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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q

(Mark One)

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

Exchange Act of 1934

For the quarterly period ended March 31, ~~2022~~2023

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

Exchange Act of 1934

For the transition period from ________ to ________

Commission file number: 001-08246

Southwestern Energy Company

(Exact name of registrant as specified in its charter)

Delaware

71-0205415

(State or other jurisdiction of incorporation or organization)

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

10000 Energy Drive

Spring, Texas 77389

(Address of principal executive offices)(Zip Code)

(832) 796-1000

(Registrant’s telephone number, including area code)

Not Applicable

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

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

Title of each class

Trading Symbol(s)

Name of each exchange on which registered

Common Stock, Par Value $0.01

SWN

New York Stock Exchange

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

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

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

Large accelerated filer

☒

Accelerated filer

☐

Non-accelerated filer

☐

Smaller reporting company

☐

Emerging growth company

☐

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

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

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


Class						Outstanding as of April ~~26, 2022~~25, 2023
Common Stock, Par Value $0.01						~~1,116,176,673~~1,101,267,771

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SOUTHWESTERN ENERGY COMPANY

INDEX TO FORM 10-Q

FOR THE QUARTERLY PERIOD ENDED MARCH 31, ~~2022~~2023


PART I – FINANCIAL INFORMATION			Page

Item 1.	Financial Statements		4
	Consolidated Statements of Operations		4
	Consolidated Statements of Comprehensive Income (Loss)		5
	Consolidated Balance Sheets		6
	Consolidated Statements of Cash Flows		7
	Consolidated Statements of Changes in Equity		8
	Notes to Consolidated Financial Statements		9
		Note 1. Basis of Presentation	9
		Note 2. Acquisition	9
		Note ~~3. Restructuring Charges~~3 . Revenue Recognition	1310
		Note ~~4. Revenue Recognition~~4 . Cash and Cash Equivalents	11
		Note 5 . Natural Gas and Oil Properties	12
		Note 6 . Earnings per Share	12
		Note 7 . Derivatives and Risk Management	14
		Note ~~5. Cash and Cash Equivalents~~8 . Reclassifications From Accumulated Other Comprehensive Income (Loss)	1520
		Note ~~6. Natural Gas and Oil Properties~~9 . Fair Value Measurements	1520
		Note ~~7. Earnings per Share~~1	160
		~~Note 8. Derivatives and Risk Management~~	17
		~~Note 9. Reclassifications From Accumulated Other Comprehensive Income (Loss)~~. Debt	23
		Note ~~10. Fair Value Measurements~~1 1 . Commitments and Contingencies	2326
		Note ~~11. Debt~~1 2 . Income Taxes	2627
		Note 1 23 . ~~Commitments~~Pension Plan and ~~Contingencies~~Other Postretirement Benefits	31
		~~Note 1~~3 ~~. Income Taxes~~	3228
		Note 1 4 . Long-Term Incentive Compensation	29
		Note 1 ~~Pension Plan and Other Post~~5 r ~~etirement~~ ~~Benefits~~. Segment Information	33
		Note ~~15. Long-Term Incentive Compensation~~	34
		~~Note~~ 1 6 ~~. Segment Information~~	37
		~~Note 1~~7 . New Accounting Pronouncements	3834

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		3935
	Results of Operations		4237
	Liquidity and Capital Resources		4944
Item 3.	Quantitative and Qualitative Disclosures About Market Risk		5550
Item 4.	Controls and Procedures		5651

PART II – OTHER INFORMATION

Item 1.	Legal Proceedings		5752
Item 1A.	Risk Factors		5752
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds		5752
Item 3.	Defaults Upon Senior Securities		5752
Item 4.	Mine Safety Disclosures		5752
Item 5.	Other Information		5752
Item 6.	Exhibits		5853

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CAUTIONARY STATEMENT ABOUT FORWARD-LOOKING STATEMENTS

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

Forward-looking statements include the items identified in the preceding paragraph, information concerning possible or assumed future results of operations and other statements in this Quarterly Report ~~on Form 10-Q (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 the COVID-19 pandemic or other world health event;

•our ability to fund our planned capital investments;

•a change in our credit rating ~~and an increase~~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 the impact of COVID-19 or other diseases;

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

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

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

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

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

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

•~~costs in connection with the Mergers and the transactions contemplated thereby;~~

•~~integration of operations and results subsequent to the Mergers;~~

•risks related to the Mergers, including potential litigation relating to the Mergers, and the effect of the consummation of the Mergers on business relationships, operating results, employees, stakeholders and business generally of the parties;

•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 completing 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;

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•increased competition;

•inflation rates;

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

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•the comparative cost of alternative fuels;

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

•our hedging strategy and results;

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

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

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

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

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

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PART I – FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

SOUTHWESTERN ENERGY COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)


		For the three months ended March 31,				For the three months ended March 31,
(in millions, except share/per share amounts)	(in millions, except share/per share amounts)	2022		2021			(in millions, except share/per share amounts)	2023		2022
Operating Revenues:	Operating Revenues:						Operating Revenues:
Gas sales	Gas sales	$	1,692	$	464		Gas sales	$	1,145	$	1,692
Oil sales	Oil sales	111		81			Oil sales	95		111
NGL sales	NGL sales	272		173			NGL sales	201		272
Marketing	Marketing	866		352			Marketing	679		866
Other	Other	2		2			Other	(2)		2
		2,943		1,072				2,118		2,943
Operating Costs and Expenses:	Operating Costs and Expenses:						Operating Costs and Expenses:
Marketing purchases	Marketing purchases	862		356			Marketing purchases	667		862
Operating expenses	Operating expenses	381		250			Operating expenses	418		381
General and administrative expenses	General and administrative expenses	44		38			General and administrative expenses	46		44
Merger-related expenses	Merger-related expenses	25		1			Merger-related expenses	—		25
Restructuring charges		—		6

Depreciation, depletion and amortization	Depreciation, depletion and amortization	275		96			Depreciation, depletion and amortization	313		275

Taxes, other than income taxes	Taxes, other than income taxes	57		24			Taxes, other than income taxes	68		57
		1,644		771				1,512		1,644
Operating Income	Operating Income	1,299		301			Operating Income	606		1,299
Interest Expense:	Interest Expense:						Interest Expense:
Interest on debt	Interest on debt	68		50			Interest on debt	63		68
Other interest charges	Other interest charges	3		3			Other interest charges	3		3
Interest capitalized	Interest capitalized	(30)		(22)			Interest capitalized	(30)		(30)
		41		31				36		41

Loss on Derivatives		(3,927)		(191)
Gain (Loss) on Derivatives							Gain (Loss) on Derivatives	1,401		(3,927)
Loss on Early Extinguishment of Debt	Loss on Early Extinguishment of Debt	(2)		—			Loss on Early Extinguishment of Debt	(19)		(2)
Other Income, Net		—		1
Other Loss, Net							Other Loss, Net	(1)		—

Income (Loss) Before Income Taxes	Income (Loss) Before Income Taxes	(2,671)		80			Income (Loss) Before Income Taxes	1,951		(2,671)
Provision (Benefit) for Income Taxes:
Provision for Income Taxes:							Provision for Income Taxes:
Current	Current	4		—			Current	—		4
Deferred	Deferred	—		—			Deferred	12		—
		4		—				12		4
Net Income (Loss)	Net Income (Loss)	$	(2,675)	$	80		Net Income (Loss)	$	1,939	$	(2,675)

Earnings (Loss) Per Common Share:	Earnings (Loss) Per Common Share:						Earnings (Loss) Per Common Share:
Basic	Basic	$	(2.40)	$	0.12		Basic	$	1.76	$	(2.40)
Diluted	Diluted	$	(2.40)	$	0.12		Diluted	$	1.76	$	(2.40)

Weighted Average Common Shares Outstanding:	Weighted Average Common Shares Outstanding:						Weighted Average Common Shares Outstanding:
Basic	Basic	1,114,610,964		675,385,145			Basic	1,100,278,261		1,114,610,964
Diluted	Diluted	1,114,610,964		679,867,825			Diluted	1,102,396,636		1,114,610,964

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

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SOUTHWESTERN ENERGY COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(Unaudited)


		For the three months ended March 31,				For the three months ended March 31,
(in millions)	(in millions)	2022		2021			(in millions)	2023		2022
Net income (loss)	Net income (loss)	$	(2,675)	$	80		Net income (loss)	$	1,939	$	(2,675)

Change in value of pension and other postretirement liabilities:	Change in value of pension and other postretirement liabilities:						Change in value of pension and other postretirement liabilities:
Settlement adjustment (1)		—		—

Amortization of prior service cost and net gain, including gain on settlements and curtailments included in net periodic pension cost (1)							Amortization of prior service cost and net gain, including gain on settlements and curtailments included in net periodic pension cost (1)	1		—
Net actuarial loss incurred in period							Net actuarial loss incurred in period	(2)		—
Net tax loss attributable to pension termination							Net tax loss attributable to pension termination	(14)		—
Total change in value of pension and postretirement liabilities							Total change in value of pension and postretirement liabilities	(15)		—
Comprehensive income (loss)	Comprehensive income (loss)	$	(2,675)	$	80		Comprehensive income (loss)	$	1,924	$	(2,675)

(1)Settlement adjustment was less than $1 million for the three months ended March 31, 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)


		March 31, 2022		December 31, 2021			March 31, 2023		December 31, 2022

ASSETS	ASSETS	(in millions)				ASSETS	(in millions)
Current assets:	Current assets:					Current assets:
Cash and cash equivalents	Cash and cash equivalents	$	21	$	28	Cash and cash equivalents	$	3	$	50
Accounts receivable, net	Accounts receivable, net	1,071		1,160		Accounts receivable, net	667		1,401
Derivative assets	Derivative assets	103		183		Derivative assets	463		145
Other current assets	Other current assets	43		42		Other current assets	66		68
Total current assets	Total current assets	1,238		1,413		Total current assets	1,199		1,664
Natural gas and oil properties, using the full cost method, including $2,228 million as of March 31, 2022 and $2,231 million as of December 31, 2021 excluded from amortization		34,184		33,631
Natural gas and oil properties, using the full cost method, including $2,185 million as of March 31, 2023 and $2,217 million as of December 31, 2022 excluded from amortization						Natural gas and oil properties, using the full cost method, including $2,185 million as of March 31, 2023 and $2,217 million as of December 31, 2022 excluded from amortization	36,430		35,763

Other	Other	513		509		Other	532		527
Less: Accumulated depreciation, depletion and amortization	Less: Accumulated depreciation, depletion and amortization	(24,482)		(24,202)		Less: Accumulated depreciation, depletion and amortization	(25,704)		(25,387)
Total property and equipment, net	Total property and equipment, net	10,215		9,938		Total property and equipment, net	11,258		10,903
Operating lease assets	Operating lease assets	186		187		Operating lease assets	175		177
Long-term derivative assets	Long-term derivative assets	126		226		Long-term derivative assets	201		72
Deferred tax assets	Deferred tax assets	—		—		Deferred tax assets	—		—
Other long-term assets	Other long-term assets	82		84		Other long-term assets	104		110
Total long-term assets	Total long-term assets	394		497		Total long-term assets	480		359
TOTAL ASSETS	TOTAL ASSETS	$	11,847	$	11,848	TOTAL ASSETS	$	12,937	$	12,926
LIABILITIES AND EQUITY	LIABILITIES AND EQUITY					LIABILITIES AND EQUITY
Current liabilities:	Current liabilities:					Current liabilities:
Current portion of long-term debt		$	5	$	206

