SOUTHWESTERN ENERGY CO [SWN] Filings

10-Q 1 swn-20240331.htm 10-Q 2024 Q1 FORM 10Q swn-20240331

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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 March 31, 2024

☐ Transition Report pursuant to Section 13 or 15(d) of the Securities

Exchange Act of 1934

For the transition period from ________ to ________

Commission file number: 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 April 30, 2024
Common Stock, Par Value $0.01						1,102,844,906

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SOUTHWESTERN ENERGY COMPANY

INDEX TO FORM 10-Q

FOR THE QUARTERLY PERIOD ENDED MARCH 31, 2024


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		9
		Note 1. Basis of Presentation	9
		Note 2 . Revenue Recognition	10
		Note 3 . Cash and Cash Equivalents	11
		Note 4 . Natural Gas and Oil Properties	12
		Note 5 . Earnings per Share	12
		Note 6 . Derivatives and Risk Management	14
		Note 7 . Reclassifications From Accumulated Other Comprehensive Income (Loss)	19
		Note 8 . Fair Value Measurements	20
		Note 9 . Debt	22
		Note 1 0 . Commitments and Contingencies	25
		Note 1 1 . Income Taxes	26
		Note 1 2 . Long-Term Incentive Compensation	27
		Note 1 3 . Segment Information	31
		Note 1 4 . New Accounting Pronouncements	32

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		33
	Results of Operations		35
	Liquidity and Capital Resources		42
Item 3.	Quantitative and Qualitative Disclosures About Market Risk		46
Item 4.	Controls and Procedures		47

PART II – OTHER INFORMATION

Item 1.	Legal Proceedings		48
Item 1A.	Risk Factors		48
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds		48
Item 3.	Defaults Upon Senior Securities		48
Item 4.	Mine Safety Disclosures		48
Item 5.	Other Information		48
Item 6.	Exhibits		49

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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);

•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;

•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 mergers and acquisitions, including the Proposed Merger (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;

•the comparative cost of alternative fuels;

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•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;

•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 hedging strategy and results;

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

•risks related to the proposed transaction (the “Proposed Merger”) between Southwestern and Chesapeake Energy Corporation (“Chesapeake”), including that the Proposed Merger may not be completed on anticipated terms and timing, or at all, including obtaining regulatory approvals that may be required on anticipated terms and Southwestern and Chesapeake stockholder approval; the possibility that any of the anticipated benefits of the transaction will not be realized or that the two companies will not be successfully integrated; the risk that disruptions from the transaction will harm Southwestern’s business, including current plans and operations and that management’s time and attention will be diverted on transaction-related issues; restrictions on our operations during the pendency of the Proposed Merger, potential adverse reactions or changes to business relationships resulting from the announcement or completion of the Proposed Merger; and potential litigation relating to the Proposed Merger that could be instituted against Southwestern or its directors; 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 March 31,
(in millions, except share/per share amounts)	2024		2023
Operating Revenues:
Gas sales	$	584	$	1,145
Oil sales	82		95
NGL sales	174		201
Marketing	579		679
Other	(2)		(2)
	1,417		2,118
Operating Costs and Expenses:
Marketing purchases	588		667
Operating expenses	417		418
General and administrative expenses	56		46
Merger-related expenses	9		—


Depreciation, depletion and amortization	262		313
Impairments	2,093		—
Taxes, other than income taxes	49		68
	3,474		1,512
Operating Income (Loss)	(2,057)		606
Interest Expense:
Interest on debt	59		63
Other interest charges	3		3
Interest capitalized	(27)		(30)
	35		36

Gain on Derivatives	126		1,401
Loss on Early Extinguishment of Debt	—		(19)
Other Income (Loss), Net	1		(1)

Income (Loss) Before Income Taxes	(1,965)		1,951
Provision (Benefit) for Income Taxes:
Current	—		—
Deferred	(430)		12
	(430)		12
Net Income (Loss)	$	(1,535)	$	1,939


Earnings (Loss) Per Common Share:
Basic	$	(1.39)	$	1.76
Diluted	$	(1.39)	$	1.76

Weighted Average Common Shares Outstanding:
Basic	1,101,824,856		1,100,278,261
Diluted	1,101,824,856		1,102,396,636

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 March 31,
(in millions)	2024		2023
Net income (loss)	$	(1,535)	$	1,939

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
Net actuarial gain (loss) incurred in period	2		(2)
Net tax loss attributable to pension termination	—		(14)
Total change in value of pension and postretirement liabilities	2		(15)
Comprehensive income (loss)	$	(1,533)	$	1,924

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)


	March 31, 2024		December 31, 2023

ASSETS	(in millions)
Current assets:
Cash and cash equivalents	$	29	$	21
Accounts receivable, net	491		680
Derivative assets	640		614
Other current assets	91		100
Total current assets	1,251		1,415
Natural gas and oil properties, using the full cost method, including $2,037 million as of March 31, 2024 and $2,075 million as of December 31, 2023 excluded from amortization	38,308		37,772

Other	573		566
Less: Accumulated depreciation, depletion and amortization	(30,784)		(28,425)
Total property and equipment, net	8,097		9,913
Operating lease assets	144		154
Long-term derivative assets	131		175
Deferred tax assets	674		238
Other long-term assets	101		96
Total long-term assets	1,050		663
TOTAL ASSETS	$	10,398	$	11,991
LIABILITIES AND EQUITY
Current liabilities:
Current portion of long-term debt	$	389	$	—
Accounts payable	1,299		1,384
Taxes payable	123		128
Interest payable	26		77

Derivative liabilities	116		79
Current operating lease liabilities	43		44
Other current liabilities	28		17
Total current liabilities	2,024		1,729
Long-term debt	3,609		3,947
Long-term operating lease liabilities	100		107
Long-term derivative liabilities	75		100

Other long-term liabilities	224		220
Total long-term liabilities	4,008		4,374
Commitments and contingencies (Note 11)
Equity:
Common stock, $0.01 par value; 2,500,000,000 shares authorized; issued 1,164,459,599 shares as of March 31, 2024 and 1,163,077,745 shares as of December 31, 2023	12		12

Additional paid-in capital	7,199		7,188
Accumulated deficit	(2,517)		(982)
Accumulated other comprehensive loss	(1)		(3)
Common stock in treasury, 61,614,693 shares as of March 31, 2024 and December 31, 2023	(327)		(327)
Total equity	4,366		5,888
TOTAL LIABILITIES AND EQUITY	$	10,398	$	11,991

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 three months ended March 31,
(in millions)	2024		2023
Cash Flows From Operating Activities:
Net income (loss)	$	(1,535)	$	1,939
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization	262		313
Amortization of debt issuance costs	2		2
Impairments	2,093		—
Deferred income taxes	(430)		12
(Gain) loss on derivatives, unsettled	30		(1,524)
Stock-based compensation	7		1
Loss on early extinguishment of debt	—		19

Other	1		2
Change in assets and liabilities:
Accounts receivable	190		734
Accounts payable	(94)		(257)
Taxes payable	(5)		(27)
Interest payable	(29)		(33)
Inventories	(1)		(14)
Other assets and liabilities	5		(30)
Net cash provided by operating activities	496		1,137

Cash Flows From Investing Activities:
Capital investments	(521)		(670)




Net cash used in investing activities	(521)		(670)

Cash Flows From Financing Activities:


Payments on long-term debt	—		(437)
Payments on revolving credit facility	(981)		(1,357)
Borrowings under revolving credit facility	1,031		1,317
Change in bank drafts outstanding	(12)		(33)



Cash paid for tax withholding	(5)		(4)



Net cash provided by (used in) financing activities	33		(514)

Increase (decrease) in cash and cash equivalents	8		(47)
Cash and cash equivalents at beginning of year	21		50
Cash and cash equivalents at end of period	$	29	$	3

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, 2023	1,163,077,745	$	12	$	7,188	$	(982)	$	(3)	61,614,693	$	(327)	$	5,888
Comprehensive loss:
Net loss	—	—		—		(1,535)		—		—	—		(1,535)
Other comprehensive income	—	—		—		—		2		—	—		2
Total comprehensive loss	—	—		—		—		—		—	—		(1,533)
Stock-based compensation	—	—		10		—		—		—	—		10



Restricted units vested	2,108,403	—		6		—		—		—	—		6


Tax withholding – stock compensation	(726,549)	—		(5)		—		—		—	—		(5)
Balance at March 31, 2024	1,164,459,599	$	12	$	7,199	$	(2,517)	$	(1)	61,614,693	$	(327)	$	4,366


	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 loss:
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

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 the development of 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, principally serving 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, 2023 (“2023 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 2023 Annual Report.

