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Table of Contents

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q

(Mark One)

☒ Quarterly Report pursuant to Section 13 or 15(d) of the Securities

Exchange Act of 1934

For the quarterly period ended ~~September~~March 3031, ~~2023~~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 ~~October~~April 3130, ~~2023~~2024
Common Stock, Par Value $0.01						1,~~101~~102,~~463~~844,~~052~~906

Table of Contents

SOUTHWESTERN ENERGY COMPANY

INDEX TO FORM 10-Q

FOR THE QUARTERLY PERIOD ENDED ~~SEPTEMBER~~MARCH 3031, ~~2023~~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		109
		Note 1. Basis of Presentation	109
		Note 2. Acquisitions	10
		Note 2. Revenue Recognition	10
		Note 3. Revenue Recognition	11
		Note 3. Cash and Cash Equivalents	11
		Note 4. Cash and Cash Equivalents	13
		Note 4. Natural Gas and Oil Properties	12
		Note 5. Natural Gas and Oil Properties	13
		Note 5. Earnings per Share	12
		Note 6. Earnings per Share	14
		Note 6. Derivatives and Risk Management	14
		Note 7. Derivatives and Risk Management	15
		Note 7. Reclassifications From Accumulated Other Comprehensive Income (Loss)	19
		Note 8. Reclassifications From Accumulated Other Comprehensive Income (Loss)	21
		Note 8. Fair Value Measurements	20
		Note 9. Fair Value Measurements	21
		Note 9. Debt	22
		Note 10. Debt	23
		Note 10. Commitments and Contingencies	25
		Note 11. Commitments and Contingencies	26
		Note 11. Income Taxes	26
		Note 12. Income Taxes	27
		Note 12. Long-Term Incentive Compensation	27
		Note 13. Pension Plan and Other Postretirement Benefits	28
		Note 13. Segment Information	31
		Note 14. Long-Term Incentive Compensation	29
		Note 14. New Accounting Pronouncements	32
		Note 15. Segment Information	33
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		33
		Note 16. New Accounting Pronouncements	35
	Results of Operations		35
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		35
	Liquidity and Capital Resources		42
	Results of Operations		37
Item 3.	Quantitative and Qualitative Disclosures About Market Risk		46
	Liquidity and Capital Resources		46
Item 4.	Controls and Procedures		47
Item 3.	Quantitative and Qualitative Disclosures About Market Risk		52
Item 4.	Controls and Procedures		53
PART II – OTHER INFORMATION
Item 1.	Legal Proceedings		5348
Item 1A.	Risk Factors		5348
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds		5348
Item 3.	Defaults Upon Senior Securities		5348
Item 4.	Mine Safety Disclosures		5348
Item 5.	Other Information		5348
Item 6.	Exhibits		5549

Table of Contents

CAUTIONARY STATEMENT ABOUT FORWARD-LOOKING STATEMENTS

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

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

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

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

•our ability to fund our planned capital investments;

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

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

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

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

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

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

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

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

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

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

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

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

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

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

•the effects of weather or power outages;

•increased competition;

•inflation rates;

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

•the comparative cost of alternative fuels;

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•the comparative cost of alternative fuels;

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

•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; ~~and~~

•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 September 30,				For the nine months ended September 30,
	For the three months ended March 31,
(in millions, except share/per share amounts)	~~2023~~2024		~~2022~~2023		~~2023~~		~~2022~~
Operating Revenues:
Gas sales	$	~~627~~584	$	21,~~884~~145	$	~~2,323~~	$	~~7,061~~
Oil sales	9482		~~100~~95		~~281~~		~~349~~
NGL sales	~~169~~174		~~260~~201		~~523~~		~~842~~
Marketing	~~553~~579		~~1,298~~679		~~1,707~~		~~3,371~~
Other	—(2)		(12)		~~(4)~~		~~(1)~~
	1,443		4,541		4,830		11,622
	1,417		2,118
Operating Costs and Expenses:
Marketing purchases	~~545~~588		~~1,289~~667		~~1,693~~		~~3,366~~
Operating expenses	~~444~~417		~~423~~418		~~1,280~~		~~1,206~~
General and administrative expenses	4656		4146		~~133~~		~~120~~
Merger-related expenses	—9		—		—		27
Depreciation, depletion and amortization	~~338~~262		~~298~~313		~~979~~		~~861~~
Taxes, other than income taxes	63		76		189		198
Impairments	2,093		—
	1,436		2,127		4,274		5,778
Taxes, other than income taxes	49		68
Operating Income	7		2,414		556		5,844
	3,474		1,512
Operating Income (Loss)	(2,057)		606
Interest Expense:
Interest on debt	6159		7763		~~184~~		~~218~~
Other interest charges	3		3		9		10
Interest capitalized	(2827)		(30)		~~(87)~~		~~(89)~~
	36		50		106		139
	35		36
Gain (Loss) on Derivatives	93		(1,903)		1,811		(6,709)
Gain on Derivatives	126		1,401
Loss on Early Extinguishment of Debt	—		—(19)		~~(19)~~		~~(6)~~
Other Income (Loss), Net	21		—(1)		1		~~(1)~~
Income (Loss) Before Income Taxes	66(1,965)		~~461~~1,951		~~2,243~~		~~(1,011)~~
Provision for Income Taxes:
Provision (Benefit) for Income Taxes:
Current	—		11—		—		41
Deferred	21(430)		—12		28		—
	21		11		28		41
	(430)		12
Net Income (Loss)	$	45(1,535)	$	~~450~~1,939	$	~~2,215~~	$	~~(1,052)~~
Earnings (Loss) Per Common Share:
Basic	$	0(1.0439)	$	01.4176	$	~~2.01~~	$	~~(0.94)~~
Diluted	$	0(1.0439)	$	01.4076	$	~~2.01~~	$	~~(0.94)~~
Weighted Average Common Shares Outstanding:
Basic	1,101,~~231~~824,~~113~~856		1,~~110~~100,~~259~~278,~~907~~261		~~1,100,895,642~~		~~1,113,705,502~~
Diluted	1,~~104~~101,~~027~~824,~~634~~856		1,~~112~~102,~~522~~396,~~861~~636		~~1,102,867,675~~		~~1,113,705,502~~

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

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SOUTHWESTERN ENERGY COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(Unaudited)

	For the three months ended September 30,				For the nine months ended September 30,
	For the three months ended March 31,
(in millions)	~~2023~~2024		~~2022~~2023		~~2023~~		~~2022~~
Net income (loss)	$	45(1,535)	$	~~450~~1,939	$	~~2,215~~	$	~~(1,052)~~
Change in value of pension and other postretirement liabilities:
Amortization of prior service cost and net gain, including gain on settlements and curtailments included in net periodic pension cost (1)	—		—		1		—
Amortization of prior service cost and net gain, including gain on settlements and curtailments included in net periodic pension cost	—		1
Net actuarial loss incurred in period	—		—		(2)		—
Net actuarial gain (loss) incurred in period	2		(2)
Net tax loss attributable to pension termination	—		—(14)		~~(14)~~		—
Total change in value of pension and postretirement liabilities	—2		—(15)		~~(15)~~		—
Comprehensive income (loss)	$	45(1,533)	$	~~450~~1,924	$	~~2,200~~	$	~~(1,052)~~

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

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

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SOUTHWESTERN ENERGY COMPANY AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(Unaudited)

	September 30, 2023		December 31, 2022
	March 31, 2024		December 31, 2023
ASSETS	(in millions)
Current assets:
Cash and cash equivalents	$	2629	$	5021
Accounts receivable, net	~~602~~491		~~1,401~~680
Derivative assets	~~336~~640		~~145~~614
Other current assets	7891		68100
Total current assets	1,~~042~~251		1,~~664~~415
Natural gas and oil properties, using the full cost method, including $2,140 million as of September 30, 2023 and $2,217 million as of December 31, 2022 excluded from amortization	37,349		35,763
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	~~555~~573		~~527~~566
Less: Accumulated depreciation, depletion and amortization	(2630,~~381~~784)		(2528,~~387~~425)
Total property and equipment, net	118,~~523~~097		109,~~903~~913
Operating lease assets	~~163~~144		~~177~~154
Long-term derivative assets	~~153~~131		72175
Deferred tax assets	—674		—238
Other long-term assets	92101		~~110~~96
Total long-term assets	~~408~~1,050		~~359~~663
TOTAL ASSETS	$	1210,~~973~~398	$	1211,~~926~~991
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable	$	1,317	$	1,835
Current portion of long-term debt	$	389	$	—
Taxes payable	135		136
Accounts payable	1,299		1,384
Interest payable	26		86
Taxes payable	123		128
Derivative liabilities	219		1,317
Interest payable	26		77
Current operating lease liabilities	44		42
Derivative liabilities	116		79
Other current liabilities	17		65
Current operating lease liabilities	43		44
Total current liabilities	1,758		3,481
Other current liabilities	28		17
Long-term debt	4,114		4,392
Total current liabilities	2,024		1,729
Long-term operating lease liabilities	116		133
Long-term debt	3,609		3,947
Long-term derivative liabilities	186		378
Long-term operating lease liabilities	100		107
Other long-term liabilities	262		218
Long-term derivative liabilities	75		100
Total long-term liabilities	4,678		5,121
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 1,163,077,745 shares as of September 30, 2023 and 1,161,545,588 shares as of December 31, 2022	12		12
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,~~185~~199		7,~~172~~188
Accumulated deficit	(~~324~~2,517)		(~~2,539~~982)
Accumulated other comprehensive income (loss)	(9)		6
Accumulated other comprehensive loss	(1)		(3)
Common stock in treasury, 61,614,693 shares as of September 30, 2023 and December 31, 2022	(327)		(327)
Common stock in treasury, 61,614,693 shares as of March 31, 2024 and December 31, 2023	(327)		(327)
Total equity	64,~~537~~366		45,~~324~~888
TOTAL LIABILITIES AND EQUITY	$	1210,~~973~~398	$	1211,~~926~~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 nine months ended September 30,
	For the three months ended March 31,
(in millions)	~~2023~~2024		~~2022~~2023
Cash Flows From Operating Activities:
Net income (loss)	$	2(1,~~215~~535)	$	(1,~~052)~~939
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization	~~979~~262		~~861~~313
Amortization of debt issuance costs	52		82
Deferred income taxes	28		—
Impairments	2,093		—
(Gain) loss on derivatives, unsettled	(1,562)		2,524
Deferred income taxes	(430)		12
Stock-based compensation	7		4
(Gain) loss on derivatives, unsettled	30		(1,524)
Loss on early extinguishment of debt	19		6
Stock-based compensation	7		1
Other	3		2
Loss on early extinguishment of debt	—		19
Other	1		2
Change in assets and liabilities:
Accounts receivable	~~799~~190		~~(602)~~734
Accounts payable	(~~362~~94)		~~506~~(257)
Taxes payable	(25)		28(27)
Interest payable	(3329)		(2233)
Inventories	(151)		(814)
Other assets and liabilities	~~(42)~~5		(5930)
Net cash provided by operating activities	~~2,039~~496		21,~~196~~137
Cash Flows From Investing Activities:
Capital investments	(~~1,833~~521)		(~~1,623~~670)
Proceeds from sale of property and equipment	123		15
Net cash used in investing activities	(521)		(670)
Net cash used in investing activities	(1,710)		(1,608)
Cash Flows From Financing Activities:
Payments on current portion of long-term debt	—		(205)
Payments on long-term debt	—		(437)
Payments on long-term debt	(437)		(71)
Payments on revolving credit facility	(981)		(1,357)
Payments on revolving credit facility	(3,044)		(10,341)
Borrowings under revolving credit facility	1,031		1,317
Borrowings under revolving credit facility	3,182		10,061
Change in bank drafts outstanding	(12)		(33)
Change in bank drafts outstanding	(50)		62
Cash paid for tax withholding	(5)		(4)
Proceeds from exercise of common stock options	—		7
Net cash provided by (used in) financing activities	33		(514)
Purchase of treasury stock	—		(100)
Increase (decrease) in cash and cash equivalents	8		(47)
Debt issuance/amendment costs	—		(14)
Cash and cash equivalents at beginning of year	21		50
Cash paid for tax withholding	(4)		(4)
Cash and cash equivalents at end of period	$	29	$	3
Net cash used in financing activities	(353)		(605)
Decrease in cash and cash equivalents	(24)		(17)
Cash and cash equivalents at beginning of year	50		28
Cash and cash equivalents at end of period	$	26	$	11