Accounts payable	Accounts payable	1,488		1,282		Accounts payable	$	1,549	$	1,835
Taxes payable	Taxes payable	80		93		Taxes payable	109		136
Interest payable	Interest payable	49		75		Interest payable	27		86

Derivative liabilities	Derivative liabilities	3,940		1,279		Derivative liabilities	409		1,317
Current operating lease liabilities	Current operating lease liabilities	44		42		Current operating lease liabilities	43		42
Other current liabilities	Other current liabilities	64		75		Other current liabilities	29		65
Total current liabilities	Total current liabilities	5,670		3,052		Total current liabilities	2,166		3,481
Long-term debt	Long-term debt	4,895		5,201		Long-term debt	3,935		4,392
Long-term operating lease liabilities	Long-term operating lease liabilities	139		142		Long-term operating lease liabilities	128		133
Long-term derivative liabilities	Long-term derivative liabilities	1,023		632		Long-term derivative liabilities	208		378
Pension and other postretirement liabilities		25		23

Other long-term liabilities	Other long-term liabilities	214		251		Other long-term liabilities	246		218
Total long-term liabilities	Total long-term liabilities	6,296		6,249		Total long-term liabilities	4,517		5,121
Commitments and contingencies (Note 12)		0		0
Equity/(deficit):
Common stock, $0.01 par value; 2,500,000,000 shares authorized; issued 1,160,451,456 shares as of March 31, 2022 and 1,158,672,666 shares as of December 31, 2021		12		12
Commitments and contingencies (Note 1 1)						Commitments and contingencies (Note 1 1)
Equity:						Equity:
Common stock, $0.01 par value; 2,500,000,000 shares authorized; issued 1,162,882,464 shares as of March 31, 2023 and 1,161,545,588 shares as of December 31, 2022						Common stock, $0.01 par value; 2,500,000,000 shares authorized; issued 1,162,882,464 shares as of March 31, 2023 and 1,161,545,588 shares as of December 31, 2022	12		12

Additional paid-in capital	Additional paid-in capital	7,159		7,150		Additional paid-in capital	7,178		7,172
Accumulated deficit	Accumulated deficit	(7,063)		(4,388)		Accumulated deficit	(600)		(2,539)
Accumulated other comprehensive loss		(25)		(25)
Common stock in treasury, 44,353,224 shares as of March 31, 2022 and December 31, 2021		(202)		(202)
Total equity/(deficit)		(119)		2,547
Accumulated other comprehensive income (loss)						Accumulated other comprehensive income (loss)	(9)		6
Common stock in treasury, 61,614,693 shares as of March 31, 2023 and December 31, 2022						Common stock in treasury, 61,614,693 shares as of March 31, 2023 and December 31, 2022	(327)		(327)
Total equity						Total equity	6,254		4,324
TOTAL LIABILITIES AND EQUITY	TOTAL LIABILITIES AND EQUITY	$	11,847	$	11,848	TOTAL LIABILITIES AND EQUITY	$	12,937	$	12,926

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

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SOUTHWESTERN ENERGY COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)


		For the three months ended March 31,					For the three months ended March 31,
(in millions)	(in millions)	2022		2021		(in millions)	2023		2022
Cash Flows From Operating Activities:	Cash Flows From Operating Activities:					Cash Flows From Operating Activities:
Net income (loss)	Net income (loss)	$	(2,675)	$	80	Net income (loss)	$	1,939	$	(2,675)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:	Adjustments to reconcile net income (loss) to net cash provided by operating activities:					Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization	Depreciation, depletion and amortization	275		96		Depreciation, depletion and amortization	313		275
Amortization of debt issuance costs	Amortization of debt issuance costs	2		2		Amortization of debt issuance costs	2		2

Loss on derivatives, unsettled		3,232		169
Deferred income taxes						Deferred income taxes	12		—
(Gain) loss on derivatives, unsettled						(Gain) loss on derivatives, unsettled	(1,524)		3,232
Stock-based compensation	Stock-based compensation	1		—		Stock-based compensation	1		1
Loss on early extinguishment of debt	Loss on early extinguishment of debt	2		—		Loss on early extinguishment of debt	19		2

Other	Other	(1)		—		Other	2		(1)
Change in assets and liabilities, excluding impact from acquisitions:	Change in assets and liabilities, excluding impact from acquisitions:					Change in assets and liabilities, excluding impact from acquisitions:
Accounts receivable	Accounts receivable	89		(33)		Accounts receivable	734		89
Accounts payable	Accounts payable	126		33		Accounts payable	(257)		126
Taxes payable	Taxes payable	(13)		(8)		Taxes payable	(27)		(13)
Interest payable	Interest payable	(16)		(2)		Interest payable	(33)		(16)
Inventories	Inventories	4		9		Inventories	(14)		4
Other assets and liabilities	Other assets and liabilities	(54)		1		Other assets and liabilities	(30)		(54)
Net cash provided by operating activities	Net cash provided by operating activities	972		347		Net cash provided by operating activities	1,137		972

Cash Flows From Investing Activities:	Cash Flows From Investing Activities:					Cash Flows From Investing Activities:
Capital investments	Capital investments	(500)		(227)		Capital investments	(670)		(500)
Proceeds from sale of property and equipment		—		1
Other		—		(1)

Net cash used in investing activities	Net cash used in investing activities	(500)		(227)		Net cash used in investing activities	(670)		(500)

Cash Flows From Financing Activities:	Cash Flows From Financing Activities:					Cash Flows From Financing Activities:
Payments on current portion of long-term debt	Payments on current portion of long-term debt	(202)		—		Payments on current portion of long-term debt	—		(202)

Payments on long-term debt	Payments on long-term debt	(21)		—		Payments on long-term debt	(437)		(21)
Payments on revolving credit facility	Payments on revolving credit facility	(2,803)		(923)		Payments on revolving credit facility	(1,357)		(2,803)
Borrowings under revolving credit facility	Borrowings under revolving credit facility	2,517		790		Borrowings under revolving credit facility	1,317		2,517
Change in bank drafts outstanding	Change in bank drafts outstanding	34		7		Change in bank drafts outstanding	(33)		34

Cash paid for tax withholding	Cash paid for tax withholding	(4)		(3)		Cash paid for tax withholding	(4)		(4)

Net cash used in financing activities	Net cash used in financing activities	(479)		(129)		Net cash used in financing activities	(514)		(479)

Decrease in cash and cash equivalents	Decrease in cash and cash equivalents	(7)		(9)		Decrease in cash and cash equivalents	(47)		(7)
Cash and cash equivalents at beginning of year	Cash and cash equivalents at beginning of year	28		13		Cash and cash equivalents at beginning of year	50		28
Cash and cash equivalents at end of period	Cash and cash equivalents at end of period	$	21	$	4	Cash and cash equivalents at end of period	$	3	$	21

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

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SOUTHWESTERN ENERGY COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY

(Unaudited)
Common Stock Additional
Paid-In
Capital Accumulated
Deficit Accumulated Other
Comprehensive
Income (Loss) Common Stock in Treasury Total
Shares
Issued Amount Shares Amount
(in millions, except share amounts)
Balance at December 31, 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)


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

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



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


Tax withholding – stock compensation	(662,163)	—		(4)		—		—		—	—		(4)
Balance at March 31, 2023	1,162,882,464	$	12	$	7,178	$	(600)	$	(9)	61,614,693	$	(327)	$	6,254

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, 2020 718,795,700 $ 7 $ 5,093 $ (4,363) $ (38) 44,353,224 $ (202) $ 497
Comprehensive income:
Net income — — — 80 — — — 80
Other comprehensive income — — — — — — — —
Total comprehensive income — — — — — — — 80
Issuance of restricted stock 10,067 — — — — — — —
Cancellation of restricted stock (405) — — — — — — —
Restricted units vested 2,136,882 — 8 — — — — 8
Performance units vested 1,001,505 — 4 — — — — 4
Tax withholding – stock compensation (748,627) — (3) — — — — (3)
Balance at March 31, 2021 721,195,122 $ 7 $ 5,102 $ (4,283) $ (38) 44,353,224 $ (202) $ 586


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

	(in millions, except share amounts)
Balance at December 31, 2021	1,158,672,666	$	12	$	7,150	$	(4,388)	$	(25)	44,353,224	$	(202)	$	2,547
Comprehensive income:
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)

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

Table of Contents

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 2two segments: E&P and Marketing.

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

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

Basis of Presentation

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

The comparability of certain 2022 amounts to prior periods could be impacted as a result of the Indigo Merger (as defined below) completed on September 1, 2021, and the GEPH Merger (as defined below) completed on December 31, 2021. The Company believes the disclosures made are adequate to make the information presented not misleading.

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, ~~2021~~2022 (“~~2021~~2022 Annual Report”).

The Company’s significant accounting policies, which have been reviewed and approved by the Audit Committee of the Company’s ~~Board~~board of ~~Directors,~~directors (the “Board”), are summarized in Note 1 in the Notes to the Consolidated Financial Statements included in the Company’s ~~2021~~2022 Annual Report.

(2) ACQUISITIONS

In September 2021, Southwestern completed the Indigo Merger, as defined and described below, to establish operations into the Haynesville and Bossier Shales. In December 2021, Southwestern completed the GEPH Merger, as defined and described below, to extend those operations in the Haynesville and Bossier Shales. For the three months ended March 31, 2022, revenues and operating income associated with the operations acquired through the Indigo and GEPH Mergers totaled $753 million and $482 million, respectively.

GEP Haynesville, LLC Merger

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

~~Table of Contents~~

Under the terms and conditions of the GEPH Merger Agreement, the outstanding equity interests in GEPH were cancelled and converted into the right to receive $1,269 million in cash consideration and 99,337,748 shares of Southwestern common stock. These shares of Southwestern common stock had an aggregate dollar value equal to approximately $463 million, based on the closing price of $4.66 per share of Southwestern common stock on the NYSE on December 31, 2021. In addition, the Company assumed GEPH’s revolving line of credit balance of $81 million as of December 31, 2021. This balance was subsequently repaid, and the GEPH revolving line of credit was retired on December 31, 2021. See ~~Note 11~~ ~~for additional information.~~

The GEPH Merger constituted a business combination, and was accounted for using the acquisition method of accounting. For tax purposes, the GEPH Merger was treated as a sale of partnership interests and an acquisition of assets. The following table presents the fair value of consideration transferred to GEPH equity holders as a result of the GEPH Merger:


~~(in millions, except share, per share amounts)~~	~~As of December 31, 2021~~
~~Shares of Southwestern common stock issued~~	~~99,337,748~~
~~NYSE closing price per share of Southwestern common shares on December 31, 2021~~	$	~~4.66~~
	$	~~463~~
~~Cash consideration~~	~~1,269~~
~~Total consideration~~	$	~~1,732~~

The following table sets forth the preliminary fair value of the assets acquired and liabilities assumed as of the acquisition date. Certain data necessary to complete the purchase price allocation is still under evaluation, including, but not limited to, the final actualization of accrued liabilities and receivable balances as well as the valuation of natural gas and oil properties. The Company will finalize the purchase price allocation during the twelve-month period following the acquisition date, during which time the value of the assets and liabilities may be revised as appropriate.