Proposed merger of the Company with Chesapeake Energy Corporation

On January 10, 2024, the Company entered into an Agreement and Plan of Merger (the “Merger Agreement”) with Chesapeake Energy Corporation, an Oklahoma corporation (“Chesapeake”), Hulk Merger Sub, Inc., a Delaware corporation and a newly formed, wholly owned subsidiary of Chesapeake (“Merger Sub”) and Hulk LLC Sub, LLC, a Delaware limited liability company and a wholly owned subsidiary of Chesapeake (“LLC Sub” and together with Merger Sub, the Company and Chesapeake, the “Parties”), pursuant to which Merger Sub will merge with and into the Company (the “Proposed Merger”), with the Company continuing as a wholly owned subsidiary of Chesapeake (the “Surviving Corporation”). Immediately following the time the Proposed Merger becomes effective (the “Effective Time”), the Surviving Corporation will be merged with and into LLC Sub, with LLC Sub continuing as the surviving entity and as a wholly owned subsidiary of Chesapeake. Under the terms of the Merger Agreement, upon completion of the Proposed Merger, Southwestern shareholders will receive 0.0867 shares of Chesapeake common stock for one share of Southwestern common stock. The consideration to be paid under the Merger Agreement is subject to adjustment as provided in the Merger Agreement. No fractional shares of Chesapeake common stock will be issued in the Proposed Merger, the holders of shares of Southwestern common stock will receive cash in lieu of fractional shares of Chesapeake common stock, if any, in accordance with the terms of the Merger Agreement.

The consummation of the Proposed Merger is subject to the satisfaction or waiver of customary closing conditions, including: receipt of the required approvals from the stockholders of the Company and Chesapeake, and the expiration or

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termination of the extended waiting period imposed by the issuance of a request for additional information and documentary materials by the Federal Trade Commission under the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended (the “HSR Act”) and no agreement between or commitment by the Parties and any governmental entity not to consummate the Proposed Merger being in effect. The Company and Chesapeake have each made customary representations and warranties in the Merger Agreement. The Merger Agreement also contains customary pre-closing covenants of the Company and Chesapeake, including, subject to certain exceptions, covenants relating to conducting their respective businesses in the ordinary course consistent with past practice and refraining from taking certain actions, excepting in each case actions expressly permitted or required by the Merger Agreement, required by law or consented to by the other party in writing. The Merger Agreement provides that in the event of termination of the Merger Agreement under certain circumstances, the Company may be required to reimburse Chesapeake’s expenses up to $55.6 million or pay Chesapeake a termination fee equal to $389 million less any expenses previously paid. Further, Chesapeake may be required to reimburse our expenses up to $37.25 million or pay us a termination fee equal to $260 million less any expenses previously paid.

For the three months ended March 31, 2024, the Company incurred approximately $9 million in merger-related expenses, mostly comprised of professional fees, associated with the Proposed Merger.

(2) 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 to 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 to 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 March 31, 2024
Gas sales	$	571	$	—	$	13	$	584
Oil sales	81		—		1		82
NGL sales	174		—		—		174
Marketing	—		1,377		(798)		579
Other (1)	(2)		—		—		(2)
Total	$	824	$	1,377	$	(784)	$	1,417
(in millions)
Three months ended March 31, 2023
Gas sales	$	1,136	$	—	$	9	$	1,145
Oil sales	94		—		1		95
NGL sales	201		—		—		201
Marketing	—		2,041		(1,362)		679
Other (1)	(2)		—		—		(2)
Total	$	1,429	$	2,041	$	(1,352)	$	2,118

(1)For the three months ended March 31, 2024 and the three months ended March 31, 2023, 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 March 31,
(in millions)	2024		2023
Appalachia	$	554	$	923
Haynesville	270		506

Total	$	824	$	1,429

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)	March 31, 2024		December 31, 2023
Receivables from contracts with customers	$	433	$	622
Other accounts receivable	58		58
Total accounts receivable	$	491	$	680

Amounts recognized against the Company’s allowance for doubtful accounts related to receivables arising from contracts with customers were not significant for both the three months ended March 31, 2024 and year ended December 31, 2023. The Company has no contract assets or contract liabilities associated with its revenues from contracts with customers.

(3) CASH AND CASH EQUIVALENTS

The following table presents a summary of cash and cash equivalents as of March 31, 2024 and December 31, 2023:


(in millions)	March 31, 2024		December 31, 2023
Cash	$	23	$	1
Marketable securities (1)	6		20

Total	$	29	$	21

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

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(4) 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 March 31, 2024. Prices used to calculate the ceiling value of reserves were as follows:


	March 31, 2024		March 31, 2023
Natural gas (per MMBtu)	$	2.45	$	5.96
Oil (per Bbl)	$	77.48	$	90.97
NGLs (per Bbl)	$	21.17	$	30.69

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 exceeded the ceiling amount at March 31, 2024, resulting in an impairment of $2,093 million. 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 and into 2024, the Company expects that an additional non-cash impairment of its asset will likely occur in the second quarter of 2024 and perhaps later.

(5) EARNINGS PER SHARE

Basic earnings per common share is computed by dividing net income (loss) attributable to common stock 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.

The following table presents the computation of earnings per share for the three months ended March 31, 2024 and 2023:


	For the three months ended March 31,
(in millions, except share/per share amounts)	2024		2023
Net income (loss)	$	(1,535)	$	1,939

Number of common shares:
Weighted average outstanding	1,101,824,856		1,100,278,261

Effect of issuance of non-vested restricted common stock	—		790,131
Effect of issuance of non-vested restricted units	—		1,328,244

Weighted average and dilutive outstanding	1,101,824,856		1,102,396,636

Earnings (loss) per common share
Basic	$	(1.39)	$	1.76
Diluted	$	(1.39)	$	1.76

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The following table presents the common stock shares equivalent excluded from the calculation of diluted earnings per share for the three months ended March 31, 2024 and 2023, as they would have had an antidilutive effect:


	For the three months ended March 31,
	2024	2023
Unexercised stock options	459,638	866,318
Unvested restricted common stock	977,979	—
Restricted units	3,490,947	1,914,812
Performance units	554,248	326,088
Total	5,482,812	3,107,218

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(6) 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 March 31, 2024 and March 31, 2023, the Company’s derivative financial instruments consisted of fixed price swaps, two-way costless collars, three-way costless collars, basis swaps, and options (calls and puts). 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.

The Company chooses 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 derivative positions on a gross basis and does not net the asset and liability positions.