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

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SOUTHWESTERN ENERGY COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY

(Unaudited)

	Common Stock			AdditionalPaid-InCapital		AccumulatedDeficit		Accumulated OtherComprehensiveIncome (Loss)		Common Stock in Treasury			Total
	SharesIssued	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
Balance at December 31, 2023	1,163,077,745	$	12	$	7,188	$	(982)	$	(3)	61,614,693	$	(327)	$	5,888
Comprehensive income:
Comprehensive loss:
Net income	—	—		—		1,939		—		—	—		1,939
Net loss	—	—		—		(1,535)		—		—	—		(1,535)
Other comprehensive loss	—	—		—		—		(15)		—	—		(15)
Other comprehensive income	—	—		—		—		2		—	—		2
Total comprehensive income	—	—		—		—		—		—	—		1,924
Total comprehensive loss	—	—		—		—		—		—	—		(1,533)
Stock-based compensation	—	—		210		—		—		—	—		210
Restricted units vested	12,~~999~~108,~~039~~403	—		86		—		—		—	—		86
Tax withholding – stock compensation	(~~662~~726,~~163~~549)	—		(45)		—		—		—	—		(45)
Balance at March 31, 2023	1,162,882,464	$	12	$	7,178	$	(600)	$	(9)	61,614,693	$	(327)	$	6,254
Balance at March 31, 2024	1,164,459,599	$	12	$	7,199	$	(2,517)	$	(1)	61,614,693	$	(327)	$	4,366
Comprehensive income:
Net income	—	—		—		231		—		—	—		231
Other comprehensive income	—	—		—		—		—		—	—		—
Total comprehensive income	—	—		—		—		—		—	—		231
Stock-based compensation	—	—		4		—		—		—	—		4
Issuance of restricted stock	188,382	—		—		—		—		—	—		—
Restricted units vested	9,968	—		—		—		—		—	—		—
Tax withholding – stock compensation	(3,069)	—		—		—		—		—	—		—
Balance at June 30, 2023	1,163,077,745	$	12	$	7,182	$	(369)	$	(9)	61,614,693	$	(327)	$	6,489
Comprehensive income:
Net income	—	—		—		45		—		—	—		45
Other comprehensive income	—	—		—		—		—		—	—		—
Total comprehensive income	—	—		—		—		—		—	—		45
Stock-based compensation	—	—		3		—		—		—	—		3
Balance at September 30, 2023	1,163,077,745	$	12	$	7,185	$	(324)	$	(9)	61,614,693	$	(327)	$	6,537


	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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	Common Stock			AdditionalPaid-InCapital		AccumulatedDeficit		Accumulated OtherComprehensiveIncome (Loss)		Common Stock in Treasury			Total
	SharesIssued	Amount								Shares	Amount
	(in millions, except share amounts)
Balance at December 31, 2021	1,158,672,666	$	12	$	7,150	$	(4,388)	$	(25)	44,353,224	$	(202)	$	2,547
Comprehensive loss:
Net loss	—	—		—		(2,675)		—		—	—		(2,675)
Other comprehensive income	—	—		—		—		—		—	—		—
Total comprehensive loss	—	—		—		—		—		—	—		(2,675)
Stock-based compensation	—	—		1		—		—		—	—		1
Performance units vested	2,499,860	—		12		—		—		—	—		12
Tax withholding – stock compensation	(721,070)	—		(4)		—		—		—	—		(4)
Balance at March 31, 2022	1,160,451,456	$	12	$	7,159	$	(7,063)	$	(25)	44,353,224	$	(202)	$	(119)
Comprehensive income:
Net income	—	—		—		1,173		—		—	—		1,173
Other comprehensive income	—	—		—		—		—		—	—		—
Total comprehensive income	—	—		—		—		—		—	—		1,173
Stock-based compensation	—	—		2		—		—		—	—		2
Exercise of stock options	893,312	—		7		—		—		—	—		7
Issuance of restricted stock	115,608	—		—		—		—		—	—		—
Restricted stock units vested	21,981	—		—		—		—		—	—		—
Treasury stock	—	—		—		—		—		2,815,541	(20)		(20)
Issuance of common stock	79	—		—		—		—		—	—		—
Tax withholding – stock compensation	(7,014)	—		—		—		—		—	—		—
Balance at June 30, 2022	1,161,475,422	$	12	$	7,168	$	(5,890)	$	(25)	47,168,765	$	(222)	$	1,043
Comprehensive income:
Net income	—	—		—		450		—		—	—		450
Other comprehensive income	—	—		—		—		—		—	—		—
Total comprehensive income	—	—		—		—		—		—	—		450
Stock-based compensation	—	—		1		—		—		—	—		1
Treasury stock	—	—		—		—		—		10,798,154	(80)		(80)
Balance at September 30, 2022	1,161,475,422	$	12	$	7,169	$	(5,440)	$	(25)	57,966,919	$	(302)	$	1,414

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

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SOUTHWESTERN ENERGY COMPANY AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

(1) BASIS OF PRESENTATION

Nature of Operations

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

E&P. Southwestern’s primary business is the development and production of natural gas as well as associated NGLs and oil, with ongoing operations focused on 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, ~~that~~principally ~~serve~~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, ~~2022~~2023 (“~~2022~~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 ~~2022~~2023 Annual Report.

~~(2)~~Proposed ~~ACQUISITIONS~~merger of the Company with Chesapeake Energy Corporation

~~GEP~~On ~~Haynesville~~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.

OnThe ~~November 3,~~consummation ~~2021, Southwestern entered into an Agreement and Plan~~ of ~~Merger with Mustang Acquisition Company, LLC (“Mustang”), GEP Haynesville, LLC (“GEPH”) and GEPH Unitholder Rep, LLC (~~the ~~“GEPH~~Proposed Merger ~~Agreement”). Pursuant~~is subject to the ~~terms~~satisfaction ofor ~~the~~waiver ~~GEPH~~of ~~Merger~~customary ~~Agreement,~~closing ~~GEPH merged with and into Mustang~~conditions, aincluding: ~~subsidiary~~receipt of ~~Southwestern,~~the ~~and~~required ~~became~~approvals afrom ~~wholly-owned~~the ~~subsidiary~~stockholders of ~~Southwestern (~~the ~~“GEPH~~Company ~~Merger”).~~and ~~The GEPH Merger closed on December 31~~Chesapeake, ~~2021~~ and ~~expanded~~ the ~~Company’s~~expiration ~~operations~~or ~~in the Haynesville.~~

~~Indigo Natural Resources Merger~~9

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

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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-~~Related~~closing ~~Expenses~~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.

~~The~~For ~~Company did not incur merger-related expenses during~~ the three ~~and nine~~ months ended ~~September~~March 3031, ~~2023~~2024, ~~or during~~ the ~~three~~Company ~~months~~incurred ~~ended~~approximately ~~September 30,~~$9 ~~2022.~~million ~~The~~in ~~following table summarizes the~~ merger-related expenses, ~~incurred~~mostly ~~during~~comprised ~~the~~of ~~nine~~professional ~~months~~fees, ~~ended~~associated ~~September 30,~~with ~~2022:~~the Proposed Merger.

	For the nine months ended September 30, 2022
(in millions)		Indigo Merger		GEPH Merger		Total
Transition services		$	—	$	18	$	18
Professional fees (bank, legal, consulting)		—		1		1
Contract buyouts, terminations and transfers		1		2		3
Due diligence and environmental		1		1		2
Employee-related		—		1		1
Other		—		2		2
Total merger-related expenses		$	2	$	25	$	27

(2) REVENUE RECOGNITION

(3) REVENUE RECOGNITION

Revenues from Contracts with Customers

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

1110

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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		IntersegmentRevenues		Total
Three months ended September 30, 2023
Three months ended March 31, 2024
Gas sales	$	~~610~~571	$	—	$	1713	$	~~627~~584
Oil sales	9381		—		1		9482
NGL sales	~~170~~174		—		~~(1)~~—		~~169~~174
Marketing	—		1,~~379~~377		(~~826~~798)		~~553~~579
Total	$	873	$	1,379	$	(809)	$	1,443
Other (1)	(2)		—		—		(2)
Total	$	824	$	1,377	$	(784)	$	1,417
(in millions)
Three months ended September 30, 2022
Three months ended March 31, 2023
Gas sales	$	21,~~889~~136	$	—	$	~~(5)~~9	$	21,~~884~~145
Oil sales	9994		—		1		~~100~~95
NGL sales	~~260~~201		—		—		~~260~~201
Marketing	—		42,~~436~~041		(31,~~138~~362)		~~1,298~~679
Other (1)	(12)		—		—		(12)
Total	$	31,~~247~~429	$	42,~~436~~041	$	(31,~~142~~352)	$	42,~~541~~118

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

(1)For the 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.