~~(in millions)~~	~~As of December 31, 2021~~
~~Consideration:~~
~~Total consideration~~	$	~~1,732~~
~~Fair Value of Assets Acquired:~~
~~Cash and cash equivalents~~	11
~~Accounts receivable~~	~~171~~
~~Other current assets~~	3
~~Commodity derivative assets~~	56
~~Evaluated oil and gas properties~~	~~1,783~~
~~Unevaluated oil and gas properties~~ ~~(1)~~	58
~~Other property, plant and equipment~~	2
~~Other long-term assets~~	3
~~Total assets acquired~~	~~2,087~~
~~Fair Value of Liabilities Assumed:~~
~~Accounts payable~~ ~~(2)~~	~~164~~
~~Other current liabilities~~	1
~~Derivative liabilities~~	75
~~Revolving credit facility~~	81

~~Asset retirement obligations~~	24
~~Other noncurrent liabilities~~ ~~(2)~~	10
~~Total liabilities assumed~~	~~355~~
~~Net Assets Acquired and Liabilities Assumed~~	$	~~1,732~~

~~(1)Reflects $1 million purchase price adjustment during the three months ended March 31, 2022.~~

~~(2)Reflects purchase price adjustments reflecting a decrease of $6 million to accounts payable and a $5 million increase to other noncurrent liabilities during the three months ended March 31, 2022.~~

The assets acquired and liabilities assumed were recorded at their preliminary estimated fair values at the date of the GEPH Merger. Acquired working capital amounts are expected to approximate fair value due to their short-term nature. The valuation of certain assets, including property, are based on preliminary appraisals. The fair value of acquired equipment is based on both available market data and a cost approach.

~~Table of Contents~~

With the completion of the GEPH Merger, Southwestern acquired proved and unproved properties of approximately $1,783 million and $58 million, respectively, primarily associated with the Haynesville and Bossier formations. The remaining $2 million in Other property, plant and equipment consists of land, facilities and various equipment.

The income approach was utilized for unevaluated and evaluated oil and gas properties based on underlying reserve projections at the GEPH Merger date. Income approaches are considered Level 3 fair value estimates and include significant assumptions of future production, commodity prices, and operating and capital cost estimates, discounted using weighted average cost of capital for industry peers, and risk adjustment factors based on reserve category. Price assumptions were based on observable market pricing adjusted for historical differentials. Cost estimates were based on current observable costs inflated based on historical and expected future inflation. Taxes were based on current statutory rates.

The Company considered the borrowings under the revolving credit facility to approximate fair value as the balance on the GEPH revolving credit facility was immediately paid off after the GEPH Merger close. The value of derivative instruments was based on observable inputs, primarily forward commodity-price curves, and is considered Level 2.

Indigo Natural Resources Merger

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

The outstanding equity interests in Indigo were cancelled and converted into the right to receive (i) $373 million in cash consideration, subject to adjustment as provided in the Indigo Merger Agreement, and (ii) 337,827,171 shares of Southwestern common stock. These shares of Southwestern common stock had an aggregate dollar value equal to approximately $1,588 million, based on the closing price of $4.70 per share of Southwestern common stock on the NYSE on September 1, 2021. Additionally, Southwestern assumed $700 million in aggregate principal amount of Indigo’s 5.375% Senior Notes due 2029 (the “Indigo Notes”) with a fair value of $726 million as of September 1, 2021, which were subsequently exchanged for $700 million of newly issued 5.375% Senior Notes due 2029. In addition, the Company assumed Indigo’s revolving line of credit balance of $95 million as of September 1, 2021. This balance was subsequently repaid in September 2021, and the Indigo revolving line of credit was retired in September 2021. See ~~Note 7~~ ~~and~~ ~~Note 11~~ ~~for additional information.~~

The Indigo Merger constituted a business combination, and was accounted for using the acquisition method of accounting. For tax purposes, the Indigo Merger was treated as a sale of partnership interests and an acquisition of assets. The following table presents the fair value of consideration transferred to Indigo equity holders as a result of the Indigo Merger:


~~(in millions, except share, per share amounts)~~	~~As of September 1, 2021~~
~~Shares of Southwestern common stock issued~~	~~337,827,171~~
~~NYSE closing price per share of Southwestern common shares on September 1, 2021~~	$	~~4.70~~
	$	~~1,588~~
~~Cash consideration~~	~~373~~
~~Total consideration~~	$	~~1,961~~

The following table sets forth the preliminary fair value of the assets acquired and liabilities assumed as of the acquisition date. Certain data necessary to complete the purchase price allocation is still under evaluation, including, but not limited to, the valuation of natural gas and oil properties and the resolution of certain matters that the Company is indemnified for under the Indigo Merger Agreement. The Company will finalize the purchase price allocation during the twelve-month period following the acquisition date, during which time the value of the assets and liabilities may be revised as appropriate.

119

Table of Contents


~~(in millions)~~	~~As of September 1, 2021~~
~~Consideration:~~
~~Total consideration~~	$	~~1,961~~
~~Fair Value of Assets Acquired:~~
~~Cash and cash equivalents~~	55
~~Accounts receivable~~	~~192~~
~~Other current assets~~	2
~~Commodity derivative assets~~	2
~~Evaluated oil and gas properties~~	~~2,724~~
~~Unevaluated oil and gas properties~~ ~~(1)~~	~~693~~
~~Other property, plant and equipment~~	4
~~Other long-term assets~~	27
~~Total assets acquired~~	~~3,699~~
~~Fair Value of Liabilities Assumed:~~
~~Accounts payable~~ ~~(1)~~	~~283~~
~~Other current liabilities~~	55
~~Derivative liabilities~~	~~501~~
~~Revolving credit facility~~	95
~~Senior unsecured notes~~	~~726~~
~~Asset retirement obligations~~	8
~~Other noncurrent liabilities~~	70
~~Total liabilities assumed~~	~~1,738~~
~~Net Assets Acquired and Liabilities Assumed~~	$	~~1,961~~

~~(1)Reflects $9 million purchase price adjustment during the three months ended March 31, 2022.~~

The assets acquired and liabilities assumed were recorded at their preliminary estimated fair values at the date of the Indigo Merger. Acquired working capital amounts are expected to approximate fair value due to their short-term nature. The valuation of certain assets, including property, are based on preliminary appraisals. The fair value of acquired equipment is based on both available market data and a cost approach.

With the completion of the Indigo Merger, Southwestern acquired proved and unproved properties of approximately $2,724 million and $693 million, respectively, primarily associated with the Haynesville and Bossier formations. The remaining $4 million in Other property, plant and equipment consists of land, water facilities and various equipment.

The income approach was utilized for unevaluated and evaluated oil and gas properties based on underlying reserve projections at the Indigo Merger date. Income approaches are considered Level 3 fair value estimates and include significant assumptions of future production, commodity prices, and operating and capital cost estimates, discounted using weighted average cost of capital for industry peers, and risk adjustment factors based on reserve category. Price assumptions were based on observable market pricing adjusted for historical differentials. Cost estimates were based on current observable costs inflated based on historical and expected future inflation. Taxes were based on current statutory rates.

The measurement of senior unsecured notes was based on unadjusted quoted prices in an active market and are Level 1. The Company considered the borrowings under the 2018 credit facility to approximate fair value as the outstanding Indigo revolving credit facility was immediately paid off after the Indigo Merger close. The value of derivative instruments was based on observable inputs, primarily forward commodity-price and interest-rate curves and is considered Level 2.

Prior to the Indigo Merger, in May 2021, Indigo closed on an agreement to divest its Cotton Valley natural gas and oil properties. Indigo retained certain contractual commitments related to volume commitments associated with natural gas gathering, for which Southwestern has assumed the obligation to pay the gathering provider for any unused portion of the volume commitment under the agreement through 2027, depending on the buyer’s actual use. As of March 31, 2022, up to approximately~~$34 million of these contractual commitments remain, and the Company has recorded a $17 million liability for the estimated future payments.~~

Excluding the Cotton Valley gathering agreement (discussed above), the Company has recorded additional liabilities totaling $35 million as of March 31, 2022, primarily related to purchase or volume commitments associated with gathering and fresh water. These amounts will be recognized as payments are made over a period of two years.

~~Table of Contents~~

Merger-Related Expenses

The Company did not incur merger-related expenses during 2023. The following table summarizes the merger-related expenses ~~incurred:~~

For the three months ended March 31,
2022 2021
(in millions) Indigo Merger GEPH Merger Total Montage Merger
Transition services $ — $ 18 $ 18 $ —
Professional fees (bank, legal, consulting) — 1 1 —
Contract buyouts, terminations and transfers — 2 2 —
Due diligence and environmental 1 — 1 —
Employee-related — 1 1 1
Other — 2 2 —
Total merger-related expenses $ 1 $ 24 $ 25 $ 1

~~Pro Forma Information~~

~~The following table summarizes the unaudited pro forma condensed financial information for~~incurred during the three months ended March 31, ~~2021 as if the Indigo Merger and the GEPH Merger each had occurred on January 1, 2020:~~2022:

~~(in millions)~~

For the three months ended
March 31, 2021

~~Revenues~~

~~1,471~~

~~Net income attributable to common stock~~

~~Net income attributable to common stock per share - basic~~

~~0.03~~

~~Net income attributable to common stock per share - diluted~~

~~0.03~~

The unaudited pro forma information is not necessarily indicative of the operating results that would have occurred had the Indigo Merger and the GEPH Merger each been completed at January 1, 2020, nor is it necessarily indicative of future operating results of the combined entities. The unaudited pro forma information gives effect to the Indigo Merger and the GEPH Merger and any related equity and debt issuances, along with the use of proceeds therefrom, as if they had occurred on January 1, 2020 and is a result of combining the statements of operations of Southwestern with the pre-merger results of Indigo and GEPH, including adjustments for revenues and direct expenses. The pro forma results exclude any cost savings anticipated as a result of the Indigo Merger and the GEPH Merger, and include adjustments to DD&A (depreciation, depletion and amortization) based on the purchase price allocated to property, plant, and equipment and the estimated useful lives as well as adjustments to interest expense. Interest expense was adjusted to reflect any retirement of assumed senior notes, credit facilities, all related accrued interest and the associated decrease in amortization of issuance costs related to notes retired and revolving lines of credit. Interest expense was also adjusted to include the impact of the assumption and exchange of Indigo’s $700 million of 5.375% Senior Notes due 2029 for equivalent Southwestern senior notes and to reflect the retirement of the Indigo and GEPH credit facilities, all related accrued interest and the associated decreases in amortization of issuance costs related to the respective revolving lines of credit. Management believes the estimates and assumptions are reasonable, and the relative effects of the Indigo Merger and the GEPH Merger are properly reflected.

