial statements of this Quarterly Report for a discussion of new accounting standards that have not yet been implemented.

LIQUIDITY AND CAPITAL RESOURCES

We depend primarily on funds generated from our operations, our 2022 credit facility, our cash and cash equivalents balance and our access to capital markets as our primary sources of liquidity. On April 8, 2022, we amended and restated our 2018 credit facility and extended the maturity through April 2027 (the “2022 credit facility”). In connection with entering into our 2022 credit facility, the banks participating in our 2022 credit facility increased our borrowing base to $3.5 billion and agreed to provide five-year revolving commitments of $2.0 billion (the “Five-Year Tranche”) and agreed to updated terms that provide the ability to convert our secured credit facility to an unsecured credit facility if we are able to achieve investment grade status, as deemed by the relevant credit rating agencies.

On October 4, 2023, our borrowing base was reaffirmed at $3.5 billion and our Five-Year Tranche was reaffirmed at $2.0 billion. At September 30, 2023, we had approximately $1.6 billion of total available liquidity, which exceeds our currently modeled needs as we remain committed to our strategy of capital discipline.

Our flexibility to access incremental secured debt capital is derived from our excess asset collateral value above the elected $3.5 billion maximum revolving credit amount and borrowing base of our 2022 credit facility and the elected aggregate revolving commitments from our bank group. Our ability to issue secured debt is governed by the limitations of our 2022 credit facility as well as our secured debt capacity (as defined by our senior note indentures) which was $4.6 billion as of September 30, 2023, based on 25% of adjusted consolidated net tangible assets. If we were to realize a return to investment grade ratings and the subsequent conversion of our secured credit facility to an unsecured credit facility, we would expect to have access to additional liquidity capital beyond our elected aggregate revolving commitments, either by increasing commitments to the 2022 credit facility up to the $3.5 billion aggregate size or otherwise on a similarly unsecured basis, given our current asset collateral value and credit quality. We refer you to Note 10 to the consolidated financial statements included in this Quarterly Report and the section below under “Credit Arrangements and Financing Activities” for additional discussion of our 2022 credit facility and related covenant requirements.

In June 2022, we announced a share repurchase program, under which we have been authorized to repurchase up to $1 billion of our outstanding common stock beginning June 21, 2022 and continuing through and including December 31, 2023. The timing, as well as the number and value of shares repurchased under the program, will be determined at our discretion and includes a variety of factors, including our progress in reducing debt to our target debt range of $3.5 billion to $3.0 billion or lower, our free cash flow generation capabilities, our assessment of the intrinsic value of our common stock, the market price of our common stock, general market and economic conditions, available liquidity, compliance with our debt and other agreements, and applicable legal requirements among other considerations. The exact number of shares to be repurchased is not guaranteed, and the program may be suspended, modified, or discontinued at any time without prior notice. During 2022, we repurchased approximately 17.3 million shares of our outstanding common stock at an average price of $7.24 per share for a total cost of approximately $125 million. We did not repurchase any shares during the nine months ended September 30, 2023.

Looking forward, we intend to prioritize the use of any free cash flow to pay down our debt in order to progress toward our debt targets of $3.5 billion to $3.0 billion or lower and our leverage targets of 1.5x to 1.0x.

Our cash flow from operating activities is highly dependent upon our ability to sell and the sales prices that we receive for our natural gas and liquids production. Natural gas, oil and NGL prices are subject to wide fluctuations and are driven by market supply and demand, which is impacted by many factors. See “Risk Factors” in Item 1A of our 2022 Annual Report for additional discussion about current and potential future market conditions. The sales price we receive for our production is also influenced by our commodity derivative program. Our derivative contracts allow us to support a certain level of cash flow to fund our operations. Although we are continually assessing adding derivative positions for portions of our expected 2023, 2024, 2025 and 2026 production, there can be no assurance that we will be able to add derivative positions to cover the remainder of our expected production at favorable prices. We again refer you to “Risk Factors” in Item 1A of our 2022 Annual Report.