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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 March 31, 2024:


Financial Protection on Production
		Weighted Average Price per MMBtu
	Volume (Bcf)	Swaps		Sold Puts		Purchased Puts		Sold Calls		Basis Differential		Fair Value at March 31, 2024 (in millions)
Natural Gas
2024
Fixed price swaps	409	$	3.58	$	—	$	—	$	—	$	—	$	486
Two-way costless collars	33	—		—		3.07		3.53		—		24
Three-way costless collars	60	—		2.50		3.25		4.19		—		30
Total	502											$	540
2025
Fixed price swaps	33	$	3.47	$	—	$	—	$	—	$	—	$	—
Two-way costless collars	73	—		—		3.50		5.40		—		33
Three-way costless collars	161	—		2.59		3.66		5.88		—		62
Total	267											$	95










Basis Swaps
2024	94	$	—	$	—	$	—	$	—	$	(0.71)	$	(11)
2025	9	—		—		—		—		(0.64)		2


Total	103											$	(9)

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	Volume (MBbls)	Weighted Average Strike Price per Bbl								Fair Value at March 31, 2024 (in millions)
		Swaps		Sold Puts		Purchased Puts		Sold Calls
Oil
2024
Fixed price swaps	1,057	$	71.62	$	—	$	—	$	—	$	(9)
Two-way costless collars	348	—		—		70.00		86.40		(1)
Three-way costless collars	534	—		56.72		66.72		88.26		(1)
Total	1,939									$	(11)
2025
Fixed price swaps	41	$	77.66	$	—	$	—	$	—	$	—
Three-way costless collars	1,278	—		58.92		68.92		92.83		—
Total	1,319									$	—







Ethane
2024
Fixed price swaps	5,335	$	10.05	$	—	$	—	$	—	$	10


2025
Fixed price swaps	2,190	$	10.19	$	—	$	—	$	—	$	—







Propane
2024
Fixed price swaps	4,483	$	31.23	$	—	$	—	$	—	$	(17)


2025
Fixed price swaps	1,341	$	30.25	$	—	$	—	$	—	$	(1)





Normal Butane
2024
Fixed price swaps	1,073	$	39.42	$	—	$	—	$	—	$	(2)
2025
Fixed price swaps	548	$	35.28	$	—	$	—	$	—	$	—

Natural Gasoline
2024
Fixed price swaps	1,210	$	61.45	$	—	$	—	$	—	$	(5)
2025
Fixed price swaps	730	$	56.44	$	—	$	—	$	—	$	(4)


Other Derivative Contracts
	Volume (Bcf)	Weighted Average Strike Price per MMBtu		Fair Value at March 31, 2024 (in millions)





Call Options – Natural Gas (Net)
2024	55	$	7.00	$	—
2025	73	7.00		(4)
2026	73	7.00		(11)


Total	201			$	(15)

At March 31, 2024, the net fair value of the Company’s financial instruments was a $580 million asset, which included net reduction of the asset of $1 million related to non-performance risk. See Note 8 for additional details regarding the Company’s fair value measurements of its derivatives position.

As of March 31, 2024, 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

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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 March 31, 2024 and December 31, 2023:


Derivative Assets
		Fair Value
(in millions)	Balance Sheet Classification	March 31, 2024		December 31, 2023
Derivatives not designated as hedging instruments:



Fixed price swaps – natural gas	Derivative assets	$	498	$	466
Fixed price swaps – oil	Derivative assets	—		1
Fixed price swaps – ethane	Derivative assets	10		9
Fixed price swaps – propane	Derivative assets	1		12
Fixed price swaps – normal butane	Derivative assets	—		1
Fixed price swaps – natural gasoline	Derivative assets	—		2
Two-way costless collars – natural gas	Derivative assets	38		36
Two-way costless collars – oil	Derivative assets	—		3

Three-way costless collars – natural gas	Derivative assets	84		62
Three-way costless collars – oil	Derivative assets	3		1
Basis swaps – natural gas	Derivative assets	7		14
Put options – natural gas	Derivative assets	—		8



Fixed price swaps – natural gas	Other long-term assets	3		—





Two-way costless collars – natural gas	Other long-term assets	33		46


Three-way costless collars – natural gas	Other long-term assets	86		116
Three-way costless collars – oil	Other long-term assets	7		10
Basis swaps – natural gas	Other long-term assets	2		4



Total derivative assets		$	772	$	791


Derivative Liabilities
		Fair Value
(in millions)	Balance Sheet Classification	March 31, 2024		December 31, 2023
Derivatives not designated as hedging instruments:



Fixed price swaps – natural gas	Derivative liabilities	$	12	$	18
Fixed price swaps – oil	Derivative liabilities	9		2

Fixed price swaps – propane	Derivative liabilities	18		1
Fixed price swaps – normal butane	Derivative liabilities	2		—
Fixed price swaps – natural gasoline	Derivative liabilities	6		—
Two-way costless collars – natural gas	Derivative liabilities	6		14
Two-way costless collars – oil	Derivative liabilities	1		1

Three-way costless collars – natural gas	Derivative liabilities	40		27
Three-way costless collars – oil	Derivative liabilities	3		1

Basis swaps – natural gas	Derivative liabilities	18		6
Call options – natural gas	Derivative liabilities	1		1

Put options – natural gas	Derivative liabilities	—		8



Fixed price swaps – natural gas	Long-term derivative liabilities	3		—


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

Fixed price swaps – natural gasoline	Long-term derivative liabilities	3		—
Two-way costless collars – natural gas	Long-term derivative liabilities	8		15

Three-way costless collars – natural gas	Long-term derivative liabilities	38		60
Three-way costless collars – oil	Long-term derivative liabilities	8		8


Call options – natural gas	Long-term derivative liabilities	14		17

Total derivative liabilities		$	191	$	179

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Net Derivative Position
	March 31, 2024		December 31, 2023
(in millions)
Net current derivative asset (liability)	$	525	$	536
Net long-term derivative asset (liability)	56		76
Non-performance risk adjustment	(1)		(2)
Net total derivative asset (liability)	$	580	$	610

The following tables summarize the before-tax effect of the Company’s derivative instruments on the consolidated statements of operations for the three months ended March 31, 2024 and 2023:


Unsettled Gain (Loss) on Derivatives Recognized in Earnings

	Consolidated Statement of Operations Classification of Gain (Loss) on Derivatives, Unsettled			For the three months ended March 31,
Derivative Instrument				2024				2023

				(in millions)

Fixed price swaps – natural gas	Gain (Loss) on Derivatives			$	38			$	961
Fixed price swaps – oil	Gain (Loss) on Derivatives			(8)				12
Fixed price swaps – ethane	Gain (Loss) on Derivatives			1				9
Fixed price swaps – propane	Gain (Loss) on Derivatives			(29)				1
Fixed price swaps – normal butane	Gain (Loss) on Derivatives			(3)				1
Fixed price swaps – natural gasoline	Gain (Loss) on Derivatives			(11)				1
Two-way costless collars – natural gas	Gain (Loss) on Derivatives			4				241
Two-way costless collars – oil	Gain (Loss) on Derivatives			(3)				—


Three-way costless collars – natural gas	Gain (Loss) on Derivatives			1				263
Three-way costless collars – oil	Gain (Loss) on Derivatives			(3)				12

Basis swaps – natural gas	Gain (Loss) on Derivatives			(21)				(30)
Call options – natural gas	Gain (Loss) on Derivatives			3				61

Sold put options - natural gas	Gain (Loss) on Derivatives			8				(6)
Purchased put options – natural gas	Gain (Loss) on Derivatives			(8)				2




Total gain (loss) on unsettled derivatives		$	(31)			$	1,528

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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 March 31,
Derivative Instrument				2024				2023

				(in millions)

Fixed price swaps – natural gas	Gain (Loss) on Derivatives			$	140			$	(45)
Fixed price swaps – oil	Gain (Loss) on Derivatives			(4)				(4)
Fixed price swaps – ethane	Gain (Loss) on Derivatives			3				1
Fixed price swaps – propane	Gain (Loss) on Derivatives			(2)				1
Fixed price swaps – normal butane	Gain (Loss) on Derivatives			(1)				—
Fixed price swaps – natural gasoline	Gain (Loss) on Derivatives			(1)				—
Two-way costless collars – natural gas	Gain (Loss) on Derivatives			9				—



Three-way costless collars – natural gas	Gain (Loss) on Derivatives			16				(33)
Three-way costless collars – oil	Gain (Loss) on Derivatives			—				(7)

Basis swaps – natural gas	Gain (Loss) on Derivatives			(4)				(29)

Call options – natural gas	Gain (Loss) on Derivatives			—				(7)

Sold put options - natural gas	Gain (Loss) on Derivatives			(10)				—
Purchased put options – natural gas	Gain (Loss) on Derivatives			10				—




Total gain (loss) on settled derivatives		$	156			$	(123)

Total gain (loss) on derivatives (2)		$	126			$	1,401

(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 $1 million in gains and $4 million in losses for the three months ended March 31, 2024 and March 31, 2023, respectively.