~~(3) RESTRUCTURING CHARGES~~

~~The following table presents a summary of the restructuring charges included in Operating Income for the three months ended March 31, 2022 and 2021:~~

For the three months ended March 31,
(in millions) 2022 2021
Severance (including payroll taxes) (1)
$ — $ 6

~~(1)All restructuring charges were recorded on the Company’s E&P segment for all periods presented.~~

On February 24, 2021, the Company notified employees of a workforce reduction plan as part of an ongoing strategic effort to reposition its portfolio, optimize operational performance and improve margins. Affected employees were offered a severance package, which included a one-time payment depending on length of service and, if applicable, the current value of unvested long-term incentive awards that were forfeited. These costs were recognized as restructuring charges for the three months ended March 31, 2021, and were substantially complete by the end of the first quarter of 2021.

~~Table of Contents~~

~~The Company had no liabilities associated with restructuring activities at March 31, 2022 and December 31, 2021.~~


	For the three months ended March 31, 2022
(in millions)	Indigo Merger		GEPH Merger		Total
Transition services	$	—	$	18	$	18
Professional fees (bank, legal, consulting)	—		1		1

Contract buyouts, terminations and transfers	—		2		2
Due diligence and environmental	1		—		1
Employee-related	—		1		1
Other	—		2		2
Total merger-related expenses	$	1	$	24	$	25

~~(4)~~(3) REVENUE RECOGNITION

Revenues from Contracts with Customers

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

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

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

Table of Contents

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)										(in millions)	E&P		Marketing		Intersegment Revenues		Total
Three months ended March 31, 2023										Three months ended March 31, 2023
Gas sales										Gas sales	$	1,136	$	—	$	9	$	1,145
Oil sales										Oil sales	94		—		1		95
NGL sales										NGL sales	201		—		—		201
Marketing										Marketing	—		2,041		(1,362)		679
Other (1)										Other (1)	(2)		—		—		(2)
Total										Total	$	1,429	$	2,041	$	(1,352)	$	2,118
(in millions)	(in millions)	E&P		Marketing		Intersegment Revenues		Total		(in millions)
Three months ended March 31, 2022	Three months ended March 31, 2022									Three months ended March 31, 2022
Gas sales	Gas sales	$	1,690	$	—	$	2	$	1,692	Gas sales	$	1,690	$	—	$	2	$	1,692
Oil sales	Oil sales	110		—		1		111		Oil sales	110		—		1		111
NGL sales	NGL sales	272		—		—		272		NGL sales	272		—		—		272
Marketing	Marketing	—		2,755		(1,889)		866		Marketing	—		2,755		(1,889)		866
Other (1)		2		—		—		2
Total		$	2,074	$	2,755	$	(1,886)	$	2,943

Three months ended March 31, 2021
Gas sales		$	451	$	—	$	13	$	464
Oil sales		80		—		1		81
NGL sales		173		—		—		173
Marketing		—		996		(644)		352
Other (2)	Other (2)	1		1		—		2		Other (2)	2		—		—		2
Total	Total	$	705	$	997	$	(630)	$	1,072	Total	$	2,074	$	2,755	$	(1,886)	$	2,943

(1)For the threemonths ended March 31, 2023, other E&P revenues consists primarily of losses on purchaser imbalances associated with natural gas and certain NGLs.

(2)For the three months ended March 31, 2022, other E&P revenues consists primarily of gains on purchaser imbalances associated with natural gas and certain NGLs.

~~(2)~~For the three months ended March 31, 2021, other E&P revenues consists primarily of gains on purchaser imbalances associated with certain NGLs and other Marketing revenues consists primarily of sales of gas from storage.

~~Table of Contents~~

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


		For the three months ended March 31,				For the three months ended March 31,
(in millions)	(in millions)	2022		2021			(in millions)	2023		2022
Appalachia	Appalachia	$	1,321	$	704		Appalachia	$	923	$	1,321
Haynesville	Haynesville	753		—			Haynesville	506		753
Other		—		1

Total	Total	$	2,074	$	705		Total	$	1,429	$	2,074

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)	(in millions)	March 31, 2022		December 31, 2021		(in millions)	March 31, 2023		December 31, 2022
Receivables from contracts with customers	Receivables from contracts with customers	$	972	$	1,085	Receivables from contracts with customers	$	567	$	1,313
Other accounts receivable	Other accounts receivable	99		75		Other accounts receivable	100		88
Total accounts receivable	Total accounts receivable	$	1,071	$	1,160	Total accounts receivable	$	667	$	1,401

Amounts recognized against the Company’s allowance for doubtful accounts related to receivables arising from contracts with customers were immaterial for both the three months ended March 31, ~~2022~~2023 and ~~2021, respectively.~~year ended December 31, 2022. The Company has no contract assets or contract liabilities associated with its revenues from contracts with customers.

~~(5)~~(4) CASH AND CASH EQUIVALENTS

The following table presents a summary of cash and cash equivalents as of March 31, ~~2022~~2023 and December 31, ~~2021:~~2022:


(in millions)	(in millions)	March 31, 2022		December 31, 2021		(in millions)	March 31, 2023		December 31, 2022
Cash	Cash	$	21	$	28	Cash	$	2	$	49
Marketable securities (1)	Marketable securities (1)	—		—		Marketable securities (1)	1		1

Total	Total	$	21	$	28	Total	$	3	$	50

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

~~(6)~~

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(5) NATURAL GAS AND OIL PROPERTIES

The Company utilizes the full cost method of accounting for costs related to the development, exploration and acquisition of natural gas and oil properties. Under this method, all such costs (productive and nonproductive), including salaries, benefits and other internal costs directly attributable to these activities, are capitalized on a country-by-country basis and amortized over the estimated lives of the properties using the units-of-production method. These capitalized costs are subject to a ceiling test that limits such pooled costs, net of applicable deferred taxes, to the aggregate of the present value of future net revenues attributable to proved natural gas, oil and NGL reserves discounted at 10% (standardized measure). Any costs in excess of the ceiling are written off as a non-cash expense. The expense may not be reversed in future periods, even though higher natural gas, oil and NGL prices may subsequently increase the ceiling. Companies using the full cost method are required to use the average quoted price from the first day of each month from the previous 12 months, including the impact of derivatives designated for hedge accounting, to calculate the ceiling value of their reserves. The Company had no hedge positions that were designated for hedge accounting as of March 31, ~~2022.~~2023. Prices used to calculate the ceiling value of reserves were as follows:


		March 31, 2022		March 31, 2021			March 31, 2023		March 31, 2022
Natural gas (per MMBtu)	Natural gas (per MMBtu)	$	4.09	$	2.16	Natural gas (per MMBtu)	$	5.96	$	4.09
Oil (per Bbl)	Oil (per Bbl)	$	75.39	$	40.01	Oil (per Bbl)	$	90.97	$	75.39
NGLs (per Bbl)	NGLs (per Bbl)	$	32.75	$	13.57	NGLs (per Bbl)	$	30.69	$	32.75

Using the average quoted prices above, adjusted for market differentials, the Company’s net book value of its United States natural gas and oil properties did not exceed the ceiling amount at March 31, ~~2022.~~2023. Decreases in market prices as well as changes in production rates, levels of reserves, evaluation of costs excluded from amortization, future development costs and production costs could result in future non-cash ceiling test impairments to the Company’s natural gas and oil properties.

~~Table of Contents~~

~~The Company did not record an impairment expense related to its other non-full cost pool gas and oil properties during the three months ended March 31, 2022 or 2021.~~

~~(7)~~(6) EARNINGS PER SHARE

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

On December 31, 2021, the Company issued 99,337,748 shares of its common stock in conjunction with the GEPH Merger. These shares of Southwestern common stock had an aggregate dollar value equal to approximately $463 million, based on the closing price of $4.66 per share of Southwestern common stock on the NYSE on December 31, 2021. See ~~Note 2~~ ~~for additional details on the GEPH Merger.~~

In September 2021, the Company issued 337,827,171 shares of its common stock in conjunction with the Indigo Merger. These shares of Southwestern common stock had an aggregate dollar value equal to approximately $1,588 million, based on the closing price of $4.70 per share of Southwestern common stock on the NYSE on September 1, 2021. See ~~Note 2~~ ~~for additional details on the Indigo Merger.~~

The following table presents the computation of earnings per share for the three months ended March 31, ~~2022~~2023 and ~~2021:~~2022:


		For the three months ended March 31,				For the three months ended March 31,
(in millions, except share/per share amounts)	(in millions, except share/per share amounts)	2022		2021			(in millions, except share/per share amounts)	2023		2022
Net income (loss)	Net income (loss)	$	(2,675)	$	80		Net income (loss)	$	1,939	$	(2,675)

Number of common shares:	Number of common shares:						Number of common shares:
Weighted average outstanding	Weighted average outstanding	1,114,610,964		675,385,145			Weighted average outstanding	1,100,278,261		1,114,610,964
Issued upon assumed exercise of outstanding stock options	Issued upon assumed exercise of outstanding stock options	—		—			Issued upon assumed exercise of outstanding stock options	—		—
Effect of issuance of non-vested restricted common stock	Effect of issuance of non-vested restricted common stock	—		870,541			Effect of issuance of non-vested restricted common stock	790,131		—
Effect of issuance of non-vested restricted units	Effect of issuance of non-vested restricted units	—		804,944			Effect of issuance of non-vested restricted units	1,328,244		—
Effect of issuance of non-vested performance units	Effect of issuance of non-vested performance units	—		2,807,195			Effect of issuance of non-vested performance units	—		—
Weighted average and potential dilutive outstanding	Weighted average and potential dilutive outstanding	1,114,610,964		679,867,825			Weighted average and potential dilutive outstanding	1,102,396,636		1,114,610,964

Earnings (loss) per common share	Earnings (loss) per common share						Earnings (loss) per common share
Basic	Basic	$	(2.40)	$	0.12		Basic	$	1.76	$	(2.40)
Diluted	Diluted	$	(2.40)	$	0.12		Diluted	$	1.76	$	(2.40)

Table of Contents

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, ~~2022~~2023 and ~~2021,~~2022, as they would have had an antidilutive effect:


		For the three months ended March 31,		For the three months ended March 31,
		2022	2021			2023	2022
Unexercised stock options	Unexercised stock options	2,948,488	3,795,091		Unexercised stock options	866,318	2,948,488
Stock-based compensation		1,436,920	—
Restricted stock units		2,528,005	3,987,291
Unvested restricted common stock					Unvested restricted common stock	—	1,436,920
Restricted units					Restricted units	1,914,812	2,528,005
Performance units	Performance units	1,917,579	—		Performance units	326,088	1,917,579
Total	Total	8,830,992	7,782,382		Total	3,107,218	8,830,992

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~~(8)~~(7) DERIVATIVES AND RISK MANAGEMENT

The Company is exposed to volatility in market prices and basis differentials for natural gas, oil and NGLs which impacts the predictability of its cash flows related to the sale of those commodities. These risks are managed by the Company’s use of certain derivative financial instruments. As of March 31, 2023 and March 31, 2022, the Company’s derivative financial instruments consisted of fixed price swaps, two-way costless collars, three-way costless collars, basis swaps, ~~call~~ options ~~swaptions~~(calls and puts), index swaps and interest rate swaps. A description of the Company’s derivative financial instruments is provided below:


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

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

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

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



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

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

1714

Table of Contents


~~Swaptions~~			Instruments that refer to an option to enter into a fixed price swap. In exchange for an option premium, the purchaser gains the right but not the obligation to enter a specified swap agreement with the issuer for specified future dates. If the Company sells a swaption, the counterparty has the right to enter into a fixed price swap wherein the Company receives a fixed price for the contract and pays a floating market price to the counterparty. If the Company purchases a swaption, the Company has the right to enter into a fixed price swap wherein the Company receives a floating market price for the contract and pays a fixed price to the counterparty.