Our commodity hedging activities are subject to the credit risk of our counterparties being financially unable to settle the transaction. We actively monitor the credit status of our counterparties, performing both quantitative and qualitative assessments based on their credit ratings and credit default swap rates where applicable, and to date have not had any credit defaults associated with our transactions. However, any future failures by one or more counterparties could negatively impact

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our cash flow from operating activities. Additionally, we do not expect the events of early 2023 within the banking industry to have a material impact on our expected results of operations, financial performance, or liquidity. However, if there are issues in the wider financial system and if other financial institutions fail, our business, liquidity and financial condition could be materially affected, including as a result of impacts of any such issues or failures on our counterparties.

Our short-term cash flows are also dependent on the timely collection of receivables from our customers, hedging counterparties and joint interest owners. We actively manage this risk through credit management activities and, through the date of this filing, have not experienced any significant write-offs for non-collectable amounts. However, any sustained inaccessibility of credit by our customers, hedging counterparties and joint interest owners could adversely impact our cash flows.

Due to these factors, we are unable to forecast with certainty our future level of cash flow from operations. Accordingly, we expect to adjust our discretionary uses of cash depending upon available cash flow. Further, we may from time to time seek to retire, rearrange or amend some or all of our outstanding debt or debt agreements through cash purchases, and/or exchanges, open market purchases, privately negotiated transactions, tender offers or otherwise. Such transactions, if any, will depend on prevailing market conditions, our liquidity requirements, contractual restrictions and other factors. The amounts involved may be material.

Credit Arrangements and Financing Activities

In April 2022, we entered into an amended and restated credit agreement that replaced the 2018 credit facility (the “2022 credit facility”) with a group of banks that, as amended, has a maturity date of April 2027. As of September 30, 2023, the 2022 credit facility had an aggregate maximum revolving credit amount and borrowing base of $3.5 billion and elected commitments of $2.0 billion.

The borrowing base is subject to redetermination at least twice a year, which typically occurs in April and October, and is subject to change based primarily on drilling results, commodity prices, our future derivative position, the level of capital investment and operating costs. The 2022 credit facility is secured by substantially all of our assets and our subsidiaries’ assets (taken as a whole). The permitted lien provisions in the senior note indentures currently limit liens securing indebtedness to the greater of $2.0 billion or 25% of adjusted consolidated net tangible assets, which was $4.6 billion as of September 30, 2023. The 2022 credit facility contains the ability to utilize SOFR index rates for purposes of calculating interest expense.

The 2022 credit facility has certain financial covenant requirements but provides certain fall away features should we receive an Investment Grade Rating (defined as an index debt rating of BBB- or higher with S&P, Baa3 or higher with Moody’s, or BBB- or higher with Fitch) and meet other criteria in the future. We refer you to Note 10 to the consolidated financial statements included in this Quarterly Report for additional discussion of our 2022 credit facility.

As of September 30, 2023, we were in compliance with all of the applicable covenants contained in the credit agreement governing our 2022 credit facility. Our ability to comply with financial covenants in future periods depends, among other things, on the success of our development program and upon other factors beyond our control, such as the market demand and prices for natural gas, oil and NGLs. We refer you to Note 10 of the consolidated financial statements included in this Quarterly Report for additional discussion of the covenant requirements of our 2022 credit facility.

As of September 30, 2023, we had $388 million of borrowings on our 2022 credit facility and no outstanding letters of credit. We currently do not anticipate being required to supply a materially greater amount of letters of credit under our existing contracts. We refer you to Note 10 to the consolidated financial statements included in this Quarterly Report for additional discussion of our 2022 credit facility.

The credit status of the financial institutions participating in our 2022 credit facility could adversely impact our ability to borrow funds under the 2022 credit facility. Although we believe all of the lenders under the facility have the ability to provide funds, we cannot predict whether each will be able to meet their obligation to us. We refer you to Note 10 to the consolidated financial statements included in this Quarterly Report for additional discussion of our revolving credit facility.

Other key financing activities for the nine months ended September 30, 2023 and September 30, 2022 are as follows:

Debt Repurchases

•On February 26, 2023, we redeemed all of the outstanding 7.750% Senior Notes due 2027 at a redemption price equal to 103.875% of the principal amount thereof plus accrued and unpaid interest of $13 million for a total payment of $450 million. We recognized a $19 million loss on the extinguishment of debt, which included the write off of $3 million in related unamortized debt discounts and debt issuance costs. We funded the redemption using approximately $316 million of cash on hand and approximately $134 million of borrowings under our 2022 credit facility.