Total Gain (Loss) on Derivatives Recognized in Earnings
	For the three months ended March 31,
	2024		2023

	(in millions)
Total gain (loss) on unsettled derivatives	$	(31)	$	1,528
Total gain (loss) on settled derivatives	156		(123)
Non-performance risk adjustment	1		(4)
Total gain (loss) on derivatives	$	126	$	1,401

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

The following tables detail the components of accumulated other comprehensive income (loss) for the three months ended March 31, 2024:


(in millions)	Other Postretirement		Foreign Currency		Total
Beginning balance December 31, 2023	$	11	$	(14)	$	(3)
Other comprehensive income before reclassifications	—		—		—
Amounts reclassified from other comprehensive income (1)	2		—		2
Net current-period other comprehensive income	2		—		2
Ending balance March 31, 2024	$	13	$	(14)	$	(1)

(1)Includes a $2 million actuarial gain related to the other postretirement plan.

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(8) FAIR VALUE MEASUREMENTS

The carrying amounts and estimated fair values of the Company’s financial instruments as of March 31, 2024 and December 31, 2023 were as follows:


	March 31, 2024				December 31, 2023
(in millions)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Cash and cash equivalents	$	29	$	29	$	21	$	21
2022 revolving credit facility due April 2027	270		270		220		220

Senior notes (1)	3,743		3,599		3,743		3,626
Derivative instruments, net	580		580		610		610

(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 9 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 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 March 31, 2024 and as of December 31, 2023. As of March 31, 2024 and December 31, 2023, 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 $2 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’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.

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


	March 31, 2024
	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	$	—	$	512	$	—	$	512
Two-way costless collars	—		71		—		71
Three-way costless collars	—		180		—		180
Basis swaps	—		9		—		9




Liabilities

Fixed price swaps	—		(54)		—		(54)
Two-way costless collars	—		(15)		—		(15)
Three-way costless collars	—		(89)		—		(89)
Basis swaps	—		(18)		—		(18)
Call options	—		(15)		—		(15)




Total (1)	$	—	$	581	$	—	$	581

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


	December 31, 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	$	—	$	491	$	—	$	491
Two-way costless collars	—		85		—		85
Three-way costless collars	—		189		—		189
Basis swaps	—		18		—		18


Purchase Put - Natural Gas	—		8		—		8
Liabilities

Fixed price swaps	—		(21)		—		(21)
Two-way costless collars	—		(30)		—		(30)
Three-way costless collars	—		(96)		—		(96)
Basis swaps	—		(6)		—		(6)
Call options	—		(18)		—		(18)
Put options	—		(8)		—		(8)



Total (1)	$	—	$	612	$	—	$	612

(1)Excludes a net reduction to the asset fair value of $2 million related to estimated non-performance risk.

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(9) DEBT

The components of debt as of March 31, 2024 and December 31, 2023 consisted of the following:


	March 31, 2024
(in millions)	Debt Instrument		Unamortized Issuance Expense			Unamortized Debt Premium/Discount		Total
Current portion of long-term debt:
4.95% Senior Notes due January 2025 (1)	$	389	$	—		$	—	$	389
Total current portion of long-term debt	$	389	$	—		$	—	$	389

Long-term debt:
Variable rate (7.16% at March 31, 2024) 2022 revolving credit facility, due April 2027	$	270	$	—	(2)	$	—	$	270




8.375% Senior Notes due September 2028	304		(3)			—		301
5.375% Senior Notes due February 2029	700		(4)			17		713
5.375% Senior Notes due March 2030	1,200		(12)			—		1,188
4.75% Senior Notes due February 2032	1,150		(13)			—		1,137
Total long-term debt	$	3,624	$	(32)		$	17	$	3,609

Total debt	$	4,013	$	(32)		$	17	$	3,998

	December 31, 2023
(in millions)	Debt Instrument		Unamortized Issuance Expense			Unamortized Debt Premium/Discount		Total






Variable rate (7.20% at December 31, 2023) 2022 revolving credit facility, due April 2027	$	220	$	—	(2)	$	—	$	220
4.95% Senior Notes due January 2025 (1)	389		—			—		389


8.375% Senior Notes due September 2028	304		(3)			—		301
5.375% Senior Notes due February 2029	700		(5)			18		713
5.375% Senior Notes due March 2030	1,200		(13)			—		1,187
4.75% Senior Notes due February 2032	1,150		(13)			—		1,137


Total debt	$	3,963	$	(34)		$	18	$	3,947

(1)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 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 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.

(2)At March 31, 2024 and December 31, 2023, unamortized issuance expense of $14 million and $15 million, respectively, associated with the 2022 credit facility (as defined below) was classified as other long-term assets on the consolidated balance sheets.

The following is a summary of scheduled debt maturities by year as of March 31, 2024:


(in millions)
2024	$	—
2025	389
2026	—
2027	270
2028	304
Thereafter	3,050
	$	4,013

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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, that as amended, has a maturity date of April 2027 (the “2022 credit facility”). As of March 31, 2024, 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 March 29, 2024, the Company’s borrowing base was reaffirmed at $3.5 billion and the Five-Year Tranche was reaffirmed at $2.0 billion with 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 no 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 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 no 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. Consolidated 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

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immediately due and payable. As of March 31, 2024, 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 became a guarantor of the 2022 credit facility also became 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 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 March 31, 2024, the Company had no outstanding letters of credit and $270 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

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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.

On February 26, 2023, the Company redeemed all of its 7.75% Senior Notes due October 2027 (the “2027 Notes”) 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. 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.

(10) COMMITMENTS AND CONTINGENCIES

Operating Commitments and Contingencies

As of March 31, 2024, 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 $9.2 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 March 31, 2024, the Company also had guarantee obligations of up to $959 million of that total amount. As of March 31, 2024, 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	$	8,016	$	1,030	$	1,950	$	1,698	$	1,634	$	1,704
Pending regulatory approval and/or construction (1)	1,192		61		170		195		294		472
Total transportation charges	$	9,208	$	1,091	$	2,120	$	1,893	$	1,928	$	2,176

(1)Based on estimated in-service dates as of March 31, 2024.

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.

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 March 31, 2024, 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

On September 1, 2021, the Company completed a merger with Indigo Natural Resources LLC (“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 exploration and production activity on certain acreage located in DeSoto Parish, Louisiana. The plaintiffs, who claim to own the properties at issue, assert

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that Indigo’s actions and the actions of other current operators conducting exploration 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, including punitive damages.

On September 13, 2018, Indigo and other defendants 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. The parties are currently engaging in settlement discussions.

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.

(11) INCOME TAXES

The Company’s effective tax rate was approximately 22% and 1% for the three months ended March 31, 2024 and March 31, 2023, respectively. The effective tax rate for the three months ended March 31, 2023 was primarily the result of the partial release of the valuation allowances against the Company’s U.S. deferred tax assets in the first quarter of 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, 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 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 $512 million of its federal and state deferred tax assets were more likely than not to be realized and released this portion of the valuation allowance throughout 2023. Accordingly, during the three months ended March 31, 2023, the Company recognized $451 million of deferred income tax expense related to recording its tax provision which was partially offset by $439 million of tax benefit attributable to the release of the valuation allowance. The remaining valuation allowance was released during subsequent quarters during 2023. The Company expects to keep a valuation allowance of $52 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.

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Due to the issuance of common stock associated with the Indigo merger in September 2021, 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 March 31, 2024, 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.

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. The Company was not impacted by the alternative minimum tax during 2023 and does not expect to be impacted by this alternative minimum tax during 2024. The Company will continue to monitor updates to the IRA and the impact it will have on the Company’s consolidated financial statements.

(12) 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 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. There were no performance unit awards granted as of March 31, 2024.