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

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

For the three months ended September 30,

For the nine months ended September 30,

For the three months ended March 31,

(in millions)

~~2023~~2024

~~2022~~2023

~~2023~~

~~2022~~

Appalachia

~~500~~554

~~1,874~~923

~~1,891~~

~~4,971~~

Haynesville

~~373~~270

~~1,373~~506

~~1,188~~

~~3,279~~

Total

~~873~~824

31,~~247~~429

~~3,079~~

~~8,250~~

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Receivables from Contracts with Customers

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

(in millions)	~~September~~March 3031, ~~2023~~2024		December 31, ~~2022~~2023
Receivables from contracts with customers	$	~~512~~433	$	~~1,313~~622
Other accounts receivable	9058		8858
Total accounts receivable	$	~~602~~491	$	~~1,401~~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 ~~nine~~three months ended ~~September~~March 3031, ~~2023~~2024 and year ended December 31, ~~2022~~2023. The Company has no contract assets or contract liabilities associated with its revenues from contracts with customers.

(43) CASH AND CASH EQUIVALENTS

The following table presents a summary of cash and cash equivalents as of ~~September~~March 3031, ~~2023~~2024 and December 31, ~~2022~~2023:

(in millions)	~~September~~March 3031, ~~2023~~2024		December 31, ~~2022~~2023
Cash	$	223	$	491
Marketable securities (1)	246		120
Total	$	2629	$	5021

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

~~(5) NATURAL GAS AND OIL PROPERTIES~~11

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

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

(4) NATURAL GAS AND OIL PROPERTIES

~~Using~~The Company utilizes the ~~average~~full ~~quoted~~cost ~~prices~~method ~~above,~~of ~~adjusted~~accounting for ~~market~~costs ~~differentials,~~related to the ~~Company’s~~development, ~~net~~exploration ~~book~~and ~~value~~acquisition of ~~its United States~~ natural gas and oil properties. Under ~~did~~this ~~not~~method, ~~exceed~~all ~~the~~such ~~ceiling~~costs ~~amount~~(productive atand ~~September 30~~nonproductive), ~~2023.~~including ~~Decreases~~salaries, inbenefits ~~market~~and ~~prices~~other asinternal ~~well~~costs asdirectly ~~changes~~attributable into ~~production~~these ~~rates~~activities, ~~levels~~are capitalized on a country-by-country basis and amortized over the estimated lives of ~~reserves,~~the ~~evaluation~~properties using the units-of-production method. These capitalized costs ~~excluded~~are ~~from~~subject ~~amortization~~to a ceiling test that limits such pooled costs, net of applicable deferred taxes, to the aggregate of the present value of future ~~development~~net ~~costs~~revenues attributable to proved natural gas, oil and ~~production~~NGL ~~costs~~reserves ~~could~~discounted ~~result~~at 10% (standardized measure). Any costs in ~~future~~excess of the ceiling are written off as a non-cash ~~ceiling~~expense. The ~~test~~expense ~~impairments~~may tonot ~~the~~be ~~Company’s~~reversed in future periods, even though higher natural gas, oil and ~~oil~~NGL ~~properties~~prices may subsequently increase the ceiling. Companies ~~Given~~using the ~~fall~~full incost ~~commodity~~method ~~prices~~are ~~during~~required ~~2023~~to use the average quoted price from the first day of each month from the previous 12 months, including the ~~Company~~impact ~~expects~~of ~~some~~derivatives ~~non-cash~~designated ~~impairment~~for hedge accounting, to calculate the ceiling value of ~~its~~their ~~assets~~reserves. ~~will~~The ~~likely~~Company ~~occur~~had asno ~~early~~hedge positions that were designated for hedge accounting as of March 31, 2024. Prices used to calculate the ~~fourth~~ceiling ~~quarter~~value of ~~2023.~~reserves were as follows:

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


	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) ~~EARNINGS~~DERIVATIVES ~~PER~~AND ~~SHARE~~RISK MANAGEMENT

~~Basic~~The ~~earnings~~Company ~~per common share~~ is ~~computed~~exposed byto ~~dividing~~volatility ~~net~~in ~~income~~market ~~(loss)~~prices byand ~~the~~basis ~~weighted~~differentials ~~average~~for ~~number~~natural ofgas, ~~common~~oil ~~shares~~and ~~outstanding~~NGLs ~~during~~which impacts the ~~reportable~~predictability ~~period. The~~of ~~diluted~~its ~~earnings~~cash ~~per~~flows ~~share~~related ~~calculation adds~~ to the ~~weighted~~sale ~~average number~~ of ~~common~~those ~~shares~~commodities. These ~~outstanding:~~risks ~~the~~are ~~incremental~~managed ~~shares~~by ~~that~~the ~~would~~Company’s ~~have~~use ~~been~~of ~~outstanding~~certain ~~assuming~~derivative ~~the~~financial ~~exercise~~instruments. As of ~~dilutive stock options~~March 31, ~~the~~2024 ~~vesting~~and ofMarch 31, ~~unvested restricted shares of common stock~~2023, ~~restricted~~the ~~stock~~Company’s ~~units~~derivative ~~and~~financial ~~performance~~instruments ~~units. An~~consisted ~~antidilutive~~of ~~impact~~fixed isprice answaps, ~~increase~~two-way incostless ~~earnings~~collars, ~~per~~three-way ~~share~~costless orcollars, abasis ~~reduction~~swaps, inand ~~net~~options ~~loss~~(calls ~~per~~and ~~share~~puts). A ~~resulting~~description ~~from~~of the ~~conversion,~~Company’s ~~exercise~~derivative orfinancial ~~contingent~~instruments ~~issuance~~is ofprovided ~~certain securities.~~below:

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


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 ~~following~~Company ~~table~~chooses ~~presents~~counterparties for its derivative instruments that it believes are creditworthy at the ~~computation~~time ofthe ~~earnings~~transactions ~~per~~are ~~share~~entered ~~for~~into, and the ~~three~~Company actively monitors the credit ratings and ~~nine~~credit ~~months~~default ~~ended~~swap ~~September~~rates of these counterparties where applicable. 30However, ~~2023~~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 ~~2022:~~does not net the asset and liability positions.

	For the three months ended September 30,				For the nine months ended September 30,
(in millions, except share/per share amounts)	2023		2022		2023		2022
Net income (loss)	$	45	$	450	$	2,215	$	(1,052)
Number of common shares:
Weighted average outstanding	1,101,231,113		1,110,259,907		1,100,895,642		1,113,705,502
Issued upon assumed exercise of outstanding stock options	—		—		—		—
Effect of issuance of non-vested restricted common stock	932,868		796,253		839,031		—
Effect of issuance of non-vested restricted units	1,689,617		1,466,701		1,133,002		—
Effect of issuance of non-vested performance units	174,036		—		—		—
Weighted average and dilutive outstanding	1,104,027,634		1,112,522,861		1,102,867,675		1,113,705,502
Earnings (loss) per common share
Basic	$	0.04	$	0.41	$	2.01	$	(0.94)
Diluted	$	0.04	$	0.40	$	2.01	$	(0.94)

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

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

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~~(7)~~The ~~DERIVATIVES~~following ~~AND~~tables ~~RISK~~provide ~~MANAGEMENT~~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:

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


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)

Fixed price swaps			If the Company sells a fixed price swap, the Company receives a fixed price for the contract, and pays a floating market price to the counterparty. If the Company purchases a fixed price swap, the Company receives a floating market price for the contract and pays a fixed price to the counterparty.
Two-way costless collars			Arrangements that contain a fixed floor price (“purchased put option”) and a fixed ceiling price (“sold call option”) based on an index price which, in aggregate, have no net cost. At the contract settlement date, (1) if the index price is higher than the ceiling price, the Company pays the counterparty the difference between the index price and ceiling price, (2) if the index price is between the floor and ceiling prices, no payments are due from either party, and (3) if the index price is below the floor price, the Company will receive the difference between the floor price and the index price.
Three-way costless collars			Arrangements that contain a purchased put option, a sold call option and a sold put option based on an index price that, in aggregate, have no net cost. At the contract settlement date, (1) if the index price is higher than the sold call strike price, the Company pays the counterparty the difference between the index price and sold call strike price, (2) if the index price is between the purchased put strike price and the sold call strike price, no payments are due from either party, (3) if the index price is between the sold put strike price and the purchased put strike price, the Company will receive the difference between the purchased put strike price and the index price, and (4) if the index price is below the sold put strike price, the Company will receive the difference between the purchased put strike price and the sold put strike price.
Basis swaps			Arrangements that guarantee a price differential for natural gas from a specified delivery point. If the Company sells a basis swap, the Company receives a payment from the counterparty if the price differential is greater than the stated terms of the contract and pays the counterparty if the price differential is less than the stated terms of the contract. If the Company purchases a basis swap, the Company pays the counterparty if the price differential is greater than the stated terms of the contract and receives a payment from the counterparty if the price differential is less than the stated terms of the contract.
Options (Calls and Puts)			The Company purchases and sells options in exchange for premiums. If the Company purchases a call option, the Company receives from the counterparty the excess (if any) of the market price over the strike price of the call option at the time of settlement, but if the market price is below the call’s strike price, no payment is due from either party. If the Company sells a call option, the Company pays the counterparty the excess (if any) of the market price over the strike price of the call option at the time of settlement, but if the market price is below the call’s strike price, no payment is due from either party. If the Company purchases a put option, the Company receives from the counterparty the excess (if any) of the strike price over the market price of the put option at the time of settlement, but if the market price is above the put’s strike price, no payment is due from either party. If the Company sells a put option, the Company pays the counterparty the excess (if any) of the strike price over the market price of the put option at the time of settlement, but if the market price is above the put’s strike price, no payment is due from either party.
Index swaps			Natural gas index swaps are used to manage the Company’s exposure to volatility in daily cash market pricing. When the Company sells an index swap, the Company pays an amount equal to the average of the daily index price for a given month at a specified location and receives a first of month index price based on the same location.

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


	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)

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


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)

~~The~~At ~~following~~March 31, ~~tables~~2024, ~~provide~~the ~~information~~net ~~about~~fair value of the Company’s financial instruments ~~that~~was ~~are~~a ~~sensitive~~$580 tomillion ~~changes~~asset, inwhich ~~commodity~~included ~~prices~~net ~~and~~reduction ~~that~~of ~~are used to protect~~ the ~~Company’s~~asset ~~exposure. None~~ of ~~the~~$1 ~~financial~~million ~~instruments~~related ~~below~~to ~~are~~non-performance ~~designated for hedge accounting treatment~~risk. ~~The~~ ~~tables~~See ~~present~~Note ~~the~~8 ~~notional~~for ~~amount,~~additional ~~the~~details ~~weighted~~regarding ~~average contract prices and~~ the Company’s fair value bymeasurements ~~expected maturity dates as~~ of ~~September 30,~~its ~~2023:~~derivatives position.