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•In January 2022, we repurchased the remaining outstanding principal balance of $201 million on our 2022 senior notes using our credit facility. As a result of the focused work on refinancing and repayment of our debt in recent years, coupled with the amendment and restatement of our credit facility on April 8, 2022, none of our outstanding debt balance is scheduled to become due prior to 2025.

•In March 2022, we repurchased $5 million of our 8.375% Senior Notes due 2028 and $15 million of our 7.75% Senior Notes due 2027, resulting in a $2 million loss on debt extinguishment.

•In April 2022, we repurchased $4 million of our 7.75% Senior Notes due 2027 and $23 million of our 8.375% Senior Notes due 2028, resulting in a $3 million loss on debt extinguishment.

•In May 2022, we repurchased $18 million of our 8.375% Senior Notes due 2028, resulting in a $1 million loss on debt extinguishment.

As of October 31, 2023, we had long-term debt issuer ratings of Ba1 by Moody’s (rating and stable outlook affirmed on June 28, 2023), BB+ by S&P (rating upgraded to BB+ and outlook upgraded to positive on January 18, 2023) and BB+ by Fitch Ratings (rating and positive outlook affirmed on August 16, 2023). Effective in January 2022, the interest rate for our 4.95% senior notes due January 2025 (“2025 Notes”) was 5.95%, reflecting a net downgrade in our bond ratings since their issuance. On May 31, 2022, Moody’s upgraded our bond rating to Ba1, which decreased the interest rate on the 2025 Notes from 5.95% to 5.70% for coupon payments paid after July 2022. Any further upgrades or downgrades in our public debt ratings by Moody’s or S&P could decrease or increase our cost of funds, respectively, as our 2025 Notes are subject to ratings driven changes.

Cash Flows


	For the nine months ended September 30,
(in millions)	2023		2022
Net cash provided by operating activities	$	2,039	$	2,196
Net cash used in investing activities	(1,710)		(1,608)
Net cash used in financing activities	(353)		(605)

Cash Flow from Operations


	For the nine months ended September 30,
(in millions)	2023		2022
Net cash provided by operating activities	$	2,039	$	2,196
Add back (subtract) changes in working capital	(345)		157
Net cash provided by operating activities, net of changes in working capital	$	1,694	$	2,353

•Net cash provided by operating activities decreased 7%, or $157 million, for the nine months ended September 30, 2023, compared to the same period in 2022, primarily due to a $4,905 million decrease resulting from lower commodity prices, a $263 million decrease related to decreased production and a $5 million increase in operating costs and expenses partially offset by a $4,434 million improvement in our settled derivative positions, a $502 million increase in working capital, a $41 million reduction in our current taxes, a $33 million decrease in interest expense, and a $5 million increase in our marketing margin.

•Net cash provided by operating activities, net of changes in working capital, provided 99% of our cash requirements for capital investments for the nine months ended September 30, 2023 and exceeded our cash requirements for capital investments for the nine months ended September 30, 2022. While we front-loaded our capital program into the earlier quarters of the year, we remain committed to our capital discipline strategy of investing within our cash flow from operations, net of changes in working capital.

Cash Flow from Investing Activities

•Total E&P capital investments increased $40 million for the nine months ended September 30, 2023, compared to the same period in 2022, primarily attributable to higher costs due to inflation.

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	For the nine months ended September 30,
(in millions)	2023		2022
Additions to properties and equipment	$	1,833	$	1,623
Adjustments for capital investments
Changes in capital accruals	(122)		44
Other (1)	3		5
Total capital investing	$	1,714	$	1,672

(1)Includes capitalized non-cash stock-based compensation and costs to retire assets, which are classified as cash used in operating activities.

Capital Investing


	For the three months ended September 30,				Increase/(Decrease)	For the nine months ended September 30,				Increase/(Decrease)
(in millions except percentages)	2023		2022			2023		2022
E&P capital investing	$	452	$	540	(16)%	$	1,709	$	1,669	2%
Other capital investing (1)	2		3		(33)%	5		3		67%
Total capital investing	$	454	$	543	(16)%	$	1,714	$	1,672	3%

(1)Other capital investing relates to information technology purchases for the three and nine months ended September 30, 2023.