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The Company recognized the following amounts in total related to long-term incentive compensation costs for the three months ended March 31, 2024 and 2023:


	For the three months ended March 31,
(in millions)	2024		2023
Long-term incentive compensation – expensed	$	11	$	4
Long-term incentive compensation – capitalized	$	6	$	3

Equity-Classified Awards

The Company recognized the following amounts in employee equity-classified stock-based compensation costs for the three months ended March 31, 2024 and 2023:


	For the three months ended March 31,
(in millions)	2024		2023
Equity-classified awards – expensed	$	7	$	1
Equity-classified awards – capitalized	$	3	$	1

Equity-Classified Stock Options

The following table summarizes equity-classified stock option activity for the three months ended March 31, 2024 and provides information for options outstanding and options exercisable as of March 31, 2024:


	Number of Options	Weighted Average Exercise Price
	(in thousands)
Outstanding at December 31, 2023	820	$	8.59
Granted	—	$	—
Exercised	—	$	—
Forfeited or expired	(820)	$	8.59
Outstanding at March 31, 2024	—	$	—
Exercisable at March 31, 2024	—	$	—

Equity-Classified Restricted Stock

As of March 31, 2024, 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 0.1 year. The following table summarizes equity-classified restricted stock activity for the three months ended March 31, 2024 and provides information for unvested shares as of March 31, 2024:


	Number of Shares	Weighted Average Fair Value
	(in thousands)
Unvested shares at December 31, 2023	169	$	5.09
Granted	—	$	—
Vested	(54)	$	4.90
Forfeited	—	$	—
Unvested shares at March 31, 2024	115	$	5.17

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Equity-Classified Restricted Stock Units

As of March 31, 2024, there was $20 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 2.4 years. The following table summarizes equity-classified restricted stock units for the three months ended March 31, 2024 and provides information for unvested units as of March 31, 2024.


	Number of Shares	Weighted Average Fair Value
	(in thousands)
Unvested units at December 31, 2023	2,706	$	4.74
Granted	3,182	$	7.10
Vested	(1,084)	$	4.69
Forfeited	—	$	—
Unvested units at March 31, 2024	4,804	$	6.32

Equity-Classified Performance Units

In each year from 2018 to 2023, 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). No performance units were granted as of March 31, 2024. The fair values of the market conditions were calculated by Monte Carlo models as of the grant date. As of March 31, 2024, there was $5 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 1.6 years.


	Number of Shares	Weighted Average Fair Value
	(in thousands)
Unvested units at December 31, 2023	1,757	$	6.08
Granted	—	$	—
Vested	—	$	—
Forfeited	—	$	—
Unvested units at March 31, 2024	1,757	$	6.08

Liability-Classified Awards

The Company recognized the following amounts in employee liability-classified stock-based compensation costs for the three months ended March 31, 2024:


	For the three months ended March 31,
(in millions)	2024		2023
Liability-classified stock-based compensation cost – expensed	$	1	$	1
Liability-classified stock-based compensation cost – capitalized	$	—	$	—

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Liability-Classified Restricted Stock Units

In each year from 2018 to 2020, 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 March 31, 2024, the liability-classified restricted stock units fully vested.


	Number of Units	Weighted Average Fair Value
	(in thousands)
Unvested units at December 31, 2023	1,741	$	4.67
Granted	—	$	—
Vested	(1,741)	$	6.93
Forfeited	—	$	—
Unvested units at March 31, 2024	—	$	—

Liability-Classified Performance Units

In each year from 2018 to 2023, 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. No performance units were granted as of March 31, 2024. Changes in the fair market value of the instruments for liability-classified awards are 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 March 31, 2024, there was $3 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 1.8 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, 2023	12,152	$	0.94
Granted	—	$	—
Vested	(3,365)	$	1.59
Forfeited	—	$	—
Unvested units at March 31, 2024	8,787	$	0.55

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Cash-Based Compensation

The Company recognized the following amounts in performance cash award compensation costs for the three months ended March 31, 2024 and 2023:


	For the three months ended March 31,
(in millions)	2024		2023
Performance cash awards – expensed	$	3	$	2
Performance cash awards – capitalized	$	3	$	2

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 and 2024, 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 2024 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 March 31, 2024, there was $54 million of total unrecognized compensation cost related to performance cash awards. This cost is expected to be recognized over a weighted-average period of 2.3 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, 2023	49,678	$	1.00
Granted	28,202	$	1.00
Vested	(20,232)	$	1.00
Forfeited	(364)	$	1.00
Unvested units at March 31, 2024	57,284	$	1.00

(13) 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 2023 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		Total Reportable Segments		Other		Total

Three months ended March 31, 2024	(in millions)
Revenues from external customers	$	838		$	579	$	1,417	$	—	$	1,417
Intersegment revenues	(14)			798		784		—		784
Depreciation, depletion and amortization expense	261			1		262		—		262
Impairments	2,093			—		2,093		—		2,093
Operating income (loss)	(2,061)			4		(2,057)		—		(2,057)
Interest expense (1)	35			—		35		—		35
Gain on derivatives	126			—		126		—		126

Other income, net	1			—		1		—		1
Benefit for income taxes (1)	(430)			—		(430)		—		(430)
Assets	9,856		(2)	391		10,247		151		10,398
Capital investments (3)	537			—		537		1		538

Three months ended March 31, 2023
Revenues from external customers	$	1,439		$	679	$	2,118	$	—	$	2,118
Intersegment revenues	(10)			1,362		1,352		—		1,352
Depreciation, depletion and amortization expense	312			1		313		—		313

Operating income	578			28		606		—		606
Interest expense (1)	36			—		36		—		36
Gain on derivatives	1,401			—		1,401		—		1,401
Loss on early extinguishment of debt	—			—		—		(19)		(19)
Other loss, net	(1)			—		(1)		—		(1)
Provision for income taxes (1)	12			—		12		—		12
Assets	12,260		(2)	552		12,812		125		12,937
Capital investments (3)	664			—		664		1		665

(1)Interest expense and provision (benefit) 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.

(3)Capital investments include an increase of $14 million and a decrease $6 million for the three months ended March 31, 2024 and March 31, 2023, respectively, relating to the change in accrued expenditures between periods.

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 March 31, 2024 and 2023:


	As of March 31,
(in millions)	2024		2023
Cash and cash equivalents	$	29	$	3
Accounts receivable	—		1


Prepayments	15		12
Other current assets	1		—
Property, plant and equipment	23		19
Unamortized debt expense	14		18
Right-of-use lease assets	47		55
Non-qualified retirement plan	2		2

Other long-term assets (1)	20		15
	$	151	$	125

(1)Consists primarily of costs associated with the development of the Company’s enterprise resource technology as of March 31, 2024 and residual assets associated with the Company’s pension plan as of March 31, 2023, respectively.

(14) NEW ACCOUNTING PRONOUNCEMENTS

New Accounting Standards Implemented in this Report

None.

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New Accounting Standards Not Yet Adopted in this Report

In November 2023, the Financial Accounting Standards Board (the “FASB”) issued ASU 2023-07, Segment Reporting (Topic 280): Improvements to Reportable Segment Disclosures. This update is to enhance disclosures on reportable segments and provide additional detailed information about significant segment expenses. The guidance in ASU 2023-07 is effective for fiscal years beginning after December 15, 2023 and interim periods within fiscal years beginning after December 15, 2024. The Company continues to assess the impact of the new guidance, but it is not expected to have a material impact on the consolidated financial statements.

In December 2023, the FASB issued ASU 2023-09 Income Taxes (Topic 740): Improvements to Income Tax Disclosures. This update is to enhance disclosures through further disaggregated information on the effective tax rate reconciliation based on specified categories, as well as disaggregation of incomes taxes paid by jurisdiction. The guidance in ASU 2023-09 is effective for fiscal years beginning after December 15, 2024. The Company continues to assess the impact of the new guidance, but it is not expected to have a material impact on the consolidated financial statements.

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, 2023 (the “2023 Annual Report”) and analyzes the changes in the results of operations between the three month periods ended March 31, 2024 and 2023. 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 2023 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 2023 Annual Report. You should read the following discussion with our consolidated financial statements and the related notes included in this Quarterly Report.

OVERVIEW

Proposed Merger with Chesapeake

On January 10, 2024, we entered into a Merger Agreement with Chesapeake, Merger Sub and LLC Sub, pursuant to which, among other things, we will survive as a wholly owned subsidiary of Chesapeake. Under the terms of the Merger Agreement, each eligible share of our common stock will be converted into the right to receive 0.0867 shares of Chesapeake common stock. Completion of the Proposed Merger remains subject to certain conditions, including the approval of the Proposed Merger by the our shareholders, approval by Chesapeake shareholders of the issuance of Chesapeake common stock in connection with the Proposed Merger, as well as certain governmental and regulatory approvals. The Proposed Merger is currently targeted to close in the second half of 2024; however, no assurance can be given as to when, or if, the Proposed Merger will occur.