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

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

The following tables provide information about the Company’s financial instruments that are sensitive to changes in commodity prices and that are used to protect the Company’s exposure. None of the financial instruments below are designated for hedge accounting treatment. The tables present the notional amount, the weighted average contract prices and the fair value by expected maturity dates as of March 31, ~~2022:~~2023:


Financial Protection on Production	Financial Protection on Production														Financial Protection on Production
			Weighted Average Price per MMBtu														Weighted Average Price per MMBtu
		Volume (Bcf)	Swaps		Sold Puts		Purchased Puts		Sold Calls		Basis Differential		Fair Value at March 31, 2022 (in millions)			Volume (Bcf)	Swaps		Sold Puts		Purchased Puts		Sold Calls		Basis Differential		Fair Value at March 31, 2023 (in millions)
Natural Gas	Natural Gas														Natural Gas
2022
Fixed price swaps		627	$	3.04	$	—	$	—	$	—	$	—	$	(1,672)
Two-way costless collars		78	—		—		2.53		2.92		—		(216)
Three-way costless collars		277	—		2.03		2.48		2.88		—		(784)
Total		982											$	(2,672)
2023	2023														2023
Fixed price swaps	Fixed price swaps	504	$	3.08	$	—	$	—	$	—	$	—	$	(675)	Fixed price swaps	453	$	3.15	$	—	$	—	$	—	$	—	$	169
Two-way costless collars	Two-way costless collars	219	—		—		3.03		3.55		—		(217)		Two-way costless collars	116	—		—		2.86		3.21		—		30
Three-way costless collars	Three-way costless collars	215	—		2.09		2.54		3.00		—		(355)		Three-way costless collars	145	—		2.07		2.49		2.91		—		(31)
Total	Total	938											$	(1,247)	Total	714											$	168
2024	2024														2024
Fixed price swaps	Fixed price swaps	224	$	2.96	$	—	$	—	$	—	$	—	$	(174)	Fixed price swaps	528	$	3.54	$	—	$	—	$	—	$	—	$	(42)
Two-way costless collars	Two-way costless collars	44	—		—		3.07		3.53		—		(19)		Two-way costless collars	44	—		—		3.07		3.53		—		(15)
Three-way costless collars	Three-way costless collars	11	—		2.25		2.80		3.54		—		(12)		Three-way costless collars	11	—		2.25		2.80		3.54		—		(8)
Total	Total	279											$	(205)	Total	583											$	(65)
2025															2025

Three-way costless collars															Three-way costless collars	99	$	—	$	2.50	$	3.75	$	5.69	$	—	$	(8)

Basis Swaps	Basis Swaps														Basis Swaps
2022		277	$	—	$	—	$	—	$	—	$	(0.53)	$	72
2023	2023	250	—		—		—		—		(0.47)		20		2023	220	$	—	$	—	$	—	$	—	$	(0.63)	$	(26)
2024	2024	46	—		—		—		—		(0.71)		9		2024	46	—		—		—		—		(0.71)		5
2025	2025	9	—		—		—		—		(0.64)		3		2025	9	—		—		—		—		(0.64)		2

Total	Total	582											$	104	Total	275											$	(19)

1815

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Volume
(MBbls)
Weighted Average Strike Price per Bbl
Fair Value at
March 31, 2022
(in millions)
Swaps Sold Puts Purchased Puts Sold Calls
Oil
2022
Fixed price swaps 2,376 $ 53.32 $ — $ — $ — $ (94)
Three-way costless collars 1,037 — 39.83 50.17 57.01 (38)
Total 3,413 $ (132)
2023
Fixed price swaps 846 $ 55.98 $ — $ — $ — $ (23)
Three-way costless collars 1,268 — 33.97 45.51 56.12 (36)
Total 2,114 $ (59)
2024
Fixed price swaps 603 $ 68.68 $ — $ — $ — $ (5)
Ethane
2022
Fixed price swaps 4,142 $ 11.27 $ — $ — $ — $ (26)
2023
Fixed price swaps 1,308 $ 11.91 $ — $ — $ — $ (3)
Propane
2022
Fixed price swaps 4,643 $ 31.09 $ — $ — $ — $ (118)
Three-way costless collars 230 — 16.80 21.00 31.92 (6)
Total 4,873 $ (124)
2023
Fixed price swaps 1,066 $ 37.15 $ — $ — $ — $ (8)
Normal Butane
2022
Fixed price swaps 1,388 $ 36.22 $ — $ — $ — $ (43)
2023
Fixed price swaps 329 $ 40.64 $ — $ — $ — $ (3)
Natural Gasoline
2022
Fixed price swaps 1,497 $ 55.78 $ — $ — $ — $ (57)
2023
Fixed price swaps 359 $ 66.00 $ — $ — $ — $ (5)

Other Derivative Contracts
Volume
(Bcf)
Weighted Average Strike Price per MMBtu
Fair Value at
March 31, 2022
(in millions)
Call Options – Natural Gas (Net)
2022 63 $ 3.01 $ (171)
2023 46 2.94 (74)
2024 9 3.00 (13)
Total 118 $ (258)


	Volume (MBbls)	Weighted Average Strike Price per Bbl								Fair Value at March 31, 2023 (in millions)
		Swaps		Sold Puts		Purchased Puts		Sold Calls
Oil
2023
Fixed price swaps	999	$	62.61	$	—	$	—	$	—	$	(11)
Two-way costless collars	294	—		—		70.00		80.58		—
Three-way costless collars	926	—		34.09		45.68		56.07		(18)
Total	2,219									$	(29)
2024
Fixed price swaps	1,571	$	71.06	$	—	$	—	$	—	$	—
Two-way costless collars	146	—		—		70.00		78.25		—
Total	1,717									$	—
2025
Fixed price swaps	41	$	77.66	$	—	$	—	$	—	$	—





Ethane
2023
Fixed price swaps	5,570	$	11.51	$	—	$	—	$	—	$	12


2024
Fixed price swaps	1,305	$	10.81	$	—	$	—	$	—	$	1







Propane
2023
Fixed price swaps	3,592	$	36.31	$	—	$	—	$	—	$	9


2024
Fixed price swaps	1,094	$	35.70	$	—	$	—	$	—	$	2





Normal Butane
2023
Fixed price swaps	591	$	40.96	$	—	$	—	$	—	$	1
2024
Fixed price swaps	329	$	40.74	$	—	$	—	$	—	$	1

Natural Gasoline
2023
Fixed price swaps	512	$	63.74	$	—	$	—	$	—	$	—
2024
Fixed price swaps	329	$	64.37	$	—	$	—	$	—	$	1

1916

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Volume
(Bcf)
Weighted Average Strike Price per MMBtu
Fair Value at
March 31, 2022
(in millions)
Swaps Basis Differential
Storage (1)

2022
Purchased fixed price swaps — $ 2.14 $ — $ 1

~~(1)The Company has entered into certain derivatives to protect the value of volumes of natural gas injected into a storage facility that will be withdrawn and sold at a later date.~~


Other Derivative Contracts
	Volume (Bcf)	Weighted Average Strike Price per MMBtu		Fair Value at March 31, 2023 (in millions)





Call Options – Natural Gas (Net)
2023	36	$	2.95	$	(16)
2024	9	3.00		(11)



Total	45			$	(27)





	Volume (MBbls)	Weighted Average Strike Price per Bbl		Fair Value at March 31, 2023 (in millions)
Put Options – Oil (Net)
2023	127	$	73.50	$	—

At March 31, ~~2022,~~2023, the net fair value of the Company’s financial instruments was a ~~$4,734~~$46 million ~~liability,~~asset, which included net reduction of the ~~liability~~asset of $8$1 million related to non-performance risk. See Note 10 9 for additional details regarding the Company’s fair value measurements of its derivatives position.

As of March 31, ~~2022,~~2023, the Company had no positions designated for hedge accounting treatment. Gains and losses on derivatives that are not designated for hedge accounting treatment, or do not meet hedge accounting requirements, are recorded as a component of gain (loss) on derivatives on the consolidated statements of operations. Accordingly, the gain (loss) on derivatives component of the statement of operations reflects the gains and losses on both settled and unsettled derivatives. Only the settled gains and losses are included in the Company’s realized commodity price calculations.

The balance sheet classification of the assets and liabilities related to derivative financial instruments are summarized below as of March 31, ~~2022~~2023 and December 31, ~~2021:~~2022:

Derivative Assets
Fair Value
(in millions) Balance Sheet Classification March 31, 2022 December 31, 2021
Derivatives not designated as hedging instruments:
Fixed price swaps – natural gas Derivative assets $ — $ 79
Fixed price swaps – ethane Derivative assets — 2
Fixed price swaps – propane Derivative assets — 2
Fixed price swaps – normal butane Derivative assets — 1
Two-way costless collars – natural gas Derivative assets 10 9
Three-way costless collars – natural gas Derivative assets 9 12
Three-way costless collars – oil Derivative assets 1 1
Basis swaps – natural gas Derivative assets 82 77
Purchased fixed price swaps – natural gas storage Derivative assets 1 —
Fixed price swaps – natural gas Other long-term assets — 64
Two-way costless collars – natural gas Other long-term assets 44 100
Three-way costless collars – natural gas Other long-term assets 12 37
Three-way costless collars – oil Other long-term assets 1 3
Basis swaps – natural gas Other long-term assets 70 22
Interest rate swaps Other long-term assets — 2
Total derivative assets $ 230 $ 411


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



Fixed price swaps – natural gas	Derivative assets	$	227	$	—
Fixed price swaps – oil	Derivative assets	1		—
Fixed price swaps – ethane	Derivative assets	12		4
Fixed price swaps – propane	Derivative assets	11		9
Fixed price swaps – normal butane	Derivative assets	1		1
Fixed price swaps – natural gasoline	Derivative assets	1		1
Two-way costless collars – natural gas	Derivative assets	137		47
Two-way costless collars – oil	Derivative assets	2		—

Three-way costless collars – natural gas	Derivative assets	51		18
Three-way costless collars – oil	Derivative assets	—		1
Basis swaps – natural gas	Derivative assets	15		64
Put options – natural gas	Derivative assets	6		—