	For the three months ended September 30,				For the nine months ended September 30,
(in millions)	2023		2022		2023		2022
E&P Capital Investments by Type:
Development and exploration, including workovers	$	374	$	471	$	1,471	$	1,446
Acquisition of properties	14		12		59		56


Other	14		4		30		13
Capitalized interest and expenses	50		53		149		154
Total E&P capital investments	$	452	$	540	$	1,709	$	1,669

E&P Capital Investments by Area:
Appalachia	$	233	$	237	$	784	$	716
Haynesville	208		301		901		942
Other E&P	11		2		24		11
Total E&P capital investments	$	452	$	540	$	1,709	$	1,669


	For the three months ended September 30,		For the nine months ended September 30,
	2023	2022	2023	2022
Gross Operated Well Count Summary:
Drilled	24	31	93	105
Completed	25	36	107	108
Wells to sales	23	31	109	105

Actual capital expenditure levels may vary significantly from period to period due to many factors, including drilling results, natural gas, oil and NGL prices, industry conditions, the prices and availability of goods and services, and the extent to which properties are acquired or non-strategic assets are sold.

Cash Flow from Financing Activities

•For the nine months ended September 30, 2022, we fully redeemed our 4.10% Senior Notes due 2022 for $201 million and paid down additional aggregate principal balances on our senior notes of $65 million in principal and $6 million in premiums, paid down $4 million of our Term Loan B due 2027 and paid down $280 million on our 2022 credit facility.

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•For the nine months ended September 30, 2022, we repurchased approximately 13.6 million shares of our outstanding common stock pursuant to our previously announced share repurchase program at an average of $7.35 per share for a total cost of approximately $100 million.

We refer you to Note 10 of the consolidated financial statements included in this Quarterly Report for additional discussion of our outstanding debt and credit facilities.

Working Capital

We had negative working capital of $716 million at September 30, 2023, a $1,101 million increase from December 31, 2022, primarily attributable to a $1,289 million increase in the current mark-to-market value of our derivatives position related to commodity pricing declines, a decrease in our accounts payable of $518 million, a decrease in interest payable of $60 million, a decrease in other current liabilities of $48 million, and an increase in other current assets of $10 million. The increase was partially offset by a decrease in accounts receivable of $799 million, and a decrease in cash and cash equivalents of $24 million as compared to December 31, 2022. We believe that our existing cash and cash equivalents, our anticipated cash flows from operations and our available 2022 credit facility will be sufficient to meet our working capital and operational spending requirements.

Off-Balance Sheet Arrangements

We may enter into off-balance sheet arrangements and transactions that can give rise to material off-balance sheet obligations. As of September 30, 2023, our material off-balance sheet arrangements and transactions include operating service arrangements. There are no other transactions, arrangements or other relationships with unconsolidated entities or other persons that are reasonably likely to materially affect our liquidity or availability of our capital resources. For more information regarding off-balance sheet arrangements, we refer you to “Contractual Obligations and Contingent Liabilities and Commitments” below for more information.

Contractual Obligations and Contingent Liabilities and Commitments

We have various contractual obligations in the normal course of our operations and financing activities. Other than the firm transportation and gathering agreements discussed below, there have been no material changes to our contractual obligations from those disclosed in our 2022 Annual Report.

Contingent Liabilities and Commitments

As of September 30, 2023, we had commitments for demand and similar charges under firm transportation and gathering agreements to guarantee access capacity on natural gas and liquids pipelines and gathering systems totaling approximately $9.7 billion, $1.2 billion of which related to access capacity on future pipeline and gathering infrastructure projects that still require the granting of regulatory approvals and/or additional construction efforts. This amount also included guarantee obligations of up to $825 million. As of September 30, 2023, future payments under non-cancelable firm transportation and gathering agreements are as follows:


	Payments Due by Period
(in millions)	Total		Less than 1 Year		1 to 3 Years		3 to 5 Years		5 to 8 years		More than 8 Years
Infrastructure currently in service	$	8,454	$	955	$	1,979	$	1,768	$	1,796	$	1,956
Pending regulatory approval and/or construction (1)	1,239		46		187		217		322		467
Total transportation charges	$	9,693	$	1,001	$	2,166	$	1,985	$	2,118	$	2,423

(1)Based on the estimated in-service dates as of September 30, 2023.