Financial Protection on Production
		Weighted Average Price per MMBtu
	Volume (Bcf)	Swaps		Sold Puts		Purchased Puts		Sold Calls		Basis Differential		Fair Value at September 30, 2023(in millions)
Natural Gas
2023
Fixed price swaps	179	$	3.28	$	—	$	—	$	—	$	—	$	49
Two-way costless collars	32	—		—		2.88		3.29		—		1
Three-way costless collars	47	—		2.08		2.50		2.91		—		(11)
Total	258											$	39
2024
Fixed price swaps	528	$	3.54	$	—	$	—	$	—	$	—	$	82
Two-way costless collars	44	—		—		3.07		3.53		—		(5)
Three-way costless collars	77	—		2.46		3.19		3.99		—		(5)
Total	649											$	72
2025
Two-way costless collars	73	$	—	$	—	$	3.50	$	5.40	$	—	$	11
Three-way costless collars	106	—		2.50		3.75		5.69		—		16
Total	179											$	27
Basis Swaps
2023	71	$	—	$	—	$	—	$	—	$	(0.57)	$	24
2024	46	—		—		—		—		(0.71)		9
2025	9	—		—		—		—		(0.64)		3
Total	126											$	36

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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	Volume(MBbls)	Weighted Average Strike Price per Bbl								Fair Value at September 30, 2023(in millions)
		Swaps		Sold Puts		Purchased Puts		Sold Calls
Oil
2023
Fixed price swaps	733	$	67.34	$	—	$	—	$	—	$	(15)
Two-way costless collars	147	—		—		70.00		80.58		(1)
Three-way costless collars	291	—		34.36		46.05		55.96		(10)
Total	1,171									$	(26)
2024
Fixed price swaps	1,571	$	71.06	$	—	$	—	$	—	$	(15)
Two-way costless collars	512	—		—		70.00		85.63		(2)
Total	2,083									$	(17)
2025
Fixed price swaps	41	$	77.66	$	—	$	—	$	—	$	—
Ethane
2023
Fixed price swaps	2,254	$	10.99	$	—	$	—	$	—	$	(1)
2024
Fixed price swaps	3,429	$	10.84	$	—	$	—	$	—	$	—
Propane
2023
Fixed price swaps	1,782	$	30.44	$	—	$	—	$	—	$	(1)
2024
Fixed price swaps	3,254	$	31.78	$	—	$	—	$	—	$	3
2025
Fixed price swaps	63	$	26.46	$	—	$	—	$	—	$	—
Normal Butane
2023
Fixed price swaps	198	$	40.96	$	—	$	—	$	—	$	1
2024
Fixed price swaps	329	$	40.74	$	—	$	—	$	—	$	1
Natural Gasoline
2023
Fixed price swaps	171	$	63.74	$	—	$	—	$	—	$	(1)
2024
Fixed price swaps	329	$	64.37	$	—	$	—	$	—	$	(1)

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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Other Derivative Contracts
Net Derivative Position
	Volume(Bcf)		Weighted Average Strike Price per MMBtu		Fair Value at September 30, 2023 (in millions)
	March 31, 2024		December 31, 2023
Call Options – Natural Gas (Net)
(in millions)
2023	15		$	2.97	$	(4)
Net current derivative asset (liability)	$	525	$	536
2024	82		6.56		(9)
Net long-term derivative asset (liability)	56		76
2025	73		7.00		(14)
Non-performance risk adjustment	(1)		(2)
2026	73		7.00		(20)
Net total derivative asset (liability)	$	580	$	610
Total	243				$	(47)

AtThe ~~September 30,~~following ~~2023,~~tables summarize the ~~net~~before-tax ~~fair~~effect ~~value~~ of the Company’s ~~financial~~derivative instruments ~~was~~on anthe ~~$84~~consolidated ~~million~~statements ~~asset, which included net reduction~~ of ~~the~~operations ~~asset of $1 million related to non-performance risk. See Note 9~~ for ~~additional details regarding~~ the ~~Company’s~~three ~~fair~~months ~~value~~ended ~~measurements~~March 31, of2024 ~~its~~and ~~derivatives position.~~2023:

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


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

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

Derivative Assets
		Fair Value
(in millions)	Balance Sheet Classification	September 30, 2023		December 31, 2022
Derivatives not designated as hedging instruments:
Fixed price swaps – natural gas	Derivative assets	$	224	$	—
Fixed price swaps – ethane	Derivative assets	2		4
Fixed price swaps – propane	Derivative assets	10		9
Fixed price swaps – normal butane	Derivative assets	2		1
Fixed price swaps – natural gasoline	Derivative assets	—		1
Two-way costless collars – natural gas	Derivative assets	32		47
Two-way costless collars – oil	Derivative assets	1		—
Three-way costless collars – natural gas	Derivative assets	28		18
Three-way costless collars – oil	Derivative assets	—		1
Basis swaps – natural gas	Derivative assets	33		64
Put options – natural gas	Derivative assets	5		—
Fixed price swaps – natural gas	Other long-term assets	25		28
Fixed price swaps – oil	Other long-term assets	—		1
Fixed price swaps – ethane	Other long-term assets	—		1
Fixed price swaps – propane	Other long-term assets	—		1
Two-way costless collars – natural gas	Other long-term assets	43		18
Two-way costless collars – oil	Other long-term assets	1		—
Three-way costless collars – natural gas	Other long-term assets	77		3
Basis swaps – natural gas	Other long-term assets	8		17
Put options – natural gas	Other long-term assets	—		4
Total derivative assets		$	491	$	218

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Derivative Liabilities
Settled Gain (Loss) on Derivatives Recognized in Earnings (1)
			Fair Value
		Consolidated Statement of Operations Classification of Gain (Loss) on Derivatives, Settled			For the three months ended March 31,
(in millions)	Balance Sheet Classification		September 30, 2023				December 31, 2022
Derivative Instrument					2024				2023
Derivatives not designated as hedging instruments:
					(in millions)
Fixed price swaps – natural gas	~~Derivative liabilities~~	Gain (Loss) on Derivatives	$	73	$	140	$	~~581~~	$	(45)
Fixed price swaps – oil	~~Derivative liabilities~~	Gain (Loss) on Derivatives	29		(4)		20		(4)
Fixed price swaps – ethane	~~Derivative liabilities~~	Gain (Loss) on Derivatives	3		3		1		1
Fixed price swaps – propane	~~Derivative liabilities~~	Gain (Loss) on Derivatives	7		(2)		—		1
Fixed price swaps – natural gasoline	Derivative liabilities		2				1
Fixed price swaps – normal butane		Gain (Loss) on Derivatives			(1)				—
Two-way costless collars – natural gas	Derivative liabilities		31				235
Fixed price swaps – natural gasoline		Gain (Loss) on Derivatives			(1)				—
Two-way costless collars – oil	Derivative liabilities		4				—
Two-way costless collars – natural gas		Gain (Loss) on Derivatives			9				—
Three-way costless collars – natural gas	~~Derivative liabilities~~	Gain (Loss) on Derivatives	39		16		~~311~~		(33)
Three-way costless collars – oil	~~Derivative liabilities~~	Gain (Loss) on Derivatives	10		—		31		(7)
Basis swaps – natural gas	~~Derivative liabilities~~	Gain (Loss) on Derivatives	5		(4)		69		(29)
Call options – natural gas	~~Derivative liabilities~~	Gain (Loss) on Derivatives	11		—		70		(7)
Put options – natural gas	Derivative liabilities		5				—
Sold put options - natural gas		Gain (Loss) on Derivatives			(10)				—
Fixed price swaps – natural gas	Long-term derivative liabilities		45				281
Purchased put options – natural gas		Gain (Loss) on Derivatives			10				—
Fixed price swaps – oil	Long-term derivative liabilities		1				4
Total gain (loss) on settled derivatives			$	156			$	(123)
Fixed price swaps – propane	Long-term derivative liabilities		1				—
Total gain (loss) on derivatives (2)			$	126			$	1,401
Two-way costless collars – natural gas	Long-term derivative liabilities		37				56
Two-way costless collars – oil	Long-term derivative liabilities		1				—
Three-way costless collars – natural gas	Long-term derivative liabilities		66				20
Basis swap – natural gas	Long-term derivative liabilities		—				1
Call options – natural gas	Long-term derivative liabilities		36				18
Total derivative liabilities			$	406			$	1,699

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

(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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~~The following tables summarize the before-tax effect of the Company’s derivative instruments on the consolidated statements of operations for the three and nine months ended September~~(8) ~~30,~~FAIR ~~2023~~VALUE ~~and 2022:~~MEASUREMENTS

Unsettled Gain (Loss) on Derivatives Recognized in Earnings
	Consolidated Statement of Operations Classification of Gain (Loss) on Derivatives, Unsettled	For the three months ended September 30,				For the nine months ended September 30,
Derivative Instrument		2023		2022		2023		2022
		(in millions)
Fixed price swaps – natural gas	Gain (Loss) on Derivatives	$	28	$	(140)	$	965	$	(1,654)
Fixed price swaps – oil	Gain (Loss) on Derivatives	(29)		73		(7)		39
Fixed price swaps – ethane	Gain (Loss) on Derivatives	(5)		24		(5)		(3)
Fixed price swaps – propane	Gain (Loss) on Derivatives	(37)		67		(8)		74
Fixed price swaps – normal butane	Gain (Loss) on Derivatives	(6)		24		1		24
Fixed price swaps – natural gasoline	Gain (Loss) on Derivatives	(9)		28		(2)		29
Two-way costless collars – natural gas	Gain (Loss) on Derivatives	3		(99)		233		(432)
Two-way costless collars – oil	Gain (Loss) on Derivatives	(4)		—		(3)		—
Two-way costless collars – ethane	Gain (Loss) on Derivatives	—		—		—		1
Three-way costless collars – natural gas	Gain (Loss) on Derivatives	20		(26)		310		(520)
Three-way costless collars – oil	Gain (Loss) on Derivatives	(1)		38		20		10
Three-way costless collars – propane	Gain (Loss) on Derivatives	—		3		—		4
Basis swaps – natural gas	Gain (Loss) on Derivatives	(43)		4		25		12
Call options – natural gas	Gain (Loss) on Derivatives	14		(8)		41		(114)
Put options – natural gas	Gain (Loss) on Derivatives	—		—		(4)		—
Fixed price swap – natural gas storage	Gain (Loss) on Derivatives	—		—		—		1
Interest rate swaps	Gain (Loss) on Derivatives	—		—		—		(2)
Total gain (loss) on unsettled derivatives		$	(69)	$	(12)	$	1,566	$	(2,531)
Settled Gain (Loss) on Derivatives Recognized in Earnings (1)
	Consolidated Statement of Operations Classification of Gain (Loss) on Derivatives, Settled	For the three months ended September 30,				For the nine months ended September 30,
Derivative Instrument		2023		2022		2023		2022
		(in millions)
Fixed price swaps – natural gas	Gain (Loss) on Derivatives	$	112	$	(1,082)	$	227	$	(2,249)
Fixed price swaps – oil	Gain (Loss) on Derivatives	(11)		(30)		(18)		(104)
Fixed price swaps – ethane	Gain (Loss) on Derivatives	(3)		(15)		3		(42)
Fixed price swaps – propane	Gain (Loss) on Derivatives	9		(21)		21		(96)
Fixed price swaps – normal butane	Gain (Loss) on Derivatives	1		(7)		2		(33)
Fixed price swaps – natural gasoline	Gain (Loss) on Derivatives	—		(9)		1		(45)
Two-way costless collars – natural gas	Gain (Loss) on Derivatives	13		(152)		44		(386)
Two-way costless collars – ethane	Gain (Loss) on Derivatives	—		—		—		(1)
Three-way costless collars – natural gas	Gain (Loss) on Derivatives	1		(491)		(15)		(1,008)
Three-way costless collars – oil	Gain (Loss) on Derivatives	(7)		(12)		(20)		(43)
Three-way costless collars – propane	Gain (Loss) on Derivatives	—		(1)		—		(4)
Basis swaps – natural gas	Gain (Loss) on Derivatives	47		40		11		64
Index swaps – natural gas	Gain (Loss) on Derivatives	—		—		—		(1)
Call options – natural gas	Gain (Loss) on Derivatives	—		(109)		(7)		(235)
Purchased fixed price swaps – natural gas	Gain (Loss) on Derivatives	—		—		—		1
Fixed price swaps – natural gas storage	Gain (Loss) on Derivatives	—		—		—		(3)
Total gain (loss) on settled derivatives		$	162	$	(1,889)	$	249	$	(4,185)
Total gain (loss) on derivatives (2)		$	93	$	(1,903)	$	1,811	$	(6,709)