The above description of the Merger Agreement and the transactions contemplated thereby, including certain referenced terms, is a summary of certain principal terms and conditions contained in the Merger Agreement, a copy of which is attached as Exhibit 2.1 to the Company’s Current Report on Form 8-K, filed January 11, 2024.

On April 4, 2024, Southwestern and Chesapeake each received a request for additional information and documentary material (collectively, the “Second Request”) from the Federal Trade Commission (the “FTC”), as disclosed in the Company’s Current Report on Form 8-K, filed April 5, 2024. Issuance of the Second Request extends the waiting period imposed by the HSR Act until 30 days after each of Southwestern and Chesapeake have substantially complied with the Second Request, unless the waiting period is earlier terminated. Southwestern and Chesapeake will continue to cooperate fully with the FTC in its review.

See Note 1 - Basis of Presentation of Notes to Consolidated Financial Statements included in “Item 1. Financial Statements” for additional information. Also, see the risk factors and other cautionary statements, specifically, Risks Related to the Proposed Merger with Chesapeake under the heading “Risk Factors” in Item 1A of our 2023 Annual Report.

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,

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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 reservoirs and give us additional exposure to the LNG corridor and other markets on the U.S. Gulf Coast. 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.

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 first quarter 2024 operating and financial results include:

Total Company

•Net loss of $1,535 million, or ($1.39) per diluted share, decreased compared to net income of $1,939 million, or $1.76 per diluted share, for the same period in 2023. Net income decreased due to lower operating income of $2,663 million primarily associated with a full cost ceiling test impairment write-down of $2,093 million along with lower realized pricing and production, and a reduced gain in our net derivative position of approximately $1,275 million. The decrease in net income from the first quarter of 2023 to the first quarter of 2024 was partially offset by a decrease in our income tax provision of $442 million and a $19 million loss on early debt extinguishment in 2023 compared to no gain or loss in 2024.

•Operating loss of $2,057 million decreased compared to operating income of $606 million for the same period in 2023 on a consolidated basis. Operating income decreased due to a $701 million decrease in operating revenues, attributable to lower realized pricing and production in addition to a full cost ceiling test impairment write-down of $2,093 million. The decrease in operating income from the first quarter of 2023 to the first quarter of 2024 was partially offset by lower operating costs of $131 million primarily associated with the impact of lower realized pricing and production on marketing purchases and production taxes.

•Net cash provided by operating activities of $496 million decreased as compared to $1,137 million for the same period in 2023. The decrease was primarily attributable to the impact of lower commodity pricing on revenues of $479 million, lower production of $126 million, and negative changes in working capital of $307 million and was partially offset by an increase in our settled derivative positions of $279 million.

•Total capital investment of $538 million in the first quarter of 2024 decreased 19% from $665 million for the same period in 2023 primarily due to lower activity levels associated with lower commodity pricing period over period.

E&P

•E&P operating loss of $2,061 million in the first quarter of 2024 decreased from operating income of $578 million in the first quarter of 2023 for a total decrease of $2,639 million, primarily due to a $605 million decrease in E&P operating revenues resulting from a $1.28 per Mcfe decrease in our realized weighted average price per Mcfe (excluding derivatives) and a 35 Bcfe decrease in production volumes. The decrease in operating income was partially offset by a $59 million decrease in E&P operating costs and expenses, excluding $2,093 million of non-cash full cost ceiling test impairments recognized during the first quarter of 2024.

•Total net production of 376 Bcfe, which was comprised of 86% natural gas and 14% oil and NGLs, decreased 9% from 411 Bcfe in the same period in 2023, primarily due to an 8% decrease in our natural gas production as a result of lower activity period over period.

•Excluding the effect of derivatives, our realized natural gas price of $1.76 per Mcf decreased 45%, our realized oil price of $66.07 per barrel increased slightly from $65.92 and our realized NGL price of $23.88 per barrel decreased 2%, as compared to the same period in 2023. Excluding the effect of derivatives, our total weighted average realized price of $2.20 per Mcfe decreased 37% from the same period in 2023.

•E&P segment invested $537 million in capital; drilling 29 wells, completing 27 wells and placing 18 wells to sales.

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Outlook

Our primary focus in 2024 is to align capital investment with expected annual cash flow in a manner that maintains production capacity.

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; enhancing the 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 attractive debt maturity profile; improving our credit ratings; lowering our weighted average cost of debt; 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, emerging technology, 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 Item 1A. Risk Factors in the 2023 Annual Report. As such, we intend to protect our financial strength by reducing 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 March 31,
(in millions)	2024		2023
Revenues	$	824	$	1,429
Operating costs and expenses	2,885		851
Operating income (loss)	$	(2,061)	$	578

Gain (loss) on derivatives, settled	$	156	$	(123)

Operating Income (Loss)

•E&P segment operating income decreased $2,639 million for the three months ended March 31, 2024, compared to operating income of $578 million during the same period in 2023. Excluding the impact of the $2,093 million non-cash full cost ceiling test impairments, the decrease was primarily due to a $605 million decrease in E&P operating revenues resulting from a 37% decrease in our realized weighted average price per Mcfe (excluding derivatives) and a 9% decrease in production volumes partially offset by a $59 million decrease in E&P operating costs and expenses.

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Revenues

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


	Three months ended March 31,
(in millions except percentages)	Natural Gas			Oil			NGLs			Total
2023 sales revenues (1)	$	1,136		$	94		$	201		$	1,431
Changes associated with prices	(475)			(1)			(3)			(479)
Changes associated with production volumes	(90)			(12)			(24)			(126)
2024 sales revenues (2)	$	571		$	81		$	174		$	826
Decrease from 2023	(50		%)	(14		%)	(13		%)	(42		%)

(1)Excludes $2 million in other operating revenues for the three months ended March 31, 2023 primarily related to gas balancing losses.

(2)Excludes $2 million in other operating revenues for the three months ended March 31, 2024 primarily related to gas balancing losses.

Production Volumes


	For the three months ended March 31,				Increase/(Decrease)
Production volumes:	2024		2023
Natural Gas (Bcf)
Appalachia	187		193		(3)%
Haynesville	138		160		(14)%

Total	325		353		(8)%

Oil (MBbls)
Appalachia	1,226		1,409		(13)%
Haynesville	5		8		(38)%
Other	—		1		(100)%
Total	1,231		1,418		(13)%

NGL (MBbls)
Appalachia	7,260		8,240		(12)%
Haynesville	1		—		100%

Total	7,261		8,240		(12)%

Production volumes by area: (Bcfe)
Appalachia	238		251		(5)%
Haynesville	138		160		(14)%

Total	376		411		(9)%

Production volumes by formation: (Bcfe)
Marcellus Shale	213		220		(3)%
Utica Shale	24		31		(23)%
Haynesville Shale	78		98		(20)%
Bossier Shale	61		62		(2)%

Total	376		411		(9)%

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

•E&P production volumes decreased by 35 Bcfe for the three months ended March 31, 2024, respectively, compared to the same periods in 2023. The decrease in production volumes is primarily attributable to lower natural gas production as a result of our moderation of activity related to the decrease in near-term natural gas prices.

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•Oil and NGL production decreased 12% for the three months ended March 31, 2024 as compared to the same period in 2023, primarily due to our moderation of activity related to the decrease in near-term pricing.

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.