Fixed price swaps – natural gas	Other long-term assets	105		28
Fixed price swaps – oil	Other long-term assets	2		1
Fixed price swaps – ethane	Other long-term assets	1		1
Fixed price swaps – propane	Other long-term assets	1		1
Fixed price swaps – normal butane	Other long-term assets	1		—
Fixed price swaps – natural gasoline	Other long-term assets	1		—
Two-way costless collars – natural gas	Other long-term assets	16		18

Two-way costless collars – oil	Other long-term assets	1		—
Three-way costless collars – natural gas	Other long-term assets	66		3

Basis swaps – natural gas	Other long-term assets	9		17

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

Total derivative assets		$	667	$	218

2017

Table of Contents


Derivative Liabilities	Derivative Liabilities						Derivative Liabilities
			Fair Value						Fair Value
(in millions)	(in millions)	Balance Sheet Classification	March 31, 2022		December 31, 2021		(in millions)	Balance Sheet Classification	March 31, 2023		December 31, 2022
Derivatives not designated as hedging instruments:	Derivatives not designated as hedging instruments:						Derivatives not designated as hedging instruments:

Fixed price swaps – natural gas storage		Derivative liabilities	$	—	$	1

Fixed price swaps – natural gas	Fixed price swaps – natural gas	Derivative liabilities	1,999		565		Fixed price swaps – natural gas	Derivative liabilities	$	97	$	581
Fixed price swaps – oil	Fixed price swaps – oil	Derivative liabilities	101		60		Fixed price swaps – oil	Derivative liabilities	14		20
Fixed price swaps – ethane	Fixed price swaps – ethane	Derivative liabilities	28		10		Fixed price swaps – ethane	Derivative liabilities	—		1
Fixed price swaps – propane	Fixed price swaps – propane	Derivative liabilities	122		78		Fixed price swaps – propane	Derivative liabilities	1		—
Fixed price swaps – normal butane		Derivative liabilities	44		27

Fixed price swaps – natural gasoline	Fixed price swaps – natural gasoline	Derivative liabilities	59		33		Fixed price swaps – natural gasoline	Derivative liabilities	1		1
Two-way costless collars – natural gas	Two-way costless collars – natural gas	Derivative liabilities	316		104		Two-way costless collars – natural gas	Derivative liabilities	112		235
Two-way costless collars – oil							Two-way costless collars – oil	Derivative liabilities	2		—

Two-way costless collars – ethane		Derivative liabilities	—		1
Three-way costless collars – natural gas	Three-way costless collars – natural gas	Derivative liabilities	977		298		Three-way costless collars – natural gas	Derivative liabilities	91		311
Three-way costless collars – oil	Three-way costless collars – oil	Derivative liabilities	49		24		Three-way costless collars – oil	Derivative liabilities	18		31
Three-way costless collars – propane		Derivative liabilities	6		4

Basis swaps – natural gas	Basis swaps – natural gas	Derivative liabilities	43		9		Basis swaps – natural gas	Derivative liabilities	41		69
Call options – natural gas	Call options – natural gas	Derivative liabilities	201		67		Call options – natural gas	Derivative liabilities	27		70

Put options – natural gas							Put options – natural gas	Derivative liabilities	6		—

Fixed price swaps – natural gas	Fixed price swaps – natural gas	Long-term derivative liabilities	522		246		Fixed price swaps – natural gas	Long-term derivative liabilities	108		281
Fixed price swaps – oil	Fixed price swaps – oil	Long-term derivative liabilities	21		9		Fixed price swaps – oil	Long-term derivative liabilities	—		4
Fixed price swaps – ethane		Long-term derivative liabilities	1		—
Fixed price swaps – propane		Long-term derivative liabilities	4		1
Fixed price swaps – normal butane		Long-term derivative liabilities	2		—
Fixed price swaps – natural gasoline		Long-term derivative liabilities	3		1

Two-way costless collars – natural gas	Two-way costless collars – natural gas	Long-term derivative liabilities	190		115		Two-way costless collars – natural gas	Long-term derivative liabilities	26		56
Two-way costless collars – oil							Two-way costless collars – oil	Long-term derivative liabilities	1		—
Three-way costless collars – natural gas							Three-way costless collars – natural gas	Long-term derivative liabilities	73		20

Three-way costless collars – natural gas		Long-term derivative liabilities	195		178
Three-way costless collars – oil		Long-term derivative liabilities	27		21

Basis swap – natural gas	Basis swap – natural gas	Long-term derivative liabilities	5		22		Basis swap – natural gas	Long-term derivative liabilities	2		1
Call options – natural gas	Call options – natural gas	Long-term derivative liabilities	57		42		Call options – natural gas	Long-term derivative liabilities	—		18

Total derivative liabilities	Total derivative liabilities		$	4,972	$	1,916	Total derivative liabilities		$	620	$	1,699


Net Derivative Position	Net Derivative Position					Net Derivative Position
		March 31, 2022		December 31, 2021			March 31, 2023		December 31, 2022
(in millions)	(in millions)					(in millions)
Net current derivative liabilities		$	(3,842)	$	(1,098)
Net current derivative asset (liability)						Net current derivative asset (liability)	$	54	$	(1,174)
Net long-term derivative liabilities	Net long-term derivative liabilities	(900)		(407)		Net long-term derivative liabilities	(7)		(307)
Non-performance risk adjustment	Non-performance risk adjustment	8		3		Non-performance risk adjustment	(1)		3
Net total derivative liabilities		$	(4,734)	$	(1,502)
Net total derivative asset (liability)						Net total derivative asset (liability)	$	46	$	(1,478)

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The following tables summarize the before-tax effect of the Company’s derivative instruments on the consolidated statements of operations for the three months ended March 31, ~~2022~~2023 and ~~2021:~~2022:

Unsettled Gain (Loss) on Derivatives Recognized in Earnings
Consolidated Statement of Operations Classification of Gain (Loss) on Derivatives, Unsettled For the three months ended March 31,
Derivative Instrument 2022 2021
(in millions)
Fixed price swaps – natural gas Gain (Loss) on Derivatives $ (1,853) $ (22)
Fixed price swaps – oil Gain (Loss) on Derivatives (53) (40)
Fixed price swaps – ethane Gain (Loss) on Derivatives (21) (2)
Fixed price swaps – propane Gain (Loss) on Derivatives (49) (45)
Fixed price swaps – normal butane Gain (Loss) on Derivatives (20) (15)
Fixed price swaps – natural gasoline Gain (Loss) on Derivatives (28) (20)
Two-way costless collars – natural gas Gain (Loss) on Derivatives (342) (12)
Two-way costless collars – oil Gain (Loss) on Derivatives — (1)
Two-way costless collars – ethane Gain (Loss) on Derivatives 1 —
Three-way costless collars – natural gas Gain (Loss) on Derivatives (724) —
Three-way costless collars – oil Gain (Loss) on Derivatives (33) (18)
Three-way costless collars – propane Gain (Loss) on Derivatives (2) (1)
Basis swaps – natural gas Gain (Loss) on Derivatives 36 3
Call options – natural gas Gain (Loss) on Derivatives (149) 3
Call options – oil Gain (Loss) on Derivatives — (1)
Swaptions – natural gas Gain (Loss) on Derivatives — 1
Purchased fixed price swap – natural gas storage Gain (Loss) on Derivatives 1 —
Fixed price swap – natural gas storage Gain (Loss) on Derivatives 1 —
Interest rate swaps Gain (Loss) on Derivatives (2) 1
Total loss on unsettled derivatives $ (3,237) $ (169)
Settled Gain (Loss) on Derivatives Recognized in Earnings (1)
Consolidated Statement of Operations Classification of Gain (Loss) on Derivatives, Settled For the three months ended March 31,
Derivative Instrument 2022 2021
(in millions)
Fixed price swaps – natural gas Gain (Loss) on Derivatives $ (297) $ 5
Fixed price swaps – oil Gain (Loss) on Derivatives (33) (17)
Fixed price swaps – ethane Gain (Loss) on Derivatives (8) (4)
Fixed price swaps – propane Gain (Loss) on Derivatives (41) (30)
Fixed price swaps – normal butane Gain (Loss) on Derivatives (14) (7)
Fixed price swaps – natural gasoline Gain (Loss) on Derivatives (19) (9)
Two-way costless collars – natural gas Gain (Loss) on Derivatives (104) 2
Two-way costless collars – oil Gain (Loss) on Derivatives — (1)
Two-way costless collars – ethane Gain (Loss) on Derivatives (1) —
Three-way costless collars – natural gas Gain (Loss) on Derivatives (121) 1
Three-way costless collars – oil Gain (Loss) on Derivatives (13) (1)
Three-way costless collars – propane Gain (Loss) on Derivatives (2) —
Basis swaps – natural gas Gain (Loss) on Derivatives 1 41
Index swaps – natural gas Gain (Loss) on Derivatives (1) —
Call options – natural gas Gain (Loss) on Derivatives (39) —
Put options – natural gas Gain (Loss) on Derivatives — (2) (2)
Fixed price swaps – natural gas storage Gain (Loss) on Derivatives (3) —
Total loss on settled derivatives $ (695) $ (22)


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		2023			2022

		(in millions)

Fixed price swaps – natural gas	Gain (Loss) on Derivatives	$	961		$	(1,853)
Fixed price swaps – oil	Gain (Loss) on Derivatives	12			(53)
Fixed price swaps – ethane	Gain (Loss) on Derivatives	9			(21)
Fixed price swaps – propane	Gain (Loss) on Derivatives	1			(49)
Fixed price swaps – normal butane	Gain (Loss) on Derivatives	1			(20)
Fixed price swaps – natural gasoline	Gain (Loss) on Derivatives	1			(28)
Two-way costless collars – natural gas	Gain (Loss) on Derivatives	241			(342)

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

Three-way costless collars – natural gas	Gain (Loss) on Derivatives	263			(724)
Three-way costless collars – oil	Gain (Loss) on Derivatives	12			(33)
Three-way costless collars – propane	Gain (Loss) on Derivatives	—			(2)
Basis swaps – natural gas	Gain (Loss) on Derivatives	(30)			36
Call options – natural gas	Gain (Loss) on Derivatives	61			(149)

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

Purchased fixed price swap – natural gas storage	Gain (Loss) on Derivatives	—			1
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		$	1,528		$	(3,237)

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

	Consolidated Statement of Operations Classification of Gain (Loss) on Derivatives, Settled	For the three months ended March 31,
Derivative Instrument		2023			2022

		(in millions)

Fixed price swaps – natural gas	Gain (Loss) on Derivatives	$	(45)		$	(297)
Fixed price swaps – oil	Gain (Loss) on Derivatives	(4)			(33)
Fixed price swaps – ethane	Gain (Loss) on Derivatives	1			(8)
Fixed price swaps – propane	Gain (Loss) on Derivatives	1			(41)
Fixed price swaps – normal butane	Gain (Loss) on Derivatives	—			(14)
Fixed price swaps – natural gasoline	Gain (Loss) on Derivatives	—			(19)
Two-way costless collars – natural gas	Gain (Loss) on Derivatives	—			(104)

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

Three-way costless collars – natural gas	Gain (Loss) on Derivatives	(33)			(121)
Three-way costless collars – oil	Gain (Loss) on Derivatives	(7)			(13)
Three-way costless collars – propane	Gain (Loss) on Derivatives	—			(2)
Basis swaps – natural gas	Gain (Loss) on Derivatives	(29)			1
Index swaps – natural gas	Gain (Loss) on Derivatives	—			(1)
Call options – natural gas	Gain (Loss) on Derivatives	(7)			(39)



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

Total loss on settled derivatives		$	(123)		$	(695)

Total gain (loss) on derivatives		$	1,401	(1)	$	(3,927)

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

~~(2)Includes $2~~ Total gain (loss) on derivatives includes non-performance risk adjustments of $4 million in ~~amortization of premiums paid related to certain natural gas put options~~losses and $5 million in gains for ~~the~~ three months ended March 31, ~~2021, which is included in gain (loss) on derivatives on the consolidated statements of operations.~~2023 and March 31, 2022, respectively.