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:

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


	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

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

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Total Gain (Loss) on Derivatives Recognized in Earnings
	For the three months ended September 30,				For the nine months ended September 30,
	2023		2022		2023		2022
	(in millions)
Total gain (loss) on unsettled derivatives	$	(69)	$	(12)	$	1,566	$	(2,531)
Total gain (loss) on settled derivatives	162		(1,889)		249		(4,185)
Non-performance risk adjustment	—		(2)		(4)		7
Total gain (loss) on derivatives	$	93	$	(1,903)	$	1,811	$	(6,709)

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

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

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

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

(9) FAIR VALUE MEASUREMENTS

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

	September 30, 2023				December 31, 2022
(in millions)	CarryingAmount		FairValue		CarryingAmount		FairValue
Cash and cash equivalents	$	26	$	26	$	50	$	50
2022 revolving credit facility due April 2027	388		388		250		250
Senior notes (1)	3,743		3,424		4,164		3,847
Derivative instruments, net	84		84		(1,478)		(1,478)

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

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

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

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

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

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

Debt: The fair values of the Company’s senior notes are based on the market value of the Company’s publicly traded debt as determined based on the market prices of the Company’s senior notes. The fair values of the Company’s senior notes are considered to be a Level 1 measurement as these are actively traded in the market. The carrying value of the borrowings under the Company’s 2022 credit facility (as defined in Note 109 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.

21The 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.

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

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

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

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

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

	September 30, 2023
	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	$	—	$	~~263~~512	$	—	$	~~263~~512
Two-way costless collars	—		7771		—		7771
Three-way costless collars	—		~~105~~180		—		~~105~~180
Basis swaps	—		419		—		419
Put options	—		5		—		5
Liabilities
Fixed price swaps	—		(~~161~~54)		—		(~~161~~54)
Two-way costless collars	—		(7315)		—		(7315)
Three-way costless collars	—		(~~115~~89)		—		(~~115~~89)
Basis swaps	—		(518)		—		(518)
Call options	—		(4715)		—		(4715)
Put options	—		(5)		—		(5)
Total (1)	$	—	$	581	$	—	$	581
Total (1)	$	—	$	85	$	—	$	85

(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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	December 31, 2022
	Fair Value Measurements Using:
(in millions)	Quoted Prices in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Assets (Liabilities) at Fair Value
Assets
Fixed price swaps	$	—	$	46	$	—	$	46
Two-way costless collars	—		65		—		65
Three-way costless collars	—		22		—		22
Basis swaps	—		81		—		81
Purchase Put - Natural Gas	—		4		—		4
Liabilities
Fixed price swaps	—		(888)		—		(888)
Two-way costless collars	—		(291)		—		(291)
Three-way costless collars	—		(362)		—		(362)
Basis swaps	—		(70)		—		(70)
Call options	—		(88)		—		(88)
Total (1)	$	—	$	(1,481)	$	—	$	(1,481)

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

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

(10) DEBT

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

	September 30, 2023
(in millions)	Debt Instrument		Unamortized Issuance Expense			Unamortized Debt Premium/Discount		Total
Variable rate (7.16% at September 30, 2023) 2022 revolving credit facility, due April 2027	$	388	$	—	(1)	$	—	$	388
4.95% Senior Notes due January 2025 (2)	389		(1)			—		388
8.375% Senior Notes due September 2028	304		(3)			—		301
5.375% Senior Notes due February 2029	700		(5)			19		714
5.375% Senior Notes due March 2030	1,200		(13)			—		1,187
4.75% Senior Notes due February 2032	1,150		(14)			—		1,136
Total debt	$	4,131	$	(36)		$	19	$	4,114
	December 31, 2022
(in millions)	Debt Instrument		Unamortized Issuance Expense			Unamortized Debt Premium/Discount		Total
Variable rate (6.15% at December 31, 2022) 2022 revolving credit facility, due April 2027	$	250	$	—	(1)	$	—	$	250
4.95% Senior Notes due January 2025 (2)	389		(1)			—		388
7.75% Senior Notes due October 2027	421		(3)			—		418
8.375% Senior Notes due September 2028	304		(3)			—		301
5.375% Senior Notes due February 2029	700		(5)			22		717
5.375% Senior Notes due March 2030	1,200		(16)			—		1,184
4.75% Senior Notes due February 2032	1,150		(16)			—		1,134
Total debt	$	4,414	$	(44)		$	22	$	4,392

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

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

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

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

Credit Facilities

2022 Credit Facility

On April 8, 2022, the Company entered into an Amended and Restated Credit Agreement that replaces its previous credit facility ~~with a group of banks~~, that as amended, has a maturity date of April 2027 (the “2022 credit facility”). As of ~~September~~March 3031, ~~2023~~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 ~~October~~March 429, ~~2023~~2024, the Company’s borrowing base was reaffirmed at $3.5 billion and the Five-Year Tranche was reaffirmed at $2.0 billion ~~and~~with ~~has~~ a maturity date of April 8, 2027.

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

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

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

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

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

•~~Restrictions~~restrictions on mergers and asset dispositions;

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

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

1.Minimum current ratio of ~~not~~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).

242.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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~~derivative~~immediately ~~assets)~~due toand ~~consolidated~~payable. ~~current~~As ~~liabilities~~of ~~(excluding~~March 31, ~~non-cash~~2024, ~~derivative~~the ~~obligations~~Company ~~and~~was ~~current~~in ~~maturities~~compliance with all of ~~long-term~~the ~~debt)~~covenants of the credit agreement in all material respects.

~~2.Maximum~~Currently, ~~total~~each ~~net~~United ~~leverage~~States ~~ratio~~domestic subsidiary of ~~not~~the ~~greater~~Company ~~than,~~for ~~with~~which ~~respect to~~ the ~~prior~~Company ~~four~~owns ~~fiscal~~100% ~~quarters~~of ~~ending~~its onequity orguarantees ~~after~~the ~~March 31,~~ 2022, ~~4.00~~credit ~~to 1~~facility.~~00. Total~~ ~~net~~Pursuant ~~leverage~~to ~~ratio~~requirements isunder ~~defined~~the asindentures ~~total~~governing ~~debt~~its ~~less~~senior ~~cash~~notes, oneach ~~hand~~subsidiary ~~(up~~that tobecame ~~the~~a ~~lesser~~guarantor of ~~10%~~the of2022 credit ~~limit~~facility oralso ~~$150~~became ~~million)~~a ~~divided~~guarantor byof ~~consolidated~~each ~~EBITDAX~~of ~~for~~ the ~~last four consecutive quarters. EBITDAX, as defined in the credit agreement governing the~~ Company’s ~~2022~~senior 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 costsnotes.

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

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

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

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

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

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

•The Guarantors may be released from their guarantees;

•The collateral under the facility will be released;

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

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

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

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

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

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

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

25As 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.

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

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

Senior Notes

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

During the nine months ended September 30, 2022, the Company redeemed the remaining outstanding principal balance of $201 million of its 4.10% Senior Notes due 2022, $46 million of its 8.375% Senior Notes due 2028 and $19 million of its 7.75% Senior Notes due 2027 for a total of $272 million, and recognized a $6 million loss on debt extinguishment.24

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

~~(11)~~rating ~~COMMITMENTS~~to ~~AND~~BB-, ~~CONTINGENCIES~~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 ~~September~~March 3031, ~~2023~~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 $9.72 billion, $1.2 billion of which related to access capacity on future pipeline and gathering infrastructure projects that still require the granting of regulatory approvals and additional construction efforts. As of ~~September~~March 3031, ~~2023~~2024, the Company also had guarantee obligations of up to $~~825~~959 million of that total amount. As of ~~September~~March 3031, ~~2023~~2024, future payments under non-cancelable firm transportation and gathering agreements ~~were~~are as follows:

Payments Due by Period

(in millions)

Total

Less than 1Year

1 to 3 Years

3 to 5 Years

5 to 8 Years

More than 8Years

Infrastructure currently in service

8,~~454~~016

~~955~~1,030

1,~~979~~950

1,~~768~~698

1,~~796~~634

1,~~956~~704

Pending regulatory approval and/or construction (1)

1,~~239~~192

4661

~~187~~170

~~217~~195

~~322~~294

~~467~~472

Total transportation charges

9,~~693~~208

1,~~001~~091

2,~~166~~120

1,~~985~~893

21,~~118~~928

2,~~423~~176

(1)Based on estimated in-service dates as of ~~September~~March 3031, ~~2023~~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.