	For the three months ended March 31,						Increase/(Decrease)
	2024			2023
Natural Gas Price:
NYMEX Henry Hub Price ($/MMBtu) (1)	$	2.24		$	3.42		(35)%
Discount to NYMEX (2)	(0.48)			(0.20)			140%
Average realized gas price, excluding derivatives ($/Mcf)	$	1.76		$	3.22		(45)%
Gain on settled financial basis derivatives ($/Mcf)	(0.01)			(0.08)
Gain (loss) on settled commodity derivatives ($/Mcf)	0.50			(0.24)
Average realized gas price, including derivatives ($/Mcf)	$	2.25		$	2.90		(22)%

Oil Price:
WTI oil price ($/Bbl) (3)	$	76.96		$	76.13		1%
Discount to WTI (4)	(10.89)			(10.21)			7%
Average realized oil price, excluding derivatives ($/Bbl)	$	66.07		$	65.92		—%
Loss on settled derivatives ($/Bbl)	(2.98)			(7.75)
Average realized oil price, including derivatives ($/Bbl)	$	63.09		$	58.17		8%

NGL Price:
Average realized NGL price, excluding derivatives ($/Bbl)	$	23.88		$	24.39		(2)%
Gain (loss) on settled derivatives ($/Bbl)	(0.12)			0.19
Average realized NGL price, including derivatives ($/Bbl)	$	23.76		$	24.58		(3)%
Percentage of WTI, excluding derivatives	31		%	32		%

Total Weighted Average Realized Price:
Excluding derivatives ($/Mcfe)	$	2.20		$	3.48		(37)%
Including derivatives ($/Mcfe)	$	2.61		$	3.18		(18)%

(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 6 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 March 31, 2024:


	Volume (Bcf)	Basis Differential
Basis Swaps – Natural Gas

2024	94	$	(0.71)
2025	9	(0.64)


Total	103

Physical NYMEX Sales Arrangements – Natural Gas (1)
2024	670	$	0.24
2025	600	0.13
2026	419	0.07
2027	340	0.03
2028	303	0.02
2029	252	0.01
2030	105	0.01



Total	2,689

(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 March 31, 2024:


	Remaining 2024	Full Year 2025
Natural gas (Bcf)	502	267
Oil (MBbls)	1,939	1,319
Ethane (MBbls)	5,335	2,190
Propane (MBbls)	4,483	1,341
Normal butane (MBbls)	1,073	548
Natural gasoline (MBbls)	1,210	730
Total financial protection on future production (Bcfe)	586	304

We refer you to Note 6 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 March 31,				Increase/(Decrease)
(in millions except percentages)	2024		2023
Lease operating expenses	$	423	$	430	(2)%
General & administrative expenses	50		42		19%
Merger-related expenses	9		—		100%

Taxes, other than income taxes	49		67		(27)%
Full cost pool amortization	257		308		(17)%
Non-full cost pool DD&A	4		4		—%

Full cost pool write-down	2,093		—		100%
Total operating costs	$	2,885	$	851	239%

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	For the three months ended March 31,					Increase/
Average unit costs per Mcfe:	2024			2023		(Decrease)
Lease operating expenses (1)	$	1.12		$	1.05	7%
General & administrative expenses	$	0.13	(2)	$	0.10	30%
Taxes, other than income taxes	$	0.13		$	0.16	(19)%
Full cost pool amortization	$	0.68		$	0.75	(9)%

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

(2)Excludes $9 million of merger-related expenses for the three months ended March 31, 2024.

Lease Operating Expenses

•Lease operating expenses decreased $8 million for the three months ended March 31, 2024 compared to the same period in 2023, primarily attributable to lower production volumes more than offsetting the impact of inflation and incremental costs from additional infrastructure becoming operational. For the three months ended March 31, 2024, these factors combined to increase lease operating expenses $0.07 per Mcfe compared to the same period in 2023.

General and Administrative Expenses

•General and administrative expenses increased $8 million or $0.03 per Mcfe for the three months ended March 31, 2024 compared to the same period in 2023, primarily due to personnel related costs and costs associated with the development of our enterprise resource technology.

Merger-Related Expenses

•For the three months ended March 31, 2024, Chesapeake merger-related expenses were approximately $9 million and mostly comprised of professional fees associated with the Proposed Merger.

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 $0.03 for the three months ended March 31, 2024, compared to the same period in 2023, 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.

Full Cost Pool Amortization

•Our full cost pool amortization rate decreased $0.07 per Mcfe for the three months ended March 31, 2024, as compared to the same period in 2023, primarily due to the non-cash full cost ceiling test impairment taken during the fourth quarter of 2023.

•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 $2,037 million and $2,075 million at March 31, 2024 and December 31, 2023, respectively. The unevaluated costs excluded from amortization decreased as the impact of $110 million of unevaluated capital invested during the period was more than offset by the evaluation of previously unevaluated properties totaling $148 million.

Impairments

•We recognized $2,093 million in non-cash full cost ceiling test impairments for the three months ended March 31, 2024 primarily due to decreased commodity pricing over the prior 12 months.

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Marketing


	For the three months ended March 31,						Increase/ (Decrease)
(in millions except volumes and percentages)	2024			2023
Marketing revenues	$	1,377		$	2,041		(33)%

Marketing purchases	1,366			2,007			(32)%
Operating costs and expenses	7			6			17%


Operating income	$	4		$	28		(86)%

Volumes marketed (Bcfe)	558			551			1%

Percent natural gas production marketed from affiliated E&P operations	83		%	93		%
Affiliated E&P oil and NGL production marketed	91		%	90		%

Operating Income

•Operating income for our Marketing segment decreased $24 million for the three months ended March 31, 2024, compared to the same period in 2023, primarily due to a $23 million decrease in the marketing margin (discussed below).

•The margin generated from marketing activities was $11 million and $34 million for the three months ended March 31, 2024 and 2023, respectively. The marketing margin decreased for the three months ended March 31, 2024, compared to the same period in 2023, primarily due to market conditions limiting opportunities to capture incremental value from 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 $664 million for the three months ended March 31, 2024, as compared to the same period in 2023. The decrease was primarily due to a 33% decrease in the price received for volumes marketed and partially offset by a 7 Bcfe increase in the volumes marketed for the three months ended March 31, 2024, compared to the same period in 2023.

Operating Costs and Expenses

•Operating costs and expenses for the marketing segment increased $1 million for the three months ended March 31, 2024, as compared to the same period in 2023, as a result of higher personnel-related costs.

Consolidated

Interest Expense


	For the three months ended March 31,				Increase/(Decrease)
(in millions except percentages)	2024		2023
Gross interest expense:
Senior notes	$	51	$	56	(9)%
Credit arrangements	8		7		14%
Amortization of debt costs	3		3		—%
Total gross interest expense	62		66		(6)%
Less: capitalization	(27)		(30)		(10)%
Net interest expense	$	35	$	36	(3)%

•Interest expense decreased for the three months ended March 31, 2024, compared to the same period in 2023, primarily due to the full redemption of our 7.75% Senior Notes due 2027 during the first quarter of 2023.

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•Capitalized interest decreased for the three months ended March 31, 2024, as compared to the same periods in 2023 due to the evaluation of natural gas and oil properties over the past twelve months.

•Capitalized interest as a percentage of gross interest expense decreased slightly for the three months ended March 31, 2024, compared to the same period in 2023, primarily due to a larger percentage decrease in our unevaluated natural gas and oil properties balance as a result of continued evaluation as compared to the smaller percentage decrease in our gross interest expense over the same periods.

•We refer you to Note 9 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 March 31,

(in millions)	2024		2023
Gain (loss) on unsettled derivatives	$	(31)	$	1,528
Gain (loss) on settled derivatives	156		(123)
Non-performance risk adjustment	1		(4)
Gain (loss) on derivatives	$	126	$	1,401

We refer you to Note 6 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 three months ended March 31, 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.

See Note 9 to the consolidated financial statements of this Quarterly Report for more information on our long-term debt.

Income Taxes


	For the three months ended March 31,
(in millions except percentages)	2024			2023
Income tax (benefit) expense	$	(430)		$	12
Effective tax rate	22		%	1		%

Our effective tax rate was approximately 22% and 1% for the three months ended March 31, 2024 and March 31, 2023, respectively. The effective tax rate for the three months ended March 31, 2023 was primarily the result of the partial release of the valuation allowances against our U.S. deferred tax assets in the first quarter of 2023. 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, we maintained a full valuation allowance against our deferred tax assets based on our 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, we sustained a three-year cumulative level of profitability. Based on this factor and other positive evidence such as forecasted income, we concluded that $512 million of our federal and state deferred tax assets were more likely than not to be realized and released this portion of the valuation allowance throughout 2023. Accordingly, during the three months ended March 31, 2023, we recognized $451 million of deferred income tax expense related to recording its tax provision which was partially offset by $439 million of tax benefit attributable to the release of the valuation allowance. The remaining valuation allowance was released during subsequent quarters during 2023. We expect to keep a valuation allowance of $52 million related to NOLs in jurisdictions in which we no longer operate and against the portion of our federal and state deferred tax assets such as capital losses and interest carryovers, which may expire before being

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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 in September 2021, 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 March 31, 2024, 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. In addition to other provisions, the IRA imposes a 15% corporate alternative minimum tax (“CAMT”) 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. The CAMT did not have any impact on the Company’s consolidated financial statements during 2023 and we do not expect to be impacted by the alternative minimum tax during 2024. We 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 1 4 to the consolidated financial statements of this Quarterly Report for a discussion of new accounting standards that have been implemented.