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Total Gain (Loss) on Derivatives Recognized in Earnings	Total Gain (Loss) on Derivatives Recognized in Earnings						Total Gain (Loss) on Derivatives Recognized in Earnings
		For the three months ended March 31,						For the three months ended March 31,
		2022		2021					2023		2022

		(in millions)				(in millions)
Total loss on unsettled derivatives		$	(3,237)	$	(169)
Total gain (loss) on unsettled derivatives							Total gain (loss) on unsettled derivatives		$	1,528	$	(3,237)
Total loss on settled derivatives	Total loss on settled derivatives	(695)		(22)			Total loss on settled derivatives		(123)		(695)
Non-performance risk adjustment	Non-performance risk adjustment	5		—			Non-performance risk adjustment		(4)		5
Total loss on derivatives		$	(3,927)	$	(191)
Total gain (loss) on derivatives							Total gain (loss) on derivatives		$	1,401	$	(3,927)

~~(9)~~(8) RECLASSIFICATIONS FROM ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)

The following tables detail the components of accumulated other comprehensive income ~~and the related tax effects~~ for the three months ended March 31, ~~2022:~~2023:


(in millions)	(in millions)	Pension and Other Postretirement		Foreign Currency		Total		(in millions)	Pension and Other Postretirement		Foreign Currency		Total
Beginning balance December 31, 2021		$	(11)	$	(14)	$	(25)
Beginning balance December 31, 2022								Beginning balance December 31, 2022	$	20	$	(14)	$	6
Other comprehensive income before reclassifications	Other comprehensive income before reclassifications	—		—		—		Other comprehensive income before reclassifications	1		—		1
Amounts reclassified from other comprehensive income (1)	Amounts reclassified from other comprehensive income (1)	—		—		—		Amounts reclassified from other comprehensive income (1)	(16)		—		(16)
Net current-period other comprehensive income		—		—		—
Ending balance March 31, 2022		$	(11)	$	(14)	$	(25)
Net current-period other comprehensive loss								Net current-period other comprehensive loss	(15)		—		(15)
Ending balance March 31, 2023								Ending balance March 31, 2023	$	5	$	(14)	$	(9)

(1)~~For~~Includes a $2 million actuarial loss and a $14 million net tax loss attributable to the ~~three months endedMarch 31, 2022, the amounts reclassified from accumulated other comprehensive income was less than $1 million. See~~ ~~Note 14~~ ~~for additional details regarding the Company’s~~ pension ~~and other postretirement benefit plans.~~plan termination.

~~(10)~~(9) FAIR VALUE MEASUREMENTS

Assets and liabilities measured at fair value on a recurring basis

The carrying amounts and estimated fair values of the Company’s financial instruments as of March 31, ~~2022~~2023 and December 31, ~~2021~~2022 were as follows:


		March 31, 2022				December 31, 2021					March 31, 2023				December 31, 2022
(in millions)	(in millions)	Carrying Amount		Fair Value		Carrying Amount		Fair Value		(in millions)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Cash and cash equivalents	Cash and cash equivalents	$	21	$	21	$	28	$	28	Cash and cash equivalents	$	3	$	3	$	50	$	50
2018 revolving credit facility due April 2024		174		174		460		460
Term Loan B due 2027		549		549		550		550
2022 revolving credit facility due April 2027										2022 revolving credit facility due April 2027	210		210		250		250

Senior notes (1)	Senior notes (1)	4,209		4,318		4,430		4,745		Senior notes (1)	3,743		3,524		4,164		3,847
Derivative instruments, net	Derivative instruments, net	(4,734)		(4,734)		(1,502)		(1,502)		Derivative instruments, net	46		46		(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 ~~values~~value of the borrowings under ~~both~~ the Company’s ~~2018~~2022 credit facility ~~(to~~(as defined in Note 10 below), to the extent ~~utilized) and Term Loan~~utilized, approximates fair value because the interest

~~Table of Contents~~

rates are variable and reflective of market rates. The Company considers the fair ~~values~~value of its ~~2018~~2022 credit facility ~~and Term Loan~~ to be a Level 1 measurement on the fair value hierarchy.

Table of Contents

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, 2023 and a net liability as of December 31, 2022. As of March 31, ~~2022~~2023 and December 31, ~~2021,~~2022, the impact of the non-performance risk on the fair value of the Company’s net derivative ~~liability~~ position ~~was~~resulted in a reduction to the net asset of $1 million and a reduction to the net liability of ~~$8 million and~~ $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 March 31, ~~2022~~2023 and December 31, ~~2021~~2022 are based on (i) the contracted notional amounts, (ii) active market-quoted ~~London Interbank Offered Rate (“LIBOR”)~~ yield curves and (iii) the applicable credit-adjusted risk-free rate yield curve. The Company had no interest rate swaps as of March 31, 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. ~~Swaptions are valued using a variant of the Black-Scholes model referred to as the Black Swaption model, which uses its own separate volatility inputs.~~

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

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


		March 31, 2022									March 31, 2023
		Fair Value Measurements Using:									Fair Value Measurements Using:
(in millions)	(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		(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	Assets									Assets

Fixed price swaps										Fixed price swaps	$	—	$	364	$	—	$	364
Two-way costless collars	Two-way costless collars	$	—	$	54	$	—	$	54	Two-way costless collars	—		156		—		156
Three-way costless collars	Three-way costless collars	—		23		—		23		Three-way costless collars	—		117		—		117
Basis swaps	Basis swaps	—		152		—		152		Basis swaps	—		24		—		24

Purchased fixed price swaps – storage		—		1		—		1
Put options										Put options	—		6		—		6

Liabilities	Liabilities									Liabilities

Fixed price swaps	Fixed price swaps	—		(2,906)		—		(2,906)		Fixed price swaps	—		(221)		—		(221)
Two-way costless collars	Two-way costless collars	—		(506)		—		(506)		Two-way costless collars	—		(141)		—		(141)
Three-way costless collars	Three-way costless collars	—		(1,254)		—		(1,254)		Three-way costless collars	—		(182)		—		(182)
Basis swaps	Basis swaps	—		(48)		—		(48)		Basis swaps	—		(43)		—		(43)
Call options	Call options	—		(258)		—		(258)		Call options	—		(27)		—		(27)

Put options										Put options	—		(6)		—		(6)

Total (1)	Total (1)	$	—	$	(4,742)	$	—	$	(4,742)	Total (1)	$	—	$	47	$	—	$	47

(1)Excludes a net reduction to the ~~liability~~asset fair value of $8$1 million related to estimated non-performance risk.

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		December 31, 2021									December 31, 2022
		Fair Value Measurements Using:									Fair Value Measurements Using:
(in millions)	(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		(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	Assets									Assets

Fixed price swaps	Fixed price swaps	$	—	$	148	$	—	$	148	Fixed price swaps	$	—	$	46	$	—	$	46
Two-way costless collars	Two-way costless collars	—		109		—		109		Two-way costless collars	—		65		—		65
Three-way costless collars	Three-way costless collars	—		53		—		53		Three-way costless collars	—		22		—		22
Basis swaps	Basis swaps	—		99		—		99		Basis swaps	—		81		—		81
Interest rate swaps		—		2		—		2

Purchase Put - Natural Gas										Purchase Put - Natural Gas	—		4		—		4
Liabilities	Liabilities									Liabilities

Fixed price swaps	Fixed price swaps	—		(1,031)		—		(1,031)		Fixed price swaps	—		(888)		—		(888)
Two-way costless collars	Two-way costless collars	—		(220)		—		(220)		Two-way costless collars	—		(291)		—		(291)
Three-way costless collars	Three-way costless collars	—		(525)		—		(525)		Three-way costless collars	—		(362)		—		(362)
Basis swaps	Basis swaps	—		(31)		—		(31)		Basis swaps	—		(70)		—		(70)
Call options	Call options	—		(109)		—		(109)		Call options	—		(88)		—		(88)

Total (1)	Total (1)	$	—	$	(1,505)	$	—	$	(1,505)	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 141 3 for a discussion of the fair value measurement of the Company’s pension plan assets.

~~Assets and liabilities measured at fair value on a non-recurring basis~~

~~The Company completed the Indigo Merger and the GEPH Merger on September 1, 2021 and December 31, 2021, respectively. See~~ ~~Note 2~~ ~~for a discussion of the fair value measurement of assets acquired and liabilities assumed.~~

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~~(11)~~(10) DEBT

The components of debt as of March 31, ~~2022~~2023 and December 31, ~~2021~~2022 consisted of the following:


		March 31, 2022											March 31, 2023
(in millions)	(in millions)	Debt Instrument			Unamortized Issuance Expense			Unamortized Debt Premium/Discount		Total		(in millions)	Debt Instrument		Unamortized Issuance Expense			Unamortized Debt Premium/Discount		Total
Current portion of long-term debt:
Variable rate (3.3% at March 31, 2022) Term Loan B due June 2027		$	5	(1)	$	—		$	—	$	5
Total current portion of long-term debt		$	5		$	—		$	—	$	5

Long-term debt:	Long-term debt:											Long-term debt:
Variable rate (2.10% at March 31, 2022) 2018 revolving credit facility due April 2024		$	174		$	—	(2)	$	—	$	174
Variable rate (6.69% at March 31, 2023) 2022 revolving credit facility due April 2027												Variable rate (6.69% at March 31, 2023) 2022 revolving credit facility due April 2027	$	210	$	—	(1)	$	—	$	210
4.95% Senior Notes due January 2025 ~~(3)~~(2)	4.95% Senior Notes due January 2025 ~~(3)~~(2)	389			(1)			—		388		4.95% Senior Notes due January 2025 ~~(3)~~(2)	389		(1)			—		388
Variable rate (3.3% at March 31, 2022) Term Loan B due June 2027		544			(7)			(1)		536