Prior to January 1, 2021, substantially all of our employees were covered by the defined benefit pension plan, a cash balance plan that provided benefits based upon a fixed percentage of an employee’s annual compensation (the “Plan”). As part of an ongoing effort to reduce costs, we elected to freeze the Plan effective January 1, 2021. Employees that were participants in the Plan prior to January 1, 2021 continued to receive the interest component of the Plan but no longer received the service component. On September 13, 2021, the Compensation Committee of the Board approved terminating the Plan, effective December 31, 2021. This decision, among other benefits, will provide Plan participants quicker access to, and greater flexibility in, the management of participants’ respective benefits due under the Plan.

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We have commenced the Plan termination process, and, on April 6, 2022, the Internal Revenue Service issued a favorable determination letter, concurring that the Plan met all of the qualification requirements under the Internal Revenue Code. In December 2022, we distributed approximately $38 million of the Plan’s assets to participants in the form of lump sum payments in connection with a limited distribution window provided to all active and former employee participants as part of the Plan termination process.

In March 2023, we entered into a group annuity contract with a qualified insurance company relating to the Plan. Under the group annuity contract, we purchased an irrevocable nonparticipating single premium group annuity contract from the insurer and transferred to the insurer the future benefit obligations and annuity administration for certain retirees and beneficiaries under the Plan.

Upon issuance of the group annuity contract, the pension benefit obligations and annuity administration for the remaining participants was irrevocably transferred from the Plan to the insurer. By transferring these obligations through the payment to the insurer in March 2023, we have no remaining obligations under the Plan or any other U.S. tax-qualified defined benefit pension plan. The purchase of the group annuity contract was funded directly by the assets of the Plan. We recognized a pre-tax non-cash pension settlement charge of approximately $2 million during the first nine months of 2023 as a result of the settlement of the Plan.

For the nine months ended September 30, 2023, we have not made contributions to the pension plan or postretirement benefit plans, and we do not expect to contribute additional funds to our pension plan during the remainder of 2023. We transferred the remaining residual pension asset balance of approximately $14 million to a qualified replacement plan in September 2023 and those funds are currently presented as cash and cash equivalents as of September 30, 2023. We recognized pension assets of approximately $15 million related to our pension plan benefits as of December 31, 2022. We recognized liabilities of approximately $10 million and $9 million related to our other postretirement benefits as of September 30, 2023 and December 31, 2022, respectively. See Note 13 to the consolidated financial statements included in this Quarterly Report for additional discussion about our pension and other postretirement benefits.

We are subject to various litigation, claims and proceedings that arise in the ordinary course of business, such as for alleged breaches of contract, miscalculation of royalties, employment matters, traffic incidents, pollution, contamination, encroachment on others’ property or nuisance. We accrue for such items when a liability is both probable and the amount can be reasonably estimated. Management believes that current litigation, claims and proceedings, individually or in aggregate and after taking into account insurance, are not likely to have a material adverse impact on our financial position, results of operations or cash flows, although it is possible that adverse outcomes could have a material adverse effect on our results of operations or cash flows for the period in which the effect of that outcome becomes reasonably estimable. Many of these matters are in early stages, so the allegations and the damage theories have not been fully developed, and are all subject to inherent uncertainties; therefore, management’s view may change in the future.

We are also subject to laws and regulations relating to the protection of the environment. Environmental and cleanup related costs of a non-capital nature are accrued when it is both probable that a liability has been incurred and when the amount can be reasonably estimated. Management believes any future remediation or other compliance related costs will not have a material effect on our financial position, results of operations or cash flows.

For further information, we refer you to “Litigation” and “Environmental Risk” in Note 11 to the consolidated financial statements included in Item 1 of Part I of this Quarterly Report.