New Accounting Standards Not Yet Implemented in this Report

Refer to Note 1 4 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 March 29, 2024, our borrowing base was reaffirmed at $3.5 billion and our Five-Year Tranche was reaffirmed at $2.0 billion. At March 31, 2024, we had approximately $1.76 billion of total available liquidity, which exceeds our currently modeled needs as we remain committed to our strategy of capital discipline.

We refer you to Note 9 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.

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.

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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 2023 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 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 refer you to “Risk Factors” in Item 1A of our 2023 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 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 March 31, 2024, 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. 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 9 to the consolidated financial statements included in this Quarterly Report for additional discussion of our 2022 credit facility.

As of March 31, 2024, 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 9 of the consolidated financial statements included in this Quarterly Report for additional discussion of the covenant requirements of our 2022 credit facility.

As of March 31, 2024, we had $270 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 9 to the consolidated financial statements included in this Quarterly Report for additional discussion of our 2022 credit facility.

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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 9 to the consolidated financial statements included in this Quarterly Report for additional discussion of our revolving credit facility.

Other key financing activities for the three months ended March 31, 2024 and March 31, 2023 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.

As of April 30, 2024, we had long-term debt issuer ratings of Ba1 by Moody’s (rating affirmed Ba1 and outlook upgraded to positive on January 11, 2024 in conjunction with the Proposed Merger announcement), BB+ by S&P (rating affirmed BB+ and outlook upgraded to positive on January 18, 2023) and BB+ by Fitch Ratings (rating and positive outlook affirmed on August 16, 2023). Both S&P and Fitch also placed us on Credit / Rating Watch Positive on January 11, 2024 following the Proposed Merger announcement. 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 three months ended March 31,
(in millions)	2024		2023
Net cash provided by operating activities	$	496	$	1,137
Net cash used in investing activities	(521)		(670)
Net cash provided by (used in) financing activities	33		(514)

Cash Flow from Operations


	For the three months ended March 31,
(in millions)	2024		2023
Net cash provided by operating activities	$	496	$	1,137
Add back (subtract) changes in working capital	(66)		(373)
Net cash provided by operating activities, net of changes in working capital	$	430	$	764

•Net cash provided by operating activities decreased 56%, or $641 million, for the three months ended March 31, 2024, compared to the same period in 2023, primarily due to a $479 million decrease resulting from lower commodity prices, a $126 million decrease related to decreased production, a $307 million decrease in working capital, and a $23 million decrease in our marketing margin which was partially offset by a $279 million improvement in our settled derivative positions, and a $8 million decrease in operating costs and expenses.

•Net cash provided by operating activities, net of changes in working capital, provided 80% of our cash requirements for capital investments for the three months ended March 31, 2024 and exceeded our cash requirements for capital investments for the three months ended March 31, 2023. 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 decreased $127 million for the three months ended March 31, 2024, compared to the same period in 2023, primarily attributable our moderation of activity related to the decrease in near-term natural gas prices.

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	For the three months ended March 31,
(in millions)	2024		2023
Additions to properties and equipment	$	521	$	670
Adjustments for capital investments
Changes in capital accruals	14		(6)
Other (1)	3		1
Total capital investing	$	538	$	665

(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 March 31,				Increase/(Decrease)
(in millions except percentages)	2024		2023
E&P capital investing	$	537	$	664	(19)%
Other capital investing (1)	1		1		—%
Total capital investing	$	538	$	665	(19)%

(1)Other capital investing relates to information technology purchases for the three months ended March 31, 2024 and March 31, 2023, respectively.


	For the three months ended March 31,
(in millions)	2024		2023
E&P Capital Investments by Type:
Development and exploration, including workovers	$	430	$	584
Acquisition of properties	45		24


Other	7		5
Capitalized interest and expenses	55		51
Total E&P capital investments	$	537	$	664

E&P Capital Investments by Area:
Appalachia	$	279	$	276
Haynesville	253		381
Other E&P	5		7
Total E&P capital investments	$	537	$	664


	For the three months ended March 31,
	2024	2023
Gross Operated Well Count Summary:
Drilled	29	31
Completed	27	36
Wells to sales	18	36

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

We refer you to Note 9 of the consolidated financial statements included in this Quarterly Report for additional discussion of our outstanding debt and credit facilities.

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Working Capital

We had negative working capital of $773 million at March 31, 2024, a $459 million decrease from December 31, 2023, primarily attributable to the reclassification of $389 million of our 4.95% Senior Notes due 2025 from long term to short term, a decrease in accounts receivable of $189 million, an $11 million decrease in the current mark-to-market value of our derivatives position related to the changes in commodity pricing, an increase in other current liabilities of $11 million and a decrease in other current assets of $9 million. The decrease was partially offset by a decrease in our accounts payable of $85 million, a decrease in interest payable of $51 million, an increase in cash and cash equivalents of $8 million and a decrease in taxes payable of $5 million as compared to December 31, 2023. 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 March 31, 2024, 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 Note 10 to the consolidated financial statements. Other than the firm transportation and gathering agreements discussed in Note 10, there have been no material changes to our contractual obligations from those disclosed in our 2023 Annual Report.

Supplemental Guarantor Financial Information

As discussed in Note 9, 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 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 2023 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

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purchasers and their dispersion across geographic areas. For the three months ended March 31, 2024, one purchaser accounted for 12% of our revenues. For the year ended December 31, 2023, one purchaser accounted for 14% 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 March 31, 2024, we had approximately $3,743 million of outstanding senior notes with a weighted average interest rate of 5.46%, and $270 million of borrowings under our 2022 credit facility. As of March 31, 2024, 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)	2024			2025			2026			2027			2028			Thereafter			Total
Fixed rate payments (1)	$	—		$	389		$	—		$	—		$	304		$	3,050		$	3,743
Weighted average interest rate	—		%	5.70		%	—		%	—		%	8.38		%	5.14		%	5.46		%

Variable rate payments (1)	$	—		$	—		$	—		$	270		$	—		$	—		$	270
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 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 6 and Note 8 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 March 31, 2024 at a reasonable assurance level.

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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 March 31, 2024 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

PART II - OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

Refer to “Litigation” and “Environmental Risk” in Note 1 0 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 2023 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 March 31, 2024, no director or officer of the Company adopted or terminated a “Rule 10b5-1 trading arrangement” or “non-Rule 10b5-1 trading arrangement,” as each term is defined in Item 408(a) of Regulation S-K promulgated by the SEC.

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ITEM 6. EXHIBITS


(2.1)			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).
(2.2)			Agreement and Plan of Merger dated January 10, 2024, by and among Southwestern Energy Company, Chesapeake Energy Corporation, Hulk Merger Sub, Inc. and Hulk LLC Sub, LLC (Incorporated by reference to Exhibit 2.1 to the Registrant’s Current Report on Form 8-K filed on January 11, 2024).
(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 Amended and Restated Bylaws of Southwestern Energy Company, as amended through November 1, 2023 (Incorporated by reference to the Exhibit 3.4 to the Registrant’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2023).






(10.1)*			Southwestern Energy Company 2022 Incentive Plan Form of Restricted Stock Unit Award Agreement, for awards granted on or after February 21, 202 4 .
(10.2)*			Southwestern Energy Company Restricted Cash Unit Award Agreement, for awards granted on or after February 21, 2024 .
(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:	May 2, 2024	/s/ CARL F. GIESLER, JR.
		Carl F. Giesler, Jr. Executive Vice President and Chief Financial Officer