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Litigation

The Company is subject to various litigation, claims and proceedings, most of which have arisen in the ordinary course of business, such as for alleged breaches of contract, miscalculation of royalties, employment matters, traffic accidents, pollution, contamination, encroachment on others’ property or nuisance. The Company accrues for litigation, claims and proceedings when a liability is both probable and the amount can be reasonably estimated. As of ~~September~~March 3031, ~~2023~~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

AsOn ~~discussed in Note 2, on~~ September 1, 2021, the Company completed ~~its~~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 ~~development~~exploration and production activity on certain acreage located in DeSoto Parish, Louisiana. The plaintiffs, who claim to own the properties at issue, assert that Indigo’s actions and the actions of other current operators conducting development and production activity, combined with the improper plugging and abandoning of legacy wells by former operators, have caused environmental contamination to their properties. Among other things, the plaintiffs contend that the defendants’ conduct resulted in the migration of natural gas, along with oilfield contaminants, into the Carrizo-Wilcox aquifer system underlying certain portions of DeSoto Parish. The plaintiffs assert claims based in tort, breach of contract and for violations of the Louisiana Civil and Mineral Codes, and they seek injunctive relief and monetary damages in an unspecified amount, including punitive damages.

On September 13, 2018, Indigo filed a variety of exceptions in response to the plaintiffs’ petition in this matter. Since the initial filing, supplemental petitions have been filed joining additional individuals and entities as plaintiffs in the matter. On September 29, 2020, plaintiffs filed their fourth supplemental and amending petition in response to the court’s order ruling that plaintiffs’ claims were improperly vague and failed to identify with reasonable specificity the defendants’ allegedly wrongful conduct. Indigo and the majority of the other defendants filed several exceptions to plaintiffs’ fourth amended petition challenging the sufficiency of plaintiffs’ allegations and seeking dismissal of certain claims. On February 18, 2021, plaintiffs filed a fifth supplemental and amending petition, which seeks to augment the claims of select plaintiffs. On October 11, 2021, a sixth supplemental petition was filed which seeks to add the Company as a party to the litigation which the Company has opposed. Plaintiffs later filed seventh and eighth supplemental petitions naming additional defendants. Fact discovery for the case is ongoing. 25

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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.

(1211) INCOME TAXES

The Company’s effective tax rate was approximately 3322% and 1% for the three ~~and nine~~ months ended ~~September~~March 3031, 2024 and March 31, 2023, respectively. The effective tax rate for the three months ended March 31, ~~primarily~~2023 aswas aprimarily the result of the partial release of the valuation allowances against the Company’s U.S. deferred tax assets ~~throughout~~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.

27For 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 ~~uses~~incurred ~~estimates~~a cumulative ownership change and ~~judgment~~as ~~regarding~~such, ~~future~~the ~~taxable~~Company’s ~~income~~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 ~~considers~~resulting annual limitation will result in the expiration of NOLs or other tax ~~consequences~~attributes inotherwise available. At March 31, 2024, the ~~jurisdiction~~Company ~~where~~had ~~such~~approximately ~~taxable~~$4 ~~income~~billion isof ~~generated~~federal NOL carryovers, toof ~~determine~~which ~~whether~~approximately a$3 ~~valuation~~billion ~~allowance~~expire isbetween ~~required~~2035 and 2037 and $1 billion have an indefinite carryforward life. ~~Such~~ ~~evidence~~The ~~can~~Company ~~include~~currently ~~current~~estimates ~~financial~~that ~~position,~~approximately ~~results~~$2 billion of ~~operations,~~these ~~both~~federal ~~actual~~NOLs will expire before they are able to be used and ~~forecasted~~accordingly, no value has been ascribed to these NOLs on the ~~reversal~~Company’s ofbalance ~~deferred~~sheet. ~~tax~~If ~~liabilities~~a ~~and~~subsequent ~~tax~~ownership ~~planning~~change ~~strategies~~were asto ~~well~~occur as a result of future transactions in the ~~current~~Company’s ~~and~~common ~~forecasted~~stock, ~~business~~the ~~economics~~Company’s use of ~~the~~remaining ~~oil~~U.S. ~~and~~tax ~~gas~~attributes ~~industry~~may be further limited.

~~For~~The ~~the~~Inflation ~~year~~Reduction ~~ended~~Act ~~December 31,~~of 2022, (the ~~Company~~“IRA”) ~~maintained~~was aenacted ~~full valuation allowance against its deferred tax assets based~~ on ~~its~~August ~~conclusion~~16, ~~considering~~2022 ~~all available evidence (both positive~~ and ~~negative),~~may ~~that~~impact ithow ~~was more likely than not that~~ the ~~deferred~~U.S. ~~tax~~taxes ~~assets~~certain ~~would~~large ~~not be realized~~corporations. AThe ~~significant~~IRA ~~item~~imposes ofa ~~objective~~15% ~~negative~~alternative ~~evidence~~minimum ~~considered was the cumulative pre-~~tax ~~loss~~on ~~incurred over~~ the ~~three-year~~“adjusted ~~period~~financial ~~ended~~statement ~~December 31,~~income” ~~2022, primarily due to impairments~~ of ~~proved~~certain ~~oil~~large ~~and~~corporations ~~gas~~(generally, ~~properties~~corporations ~~recognized~~reporting inat ~~2020.~~least As$1 ofbillion ~~the~~average ~~first~~adjusted ~~quarter of 2023, the Company sustained a three~~pre-~~year~~tax ~~cumulative~~net ~~level~~income ~~of profitability. Based~~ on ~~this~~their ~~factor~~consolidated ~~and~~financial ~~other~~statements) ~~positive~~for ~~evidence~~tax ~~such~~years asbeginning ~~forecasted~~after ~~income~~December 31, ~~the~~2022. The Company ~~concluded~~was ~~that $523 million of its federal and state deferred tax assets were more likely than~~ not toimpacted beby ~~realized and plan to release this portion of~~ the ~~valuation~~alternative ~~allowance~~minimum intax ~~2023. Accordingly,~~ during ~~the nine months ended September 30,~~ 2023, ~~the~~and ~~Company~~does ~~recognized~~not ~~$520~~expect ~~million of deferred income tax expense related~~ to ~~recording~~be ~~its~~impacted ~~tax provision which was partially offset~~ by ~~$492~~this ~~million~~alternative ofminimum tax ~~benefit attributable to the release of the valuation allowance. The remaining valuation allowance will be released~~ during ~~the fourth quarter of 2023~~2024. The Company ~~expects~~will continue to ~~keep~~monitor aupdates ~~valuation allowance of $66 million related~~ to ~~NOLs in jurisdictions in which it no longer operates and against~~ the ~~portion~~IRA ~~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~~impact ofit ~~the~~will ~~limitations~~have ~~under~~on ~~Section 382 and~~ the ~~ordering~~Company’s inconsolidated ~~which~~financial ~~such attributes may be applied~~statements.

~~Due~~(12) toLONG-TERM ~~the~~INCENTIVE issuance of common stock associated with the Indigo Merger, the Company incurred a cumulative ownership change and as such, the Company’s NOLs prior to the acquisition are subject to an annual limitation under Internal Revenue Code Section 382 of approximately $48 million. The ownership changes and resulting annual limitation will result in the expiration of NOLs or other tax attributes otherwise available. At September 30, 2023, the Company had approximately $4 billion of federal NOL carryovers, of which approximately $3 billion expire between 2035 and 2037 and $1 billion have an indefinite carryforward life. The Company currently estimates that approximately $2 billion of these federal NOLs will expire before they are able to be used and accordingly, no value has been ascribed to these NOLs on the Company’s balance sheet. If a subsequent ownership change were to occur as a result of future transactions in the Company’s common stock, the Company’s use of remaining U.S. tax attributes may be further limited.COMPENSATION

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

(13) PENSION PLAN AND OTHER POSTRETIREMENT BENEFITS

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

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

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

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

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

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

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

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

	Consolidated Statements ofOperations Classification ofNet Periodic Benefit Cost	For the three months ended September 30,				For the nine months ended September 30,
(in millions)		2023		2022		2023		2022
Service cost	General and administrative expenses	$	—	$	—	$	—	$	—
Interest cost	Other Income (Loss), Net	—		1		—		3
Expected return on plan assets	Other Income (Loss), Net	—		—		—		—
Amortization of prior service cost	Other Income (Loss), Net	—		—		(1)		(1)
Settlement loss	Other Income (Loss), Net	—		—		2		—
Net periodic benefit cost		$	—	$	1	$	1	$	2

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

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

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

(14) LONG-TERM INCENTIVE COMPENSATION

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

Stock-Based Compensation

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

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

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

The Company issues performance unit awards to employees which historically have vested at or over three years. The performance units granted in 2021, 2022, and 2023 cliff-vest at the end of three years. There were no performance unit awards granted as of March 31, 2024.

~~The Company recognized the following amounts in total related to long-term incentive compensation costs for the three and nine months ended September 30, 2023 and 2022:~~27

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

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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 ~~and nine~~ months ended ~~September~~March 3031, ~~2023~~2024 and ~~2022~~2023:

	For the three months ended September 30,				For the nine months ended September 30,
	For the three months ended March 31,
(in millions)	~~2023~~2024		~~2022~~2023		~~2023~~		~~2022~~
Equity-classified awards – expensed	$	27	$	1	$	7	$	4
Equity-classified awards – capitalized	$	13	$	—1	$	2	$	—

Equity-Classified Stock Options

The following table summarizes equity-classified stock option activity for the ~~nine~~three months ended ~~September~~March 3031, ~~2023~~2024 and provides information for options outstanding and options exercisable as of ~~September~~March 3031, ~~2023~~2024:

	Numberof Options	Weighted AverageExercise Price
	(in thousands)
Outstanding at December 31, 2022	997	$	8.59
Outstanding at December 31, 2023	820	$	8.59
Granted	—	$	—
Exercised	—	$	—
Forfeited or expired	(~~177~~820)	$	8.6059
Outstanding at September 30, 2023	820	$	8.59
Outstanding at March 31, 2024	—	$	—
Exercisable at September 30, 2023	820	$	8.59
Exercisable at March 31, 2024	—	$	—

Equity-Classified Restricted Stock

As of ~~September~~March 3031, ~~2023~~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 0.61 ~~years~~year. The following table summarizes equity-classified restricted stock activity for the ~~nine~~three months ended ~~September~~March 3031, ~~2023~~2024 and provides information for unvested shares as of ~~September~~March 3031, ~~2023~~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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	Numberof Shares	Weighted AverageFair Value
	(in thousands)
Unvested shares at December 31, 2022	211	$	5.81
Granted	336	$	5.34
Vested	(378)	$	5.71
Forfeited	—	$	—
Unvested shares at September 30, 2023	169	$	5.09

Equity-Classified Restricted Stock Units

As of ~~September~~March 3031, ~~2023~~2024, there was $820 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 12.64 years. The following table summarizes equity-classified restricted stock units for the ~~nine~~three months ended ~~September~~March 3031, ~~2023~~2024 and provides information for unvested units as of ~~September~~March 3031, ~~2023~~2024.