Supplemental Guarantor Financial Information

As discussed in Note 10, in April 2022 the Company entered into the 2022 credit facility. Pursuant to requirements under the indentures governing our senior notes, each 100% owned subsidiary that becomes a guarantor of the 2022 credit facility is also required to become a guarantor of each of our senior notes (the “Guarantor Subsidiaries”). The Guarantor Subsidiaries also granted liens and security interests to support their guarantees under the 2022 credit facility, but not of the senior notes. These guarantees are full and unconditional and joint and several among the Guarantor Subsidiaries. Certain of our operating units are accounted for on a consolidated basis do not guarantee the 2022 credit facility and senior notes.

The Company and the Guarantor Subsidiaries jointly and severally, and fully and unconditionally, guarantee the payment of the principal and premium, if any, and interest on the senior notes when due, whether at stated maturity of the senior notes, by acceleration, by call for redemption or otherwise, together with interest on the overdue principal, if any, and interest on any overdue interest, to the extent lawful, and all other obligations of the Company to the holders of the senior notes.

SEC Regulation S-X Rule 13-01 requires the presentation of “Summarized Financial Information” to replace the “Condensed Consolidating Financial Information” required under Rule 3-10. Rule 13-01 allows the omission of Summarized Financial Information if assets, liabilities and results of operations of the Guarantor Subsidiaries are not materially different

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than the corresponding amounts presented in the consolidated financial statements of the Company. The Parent and Guarantor Subsidiaries comprise the material operations of the Company. Therefore, the Company concluded that the presentation of the Summarized Financial Information is not required as the Summarized Financial Information of the Company’s Guarantors is not materially different from our consolidated financial statements.

Critical Accounting Policies and Estimates

There have been no material changes to our critical accounting policies and estimates as compared to the critical accounting policies and estimates described in our 2022 Annual Report.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Market risks relating to our operations result primarily from the volatility in commodity prices, basis differentials and interest rates, as well as service costs and credit risk concentrations. We use fixed price swaps, two-way costless collars, three-way costless collars, options (calls and puts), basis swaps, index swaps and interest rate swaps to reduce the volatility of earnings and cash flow due to fluctuations in the prices of natural gas, oil and certain NGLs along with interest rates. Our Board has approved risk management policies and procedures to utilize financial products for the reduction of defined commodity price risk. Utilization of financial products for the reduction of interest rate risks is also overseen by our Board. These policies prohibit speculation with derivatives and limit swap agreements to counterparties with appropriate credit standings.

Credit Risk

Our exposure to concentrations of credit risk consists primarily of trade receivables and derivative contracts associated with commodities trading. Concentrations of credit risk with respect to receivables are limited due to the large number of our purchasers and their dispersion across geographic areas. For the nine months ended September 30, 2023, one purchaser accounted for 14% of our revenues. For the year ended December 31, 2022, one purchaser accounted for 17% of our revenues. No other individual purchasers accounted for more than 10% of our revenues in either of these respective periods. A default on this account could have a material impact on the Company. See “Commodities Risk” below for discussion of credit risk associated with commodities trading.

Interest Rate Risk

As of September 30, 2023, we had approximately $3,743 million of outstanding senior notes with a weighted average interest rate of 5.46%, and $388 million of borrowings under our 2022 credit facility. As of September 30, 2023, we had long-term debt issuer ratings of BB+ by S&P, Ba1 by Moody’s and BB+ by Fitch Ratings. On September 1, 2021 S&P upgraded our bond rating to BB, and on January 6, 2022, S&P further upgraded our bond rating to BB+, which decreased the interest rate on the 2025 notes to 5.95%, beginning with coupon payments paid after January 2022. On May 31, 2022, Moody’s upgraded the Company’s bond rating to Ba1, which decreased the interest rate on the 2025 Notes from 5.95% to 5.70% with coupon payments paid after July 2022. Any further upgrades or downgrades in our public debt ratings by Moody’s or S&P could decrease or increase our cost of funds, respectively, as our 2025 Notes are subject to ratings driven changes.


	Expected Maturity Date
($ in millions except percentages)	2023			2024			2025			2026			2027			Thereafter			Total
Fixed rate payments (1)	$	—		$	—		$	389		$	—		$	—		$	3,354		$	3,743
Weighted average interest rate	—		%	—		%	5.70		%	—		%	—		%	5.43		%	5.46		%

Variable rate payments (1)	$	—		$	—		$	—		$	—		$	388		$	—		$	388
Weighted average interest rate	—		%	—		%	—		%	—		%	7.16		%	—		%	7.16		%

(1)Excludes unamortized debt issuance costs and debt discounts.