	Numberof Shares	Weighted AverageFair Value
	(in thousands)
Unvested units at December 31, 2022	1,645	$	4.44
Unvested units at December 31, 2023	2,706	$	4.74
Granted	13,~~539~~182	$	47.8310
Vested	(~~555~~1,084)	$	4.4269
Forfeited	~~(1)~~—	$	~~3.05~~—
Unvested units at September 30, 2023	2,628	$	4.67
Unvested units at March 31, 2024	4,804	$	6.32

Equity-Classified Performance Units

In each year ~~beginning~~from ~~with~~ 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 ~~September~~March 3031, ~~2023~~2024, there was $75 million of total unrecognized compensation costs related to the Company’s unvested equity-classified performance units. This cost is expected to be recognized over a weighted-average period of 2.1.6 years.

	Numberof Shares	Weighted AverageFair Value
	(in thousands)
Unvested units at December 31, 2022	817	$	6.04
Unvested units at December 31, 2023	1,757	$	6.08
Granted	~~940~~—	$	~~6.12~~—
Vested	—	$	—
Forfeited	—	$	—
Unvested units at September 30, 2023	1,757	$	6.08
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 ~~and nine~~ months ended ~~September~~March 3031, ~~2023~~2024:

	For the three months ended September 30,				For the nine months ended September 30,
	For the three months ended March 31,
(in millions)	~~2023~~2024		~~2022~~2023		~~2023~~		~~2022~~
Liability-classified stock-based compensation cost – expensed	$	21	$	31	$	3	$	15
Liability-classified stock-based compensation cost – capitalized	$	1—	$	2—	$	2	$	10

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Liability-Classified Restricted Stock Units

In ~~the first quarter of~~ each year ~~beginning~~from ~~with~~ 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 ~~September~~March 3031, ~~2023~~2024, ~~there~~the ~~was $3 million of total unrecognized compensation cost related to~~ liability-classified restricted stock units ~~that~~fully ~~is expected to be recognized over a weighted-average period of 0~~vested.~~4 years. The amount of unrecognized compensation cost for liability-classified awards will fluctuate over time as they are marked to market.~~

	Numberof Units	Weighted AverageFair Value
	(in thousands)
Unvested units at December 31, 2022	3,950	$	4.81
Unvested units at December 31, 2023	1,741	$	4.67
Granted	—	$	—
Vested	(21,~~206~~741)	$	46.8493
Forfeited	~~(3)~~—	$	~~5.57~~—
Unvested units at September 30, 2023	1,741	$	4.61
Unvested units at March 31, 2024	—	$	—

Liability-Classified Performance Units

In each year ~~beginning~~from ~~with~~ 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 ~~will~~are be recorded to general and administrative expense and capitalized expense over the vesting period of the awards.

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

As of ~~September~~March 3031, ~~2023~~2024, there was $73 million of total unrecognized compensation cost related to liability-classified performance units. This cost is expected to be recognized over a weighted-average period of 2.1.8 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.

	Numberof Units	Weighted AverageFair Value
	(in thousands)
Unvested units at December 31, 2022	10,982	$	2.25
Unvested units at December 31, 2023	12,152	$	0.94
Granted	~~5,136~~—	$	~~4.83~~—
Vested	(3,~~966~~365)	$	61.1359
Forfeited	—	$	—
Unvested units at September 30, 2023	12,152	$	1.15
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 ~~and nine~~ months ended ~~September~~March 3031, ~~2023~~2024 and ~~2022~~2023:

	For the three months ended September 30,				For the nine months ended September 30,
	For the three months ended March 31,
(in millions)	~~2023~~2024		~~2022~~2023		~~2023~~		~~2022~~
Performance cash awards – expensed	$	3	$	2	$	8	$	5
Performance cash awards – capitalized	$	23	$	2	$	7	$	5

Performance Cash Awards

From 2020 through 2022 the Company granted performance cash awards that vest over a four-year period and are payable in cash on an annual basis. In 2023 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 ~~2023~~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 ~~September~~March 3031, ~~2023~~2024, there was $3854 million of total unrecognized compensation cost related to performance cash awards. This cost is expected to be recognized over a weighted-average period of 2.23 years. The final value of the performance cash awards is contingent upon the Company’s actual performance against these performance measures.

	Numberof Units	Weighted Average Fair Value
	(in thousands)
Unvested units at December 31, 2022	39,994	$	1.00
Unvested units at December 31, 2023	49,678	$	1.00
Granted	2728,~~493~~202	$	1.00
Vested	(1320,~~250~~232)	$	1.00
Forfeited	(~~3,761~~364)	$	1.00
Unvested units at September 30, 2023	50,476	$	1.00
Unvested units at March 31, 2024	57,284	$	1.00

(1513) SEGMENT INFORMATION

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

Summarized financial information for the Company’s reportable segments is shown in the following table. The accounting policies of the segments are the same as those described in Note 1 of the Notes to Consolidated Financial Statements included in Item 8 of the ~~2022~~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		~~Other~~Total Reportable Segments		~~Total~~Other		Total
Three months ended September 30, 2023	(in millions)
Three months ended March 31, 2024	(in millions)
Revenues from external customers	$	~~890~~838		$	~~553~~579	$	—1,417	$	~~1,443~~—	$	1,417
Intersegment revenues	(1714)			~~826~~798		—784		~~809~~—		784
Depreciation, depletion and amortization expense	~~337~~261			1		—262		~~338~~—		262
Operating income (loss)	(18)			25		—		7
Impairments	2,093			—		2,093		—		2,093
Interest expense (1)	36			—		—		36
Operating income (loss)	(2,061)			4		(2,057)		—		(2,057)
Gain on derivatives	93			—		—		93
Interest expense (1)	35			—		35		—		35
Other income, net	1			—		1		2
Gain on derivatives	126			—		126		—		126
Provision for income taxes (1)	21			—		—		21
Other income, net	1			—		1		—		1
Assets	12,350		(2)	483		140		12,973
Benefit for income taxes (1)	(430)			—		(430)		—		(430)
Capital investments (3)	452			—		2		454
Assets	9,856		(2)	391		10,247		151		10,398
Three months ended September 30, 2022
Capital investments (3)	537			—		537		1		538
Revenues from external customers	$	3,243		$	1,298	$	—	$	4,541
Three months ended March 31, 2023
Intersegment revenues	4			3,138		—		3,142
Revenues from external customers	$	1,439		$	679	$	2,118	$	—	$	2,118
Depreciation, depletion and amortization expense	297			1		—		298
Intersegment revenues	(10)			1,362		1,352		—		1,352
Operating income	2,386			28		—		2,414
Depreciation, depletion and amortization expense	312			1		313		—		313
Interest expense (1)	50			—		—		50
Operating income	578			28		606		—		606
Loss on derivatives	(1,903)			—		—		(1,903)
Interest expense (1)	36			—		36		—		36
Provision for income taxes (1)	11			—		—		11
Gain on derivatives	1,401			—		1,401		—		1,401
Assets	11,359		(2)	1,633		112		13,104
Loss on early extinguishment of debt	—			—		—		(19)		(19)
Capital investments (3)	540			—		3		543
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

	Exploration and Production			Marketing		Other		Total
Nine months ended September 30, 2023	(in millions)
Revenues from external customers	$	3,123		$	1,707	$	—	$	4,830
Intersegment revenues	(44)			2,944		—		2,900
Depreciation, depletion and amortization expense	975			4		—		979
Operating income	490			66		—		556
Interest expense (1)	106			—		—		106
Gain on derivatives	1,811			—		—		1,811
Loss on extinguishment of debt	—			—		(19)		(19)
Other income, net	—			—		1		1
Provision for income taxes (1)	28			—		—		28
Assets	12,350		(2)	483		140		12,973
Capital investments (3)	1,709			—		5		1,714
Nine months ended September 30, 2022
Revenues from external customers	$	8,251		$	3,371	$	—	$	11,622
Intersegment revenues	(1)			7,843		—		7,842
Depreciation, depletion and amortization expense	857			4		—		861
Operating income	5,784		(4)	60		—		5,844
Interest expense (1)	139			—		—		139
Loss on derivatives	(6,707)			—		(2)		(6,709)
Loss on early extinguishment of debt	—			—		(6)		(6)
Other loss, net	—			(1)		—		(1)
Provision for income taxes (1)	41			—		—		41
Assets	11,359		(2)	1,633		112		13,104
Capital investments (3)	1,669			—		3		1,672

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

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

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

34(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.

~~Table~~The following table presents the breakout of ~~Contents~~ other assets, which represent corporate assets not allocated to segments and assets for non-reportable segments as of March 31, 2024 and 2023:

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


	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

(41)~~The~~Consists ~~E&P~~primarily ~~segment~~of ~~operating~~costs ~~income~~associated ~~includes~~with ~~$27~~the ~~million~~development of ~~merger-related~~the ~~expenses~~Company’s ~~related~~enterprise toresource ~~the~~technology ~~Indigo~~as of March 31, 2024 and ~~GEPH~~residual ~~Mergers~~assets ~~for~~associated with the ~~nine~~Company’s ~~months~~pension ~~ended~~plan ~~September~~as of March 3031, ~~2022~~2023, respectively.

~~The~~(14) ~~following~~NEW ~~table~~ACCOUNTING ~~presents the breakout of other assets, which represent corporate assets not allocated to segments and assets for non-reportable segments as of September 30, 2023 and 2022:~~PRONOUNCEMENTS

	As of September 30,
(in millions)	2023			2022
Cash and cash equivalents	$	26		$	11
Accounts receivable	1			1
Prepayments	10			8
Other current assets	2			—
Property, plant and equipment	21			10
Unamortized debt expense	16			21
Right-of-use lease assets	51			58
Non-qualified retirement plan	3			3
Other long-term assets	10		(1)	—
	$	140		$	112

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

(16) NEW ACCOUNTING PRONOUNCEMENTS

New Accounting Standards Implemented in this Report

None.

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New Accounting Standards Not Yet Adopted in this Report

~~None~~In ~~that~~November ~~are~~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, ~~2022~~2023 (the “~~2022~~2023 Annual Report”) and analyzes the changes in the results of operations between the three ~~and nine~~ month periods ended ~~September~~March 3031, ~~2023~~2024 and ~~2022~~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 ~~2022~~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 ~~2022~~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, 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 33

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~~reservoirs.~~which Wewe ~~also~~call ~~have~~“Marketing”. ~~drilling~~We ~~rigs~~conduct ~~located~~most inof ~~Appalachia~~our ~~and~~businesses ~~Haynesville~~through subsidiaries, and we ~~provide~~currently ~~certain~~operate ~~oilfield~~exclusively ~~products~~in ~~and~~the ~~services,~~Appalachian ~~principally~~and ~~serving~~Haynesville ~~our~~natural ~~E&P~~gas ~~operations~~basins ~~through~~in ~~vertical integration. Over~~ the ~~past~~lower ~~three~~48 ~~years,~~United ~~we have completed three strategic acquisitions which have added scale to our operations:~~States.

~~•On~~E&P. ~~November~~Our 13primary business is the development and production of natural gas as well as associated NGLs and oil, ~~2020~~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 ~~closed~~refer to as “Appalachia,” are focused on the ~~Montage~~Marcellus ~~Merger~~Shale, the Utica and the Upper Devonian unconventional natural gas and liquids reservoirs. Our operations in Louisiana, which ~~increased~~we ~~our~~refer ~~footprint~~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 ~~West~~Appalachia ~~Virginia~~and Haynesville, and ~~Pennsylvania~~we provide certain oilfield products and ~~expanded~~services, principally serving our E&P operations ~~into~~through ~~Ohio~~vertical integration.

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

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

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

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

Recent Financial and Operating Results

Significant ~~third~~first quarter ~~2023~~2024 operating and financial results include:

Total Company

•Net ~~income~~loss of $451,535 million, or ($01.0439) per diluted share, decreased compared to net income of $~~450~~1,939 million, or $01.4076 per diluted share, for the same period in ~~2022~~2023. Net income decreased due to lower operating income of $2,~~407~~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 ~~higher~~reduced ~~income~~gain ~~tax~~in ~~provision~~our net derivative position of approximately $10 1,275 million. The decrease in net income from the ~~third~~first quarter of ~~2022~~2023 to the ~~third~~first quarter of ~~2023~~2024 was partially offset by a ~~positive~~decrease ~~change~~ in our ~~net~~income ~~derivative~~tax ~~position~~provision of ~~approximately~~ $~~2 billion due to an increase in our settled derivative position of approximately $2,051~~ 442 million, ~~partially~~and ~~offset by~~ a ~~lower mark to market position on our unsettled derivatives of approximately~~ $55 19 million, asloss aon ~~result~~early ofdebt ~~changes~~extinguishment in ~~commodity~~2023 ~~pricing.~~compared ~~Further offsetting the decrease in net income from the third quarter of 2022~~ to ~~the~~no ~~third~~gain ~~quarter~~or ofloss ~~2023 was decreased interest expense of $14 million as a result from our debt reduction~~ in ~~the prior periods~~2024.

•Operating ~~income~~loss of $72,057 million decreased compared to operating income of $~~2,414~~606 million for the same period in ~~2022~~2023 on a consolidated basis. Operating income decreased asdue to a $~~3,098~~701 million decrease in operating revenues, ~~was~~attributable ~~only~~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 ~~decreased~~lower operating costs of $~~691~~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 $~~477~~496 million decreased as compared to $~~797~~ 1,137 million for the same period in ~~2022~~2023. The decrease was primarily attributable to the impact of lower commodity pricing on revenues of $~~2,246~~ 479 million, lower production of $~~129~~126 million, and anegative ~~higher~~changes ~~provision~~in ~~for~~working ~~income~~capital ~~taxes~~ of $10307 million, and was partially offset by an increase in our settled derivative positions of $~~2,051~~ 279 million ~~and lower interest expense of $14 million~~.

•Total capital investment of $~~454~~538 million in the ~~third~~first quarter of ~~2023~~2024 decreased 1619% from $~~543~~665 million for the same period in ~~2022~~2023 primarily due to lower activity levels associated with lower commodity pricing period over period.

E&P

•E&P operating loss of $182,061 million in the ~~third~~first quarter of ~~2023~~2024 decreased from operating income of $~~2,386~~578 million in the ~~third~~first quarter of ~~2022~~2023 for a total decrease of $2,~~404~~639 million, primarily due to a $~~2,374~~605 million decrease in E&P operating revenues resulting from a $51.28 per Mcfe decrease in our realized weighted average price per Mcfe (excluding derivatives) and ana 1835 Bcfe decrease in production volumes. ~~combined~~The ~~with~~decrease in operating income was partially offset by a $3059 million ~~increase~~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 ~~425~~376 Bcfe, which was comprised of 86% natural gas and 14% oil and NGLs, decreased 49% from ~~443~~411 Bcfe in the same period in ~~2022~~2023, primarily due to aan 58% 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 $1.6676 per Mcf decreased 7845%, our realized oil price of $7166.0907 per barrel ~~decreased~~increased ~~16%~~slightly from $65.92 and our realized NGL price of $2023.5388 per barrel decreased 382%, as compared to the same period in ~~2022~~2023. Excluding the effect of derivatives, our total weighted average realized price of $2.0520 per Mcfe decreased 7237% from the same period in ~~2022~~2023.

•E&P segment invested $~~452~~537 million in capital; drilling 2429 wells, completing 2527 wells and placing 2318 wells to sales.

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Outlook

Our primary focus in ~~2023~~2024 is to ~~generally~~align ~~maintain~~capital ~~our~~investment ~~productive~~with ~~capacity~~expected ~~and~~annual ~~improve the safety and efficiency of our operations to further our ability to generate free~~ cash flow, ~~further~~in ~~reduce~~a ~~debt~~manner ~~and~~that ~~return~~maintains ~~capital~~production ~~to shareholders (subject to market and business conditions)~~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; ~~improving~~enhancing the ~~cost of~~ capital efficiency of our operations; and converting resources to proved reserves.

•Protecting Financial Strength. We intend to protect our financial strength by lowering our leverage ratio and total debt; maintaining a strong liquidity position and ~~extended~~attractive debt maturity profile; improving our credit ratings; lowering our weighted average cost of ~~capital~~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 ~~2022~~2023 Annual Report. As such, we intend to protect our financial strength by reducing our debt ~~while continuing to extend the weighted average years to maturity of our debt,~~ and by maintaining a derivative program designed to reduce our exposure to commodity price volatility.

RESULTS OF OPERATIONS

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

E&P

	For the three months ended September 30,				For the nine months ended September 30,
	For the three months ended March 31,
(in millions)	~~2023~~2024		~~2022~~2023		~~2023~~		~~2022~~
Revenues	$	~~873~~824	$	31,~~247~~429	$	~~3,079~~	$	~~8,250~~
Operating costs and expenses (1)	891		861		2,589		2,466
Operating costs and expenses	2,885		851
Operating income (loss)	$	(182,061)	$	~~2,386~~578	$	~~490~~	$	~~5,784~~
Gain (loss) on derivatives, settled	$	~~162~~156	$	(~~1,889~~123)	$	~~249~~	$	~~(4,185)~~

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

Operating Income (Loss)

•E&P segment operating ~~loss~~income decreased $2,~~404~~639 million for the three months ended ~~September~~March 3031, ~~2023~~2024, compared to operating income of $578 million during the same period in ~~2022~~2023. ~~The~~Excluding the impact of the $2,093 million non-cash full cost ceiling test impairments, the decrease was primarily due to a $~~2,374~~605 million decrease in E&P operating revenues resulting from a 7237% decrease in our realized weighted average price per Mcfe (excluding derivatives) and a 49% decrease in production volumes ~~combined~~partially ~~with~~offset by a $3059 million ~~increase~~decrease in E&P operating costs and expenses.

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

Revenues

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

	Three months ended September 30,
	Three months ended March 31,
(in millions except percentages)	NaturalGas			Oil			NGLs			Total
2022 sales revenues (1)	$	2,889		$	99		$	260		$	3,248
2023 sales revenues (1)	$	1,136		$	94		$	201		$	1,431
Changes associated with prices	(~~2,123~~475)			(181)			(~~105~~3)			(~~2,246~~479)
Changes associated with production volumes	(~~156~~90)			(12)			15(24)			(~~129~~126)
2023 sales revenues (2)	$	610		$	93		$	170		$	873
2024 sales revenues (2)	$	571		$	81		$	174		$	826
Decrease from 2022	(79		%)	(6		%)	(35		%)	(73		%)
Decrease from 2023	(50		%)	(14		%)	(13		%)	(42		%)

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

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

(12)Excludes $12 million in other operating revenues for the three ~~and nine~~ months ended ~~September~~March 3031, ~~2022~~2024 primarily related to gas balancing losses.

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

Table of Contents

Production Volumes

For the three months ended September 30,

Increase/(Decrease)

For the nine months ended September 30,

Increase/(Decrease)

For the three months ended March 31,

Increase/(Decrease)

Production volumes:

~~2023~~2024

~~2022~~2023

~~2023~~

~~2022~~

Natural Gas (Bcf)

Appalachia

~~205~~187

~~213~~193

(43)%

~~597~~

~~637~~

~~(6)%~~

Haynesville

~~163~~138

~~176~~160

(714)%

~~489~~

~~511~~

~~(4)%~~

Total

~~368~~325

~~389~~353

(58)%

~~1,086~~

~~1,148~~

~~(5)%~~

Oil (MBbls)

Appalachia

1,~~303~~226

1,~~169~~409

11(13)%

~~4,146~~

~~3,786~~

~~10%~~

Haynesville

50(38)%

~~40%~~

Other

1—

—1

(100)%

~~(60)%~~

Total

1,~~310~~231

1,~~173~~418

12(13)%

~~4,169~~

~~3,806~~

~~10%~~

NGL (MBbls)

Appalachia

87,~~226~~260

78,~~787~~240

6(12)%

~~24,707~~

~~22,444~~

~~10%~~

Haynesville

—

100%

—

~~100%~~

Other

—

(100)%

—%

Total

7,261

8,240

(12)%

Total

8,228

7,788

24,715

22,445

10%

Production volumes by area: (Bcfe)

Appalachia

~~262~~238

~~267~~251

(25)%

~~770~~

~~795~~

~~(3)%~~

Haynesville

~~163~~138

~~176~~160

(714)%

~~489~~

~~511~~

~~(4)%~~

Total

~~425~~376

~~443~~411

(49)%

~~1,259~~

~~1,306~~

~~(4)%~~

Production volumes by formation: (Bcfe)

Marcellus Shale

~~232~~213

~~226~~220

(3)%

~~680~~

~~669~~

Utica Shale

3024

4131

(2723)%

~~126~~

~~(29)%~~

Haynesville Shale

9578

~~107~~98

(1120)%

~~290~~

~~317~~

~~(9)%~~

Bossier Shale

6861

6962

(12)%

~~199~~

~~194~~

Total

~~425~~376

~~443~~411

(49)%

~~1,259~~

~~1,306~~

~~(4)%~~

Production percentage:

Natural gas

8886

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