Commodities Risk

We use fixed price swap agreements and options to protect sales of our production against the inherent risks of adverse price fluctuations or locational pricing differences between a published index and the NYMEX futures market. These swaps and options include transactions in which one party will pay a fixed price (or variable price) for a notional quantity in exchange for receiving a variable price (or fixed price) based on a published index (referred to as price swaps) and transactions in which parties agree to pay a price based on two different indices (referred to as basis swaps).

The primary market risks relating to our derivative contracts are the volatility in market prices and basis differentials for our production. However, the market price risk is offset by the gain or loss recognized upon the related sale or purchase of the production that is financially protected. Credit risk relates to the risk of loss as a result of non-performance by our

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counterparties. The counterparties are primarily major banks and integrated energy companies that management believes present minimal credit risks. The credit quality of each counterparty and the level of financial exposure we have to each counterparty are closely monitored to limit our credit risk exposure. Additionally, we perform both quantitative and qualitative assessments of these counterparties based on their credit ratings and credit default swap rates where applicable. We have not incurred any counterparty losses related to non-performance and do not anticipate any losses given the information we have currently. However, we cannot be certain that we will not experience such losses in the future. The fair value of our derivative assets and liabilities includes a non-performance risk factor. We refer you to Note 7 and Note 9 of the consolidated financial statements included in this Quarterly Report for additional details about our derivative instruments and their fair value.

ITEM 4. CONTROLS AND PROCEDURES

Disclosure Controls and Procedures

We have performed an evaluation under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of our disclosure controls and procedures, as defined in Rule 13a-15(e) and 15d-15(e) under the Exchange Act as of the end of the period covered by this Quarterly Report. Our disclosure controls and procedures are the controls and other procedures that we have designed to ensure that we record, process, accumulate and communicate information to our management, including our Chief Executive Officer and Chief Financial Officer, to allow timely decisions regarding required disclosures and submission within the time periods specified in the SEC’s rules and forms. All internal control systems, no matter how well designed, have inherent limitations. Therefore, even those determined to be effective can provide only a level of reasonable assurance with respect to financial statement preparation and presentation. Based on the evaluation, our management, including our Chief Executive Officer and Chief Financial Officer, concluded that our disclosure controls and procedures were effective as of September 30, 2023 at a reasonable assurance level.

Changes in Internal Control over Financial Reporting

There were no changes in our internal control over financial reporting (as defined in Rule 13a-15(f) and 15d-15(f) under the Exchange Act) that occurred during the quarter ended September 30, 2023 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

Refer to “Litigation” and “Environmental Risk” in Note 11 to the consolidated financial statements included in Item 1 of Part I of this Quarterly Report for a discussion of the Company’s legal proceedings.

ITEM 1A. RISK FACTORS

There were no additions or material changes to our risk factors as disclosed in Item 1A of Part I in the Company’s 2022 Annual Report.

ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

Not applicable.

ITEM 3. DEFAULTS UPON SENIOR SECURITIES

Not applicable.

ITEM 4. MINE SAFETY DISCLOSURES

Not applicable.

ITEM 5. OTHER INFORMATION

Securities Trading Plans of Directors and Executive Officers

During the three months ended September 30, 2023, 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 promulgated by the SEC.

Table of Contents

Second Amended and Restated Bylaws

On November 1, 2023, the Company’s Board adopted and approved, effective as of such date, the Second Amended and Restated Bylaws of the Company (the “Second Amended and Restated Bylaws”). The Second Amended and Restated Bylaws, among other things:

•revise procedures and disclosure requirements for the nomination of directors and the submission of proposals for consideration at annual meetings of the stockholders of the Company, including, among other things, adding a requirement that a stockholder seeking to nominate director(s) at an annual meeting deliver to the Company reasonable evidence that it has complied with the requirements of Rule 14a-19 of the Exchange Act related to the universal proxy rules at least eight business days prior to the date of such annual meeting;

•clarify the power of the Chair of the Board or the presiding officer of a stockholder meeting to adjourn any meeting of stockholders and the power of the Board to postpone any previously scheduled stockholder meeting;

•specify that, in addition to the Chair of the Board or President of the Company, special meetings of the Board may be called only by a majority of the Board rather than by any two directors; and

•make certain administrative, modernizing, clarifying and confirming changes, including (i) making updates to reflect recent amendments to the Delaware General Corporation Law; (ii) adopting emergency bylaws; (iii) clarifying that for the applicability of the majority voting standard for uncontested elections of directors, an election remains “contested” (and the plurality voting standard applies) even if the Board determines that a stockholder’s nomination notice does not comply with the advance notice bylaws; (iv) clarifying that meetings of stockholders may, in addition to or instead of a physical meeting, be held by means of remote communication (including virtually) as provided under applicable Delaware law; and (v) adopting gender-neutral terms when referring to particular positions, offices or title holders, including the adoption of the title Chair of the Board in place of Chairman of the Board.

The foregoing description of the Second Amended and Restated Bylaws is not complete and is qualified in its entirety by reference to the complete text of the Second Amended and Restated Bylaws, which is filed as Exhibit 3.4 to this Quarterly Report and is incorporated herein by reference.

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ITEM 6. EXHIBITS


(2.1)			Agreement and Plan of Merger, dated August 12, 2020, by and among Southwestern Energy Company and Montage Resources Corporation (Incorporated by reference to Exhibit 2.1 to the Registrant's Current Report on Form 8-K/A filed on August 12, 2020).
(2.2)			Agreement and Plan of Merger, dated June 1, 2021, by and among Southwestern Energy Company, Ikon Acquisition Company, LLC, Indigo Natural Resources LLC, and Ibis Unitholder Representative, LLC solely in its capacity as the Unitholder Representative (Incorporated by reference to Exhibit 2.1 to the Registrant's Current Report on Form 8-K filed on June 2, 2021).
(2.3)			Agreement and Plan of Merger, dated November 3, 2021, by and among Southwestern Energy Company, Mustang Acquisition Company, LLC, GEP Haynesville, LLC, and GEPH Unitholder Rep, LLC solely in its capacity as the Unitholder Representative (Incorporated by reference to Exhibit 2.1 to the Registrant's Current Report on Form 8-K filed on November 5, 2021).
(3.1)			Amended and Restated Certificate of Incorporation of Southwestern Energy Company (Incorporated by reference to Exhibit 3.1 to the Registrant’s Current Report on Form 8-K filed May 24, 2010).
(3.2)			Certificate of Amendment of the Amended and Restated Certificate of Incorporation, dated September 1, 2021 (Incorporated by reference to Exhibit 3.1 to the Registrant’s Current Report on Form 8-K filed September 1, 2021).
(3.3)			Certificate of Amendment No. 2 of the Amended and Restated Certificate of Incorporation, dated May 18, 2023 (Incorporated by reference to Exhibit 3.1 to the Registrant’s Current Report on Form 8-K filed May 22, 2023).
(3.4)*			Second A mended and Restated Bylaws of Southwestern Energy Company, as amended through November 1 , 2023 .






(31.1)*			Certification of CEO filed pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
(31.2)*			Certification of CFO filed pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
(32.1)**			Certification of CEO furnished pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
(32.2)**			Certification of CFO furnished pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
(101.INS)			Inline Interactive Data File Instance Document
(101.SCH)			Inline Interactive Data File Schema Document
(101.CAL)			Inline Interactive Data File Calculation Linkbase Document
(101.LAB)			Inline Interactive Data File Label Linkbase Document
(101.PRE)			Inline Interactive Data File Presentation Linkbase Document
(101.DEF)			Inline Interactive Data File Definition Linkbase Document
(104.1)			Cover Page Interactive Data File – the cover page from this Quarterly Report on Form 10-Q, formatted in inline XBRL (included within the Exhibit 101 attachments)

* Filed herewith

** Furnished herewith

Signatures

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.


		SOUTHWESTERN ENERGY COMPANY
		Registrant

Dated:	November 2, 2023	/s/ CARL F. GIESLER, JR.
		Carl F. Giesler, Jr. Executive Vice President and Chief Financial Officer

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Southwestern Energy (SWN) 10-Q2023 Q3 Quarterly report

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