7.75% Senior Notes due October 2027		425			(4)			—		421

8.375% Senior Notes due September 2028	8.375% Senior Notes due September 2028	345			(5)			—		340		8.375% Senior Notes due September 2028	304		(3)			—		301
5.375% Senior Notes due February 2029	5.375% Senior Notes due February 2029	700			(6)			24		718		5.375% Senior Notes due February 2029	700		(5)			21		716
5.375% Senior Notes due September 2030		1,200			(16)			—		1,184
5.375% Senior Notes due March 2030												5.375% Senior Notes due March 2030	1,200		(15)			—		1,185
4.75% Senior Notes due February 2032	4.75% Senior Notes due February 2032	1,150			(16)			—		1,134		4.75% Senior Notes due February 2032	1,150		(15)			—		1,135
Total long-term debt	Total long-term debt	$	4,927		$	(55)		$	23	$	4,895	Total long-term debt	$	3,953	$	(39)		$	21	$	3,935

Total debt	Total debt	$	4,932		$	(55)		$	23	$	4,900	Total debt	$	3,953	$	(39)		$	21	$	3,935

		December 31, 2021											December 31, 2022
(in millions)	(in millions)	Debt Instrument			Unamortized Issuance Expense			Unamortized Debt Premium/Discount		Total		(in millions)	Debt Instrument		Unamortized Issuance Expense			Unamortized Debt Premium/Discount		Total
Current portion of long-term debt:
4.10% Senior Notes due March 2022		$	201		$	—		$	—	$	201
Variable rate (3.0% at December 31, 2021) Term Loan B due June 2027		5		(1)	—			—		5
Total current portion of long-term debt		$	206		$	—		$	—	$	206

Long-term debt:	Long-term debt:											Long-term debt:
Variable rate (2.08% at December 31, 2021) 2018 revolving credit facility, due April 2024		$	460		$	—	(2)	$	—	$	460
Variable rate (6.15% at December 31, 2022) 2022 revolving credit facility, due April 2027												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 ~~(3)~~(2)	4.95% Senior Notes due January 2025 ~~(3)~~(2)	389			(1)			—		388		4.95% Senior Notes due January 2025 ~~(3)~~(2)	389		(1)			—		388
Variable rate (3.0% at December 31, 2021) Term Loan B due June 2027		545			(7)			(1)		537

7.75% Senior Notes due October 2027	7.75% Senior Notes due October 2027	440			(4)			—		436		7.75% Senior Notes due October 2027	421		(3)			—		418
8.375% Senior Notes due September 2028	8.375% Senior Notes due September 2028	350			(5)			—		345		8.375% Senior Notes due September 2028	304		(3)			—		301
5.375% Senior Notes due September 2029		700			(6)			25		719
5.375% Senior Notes due February 2029												5.375% Senior Notes due February 2029	700		(5)			22		717
5.375% Senior Notes due March 2030	5.375% Senior Notes due March 2030	1,200			(17)			—		1,183		5.375% Senior Notes due March 2030	1,200		(16)			—		1,184
4.75% Senior Notes due February 2032	4.75% Senior Notes due February 2032	1,150			(17)			—		1,133		4.75% Senior Notes due February 2032	1,150		(16)			—		1,134
Total long-term debt	Total long-term debt	$	5,234		$	(57)		$	24	$	5,201	Total long-term debt	$	4,414	$	(44)		$	22	$	4,392

Total debt	Total debt	$	5,440		$	(57)		$	24	$	5,407	Total debt	$	4,414	$	(44)		$	22	$	4,392

(1)~~The Term Loan requires quarterly principal repayments of $1.375 million, subject to adjustment for voluntary prepayments, beginning in March 2022.~~

~~(2)~~At March 31, ~~2022~~2023 and December 31, ~~2021,~~2022, unamortized issuance expense of $9$18 million and ~~$10~~$19 million, respectively, associated with the ~~2018~~2022 credit facility (as defined below) was classified as other long-term assets on the consolidated balance sheets.

~~(3)~~(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

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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 March 31, ~~2022 and includes the quarterly Term Loan principal repayments~~2023:


(in millions)
2023	$	—
2024	—
2025	389
2026	—
2027	210
Thereafter	3,354
	$	3,953

Table of ~~$1.375 million, subject to adjustment for voluntary prepayments, beginning in March 2022:~~Contents

(in millions)
2022 $ 4
2023 6
2024 (1)
179
2025 395
2026 5
Thereafter 4,343
$ 4,932

~~(1)As of March 31, 2022, the Company’s 2018 credit facility matures in 2024. In April 2022, the 2018 credit facility was amended and restated resulting in the extension of the maturity date to 2027.~~

Credit Facilities

~~2018~~2022 Credit Facility

InOn April ~~2018,~~8, 2022, the Company entered into ~~a revolving~~an Amended and Restated Credit Agreement that replaces its previous credit facility ~~(the “2018 credit facility”)~~ with a group of banks, that as amended, has a maturity date of April ~~2024. The 2018~~2027 (the “2022 credit facility”). As of March 31, 2023, the 2022 credit facility has an aggregate maximum revolving credit amount and borrowing base of $3.5 billion and ~~in October 2021, the banks participating in the 2018 credit facility reaffirmed the~~ elected ~~borrowing base~~five-year revolving commitments of $2.0 billion (the “Five-Year Tranche”) and ~~aggregate~~elected short-term commitments ~~to be $2.0 billion.~~of $500 million (the “Short-Term 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. ~~The permitted lien provisions in~~On April 5, 2023, the ~~senior notes indentures currently limit liens securing indebtedness to~~Company’s borrowing base was reaffirmed at $3.5 billion and both the ~~greater of~~Five-Year Tranche and Short-Term Tranche were reaffirmed at $2.0 billion and ~~25%~~$500 million, respectively. The Five-Year Tranche and Short-Term Tranche have maturity dates of ~~adjusted consolidated net tangible assets.~~April 8, 2027 and April 30, 2023, respectively.

~~The~~Effective August 4, 2022, the Company ~~may utilize the 2018 credit facility in the form of loans and letters of credit. Loans under the 2018 credit facility are subject~~elected to varying rates of interest based on whether the loan is a Eurodollar loan or an alternate base rate loan. Eurodollar loans bear interest at the Eurodollar rate, which is adjusted LIBOR for such interest period plus the applicable margin (as those terms are defined in the 2018 credit facility documentation). The applicable margin for Eurodollar loans under the 2018 credit facility, as amended, ranges from 1.75% to 2.75% based on the Company’s utilization of the 2018 credit facility. Alternate base rate loans bear interest at the alternate base rate plus the applicable margin. The applicable margin for alternate base rate loans under the 2018 credit facility, as amended, ranges from 0.75% to 1.75% based on the Company’s utilization of the 2018 credit facility.

~~The 2018 credit facility contains customary representations and warranties and covenants including, among others, the following:~~

•~~a prohibition against incurring debt, subject to permitted exceptions;~~

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

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

•~~restrictions on use of proceeds, investments, transactions with affiliates, or change of principal business; and~~

•~~maintenance of the following financial covenants, commencing with the fiscal quarter ended June 30, 2018:~~

1.~~Minimum current ratio of no less than 1.00 to 1.00, whereby current ratio is defined as the Company’s consolidated current assets (including unused~~temporarily increase commitments under the ~~credit agreement, but excluding non-cash derivative assets) to consolidated current liabilities (excluding non-cash derivative obligations and current maturities of long-term debt).~~

2.Maximum total net leverage ratio of no greater than, with respect to each fiscal quarter ending on or after June 30, 2020, 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. For purposes of calculating consolidated EBITDAX, the Company can include the Indigo and GEPH consolidated EBITDAX prior to the respective Mergers for the same twelve-month rolling period. EBITDAX, as defined in the Company’s 2018 credit agreement, excludes the effects of interest expense, depreciation, depletion and amortization, income tax, any non-cash impacts from impairments, certain non-cash hedging activities, stock-

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~~based compensation expense, non-cash gains or losses on asset sales, unamortized issuance cost, unamortized debt discount and certain restructuring costs.~~

~~The 2018~~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 outstandingby $500 million under the ~~2018 credit facility may become immediately due and payable.~~Short-Term Tranche as a temporary working capital liquidity resource. As of March 31, ~~2022, the Company was in compliance with all of the covenants of the credit agreement in all material respects.~~

Each United States domestic subsidiary of the Company for which the Company owns 100% of its equity guarantees the 2018 credit facility. Pursuant to requirements under the indentures governing its senior notes, each subsidiary that became a guarantor of the 2018 credit facility also became a guarantor of each of the Company’s senior notes.

~~As of March 31, 2022,~~2023, the Company had ~~$147 million in letters of credit and $174 million in~~no borrowings ~~outstanding~~ under the ~~2018 credit facility. The Company currently does not anticipate being required to supply a materially greater amount of letters of credit under its existing contracts.~~

~~2022 Credit Facility~~

OnShort-Term Tranche and the short-term commitments will expire on April 8, 2022, the Company entered into an Amended and Restated Credit Agreement that replaces the 2018 credit facility (the “2022 credit facility”) with a group of banks, that as amended, has a maturity date of April 2027. The 2022 credit facility has an aggregate maximum revolving credit amount and borrowing base of $3.5 billion, and elected commitments of $2.0 billion. The borrowing base is subject to redetermination at least twice a year, which typically occurs in April and October, and is secured by substantially all of the assets owned by the Company and its subsidiaries. The 2022 credit facility has a term of five years from the effective date of April 8, 2022.30, 2023.

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 less than 1.00 to 1.00, whereby current ratio is defined as the Company’s consolidated current assets (including unused commitments under the credit agreement, but excluding non-cash derivative assets) to consolidated current liabilities (excluding non-cash derivative obligations and current maturities of long-term debt).

2.Maximum total net leverage ratio of not greater than, with respect to the prior four fiscal quarters ending on or after March 31, 2022, 4.00 to 1.00. Total net leverage ratio is defined as total debt less cash on hand (up to the lesser of 10% of credit limit or $150 million) divided by consolidated EBITDAX for the last four consecutive quarters. EBITDAX, as defined in the credit agreement governing the Company’s ~~2018~~2022 credit facility, excludes the effects of interest expense, depreciation, depletion and amortization, income tax, any non-cash impacts from

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impairments, certain non-cash hedging activities, stock-based compensation expense, non-cash gains or losses on asset sales, unamortized issuance cost, unamortized debt discount and certain restructuring costs.

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

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immediately due and payable. As of March 31, 2023, the Company was in compliance with all of the covenants of the credit agreement in all material respects.

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

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

•An unsecured long-term debt credit ~~rating~~ 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 ~~repayment in full of the term loan obligations under Southwestern’s Term Loan Agreement dated December 22, 2021,~~ 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,~~guarantees;

•The collateral under the facility will be ~~released,~~released;

•The facility will no longer be subject to a borrowing ~~base,~~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%.

~~Term Loan Credit Agreement~~

In December 2021, the Company entered into a term loan credit agreement with a group of lenders that provided for a $550 million secured term loan facility which matures in June 2027 (the “Term Loan”). As of March 31, ~~2022,~~2023, the Company had $89 million in letters of credit and $210 million in borrowings under this Term Loan of $549 million. The net proceeds from the initial loans of $542 million were used to fund a portion of the GEPH Merger on December 31, 2021. Beginning on March 31, 2022, the Term Loan requires minimum quarterly payments of $1.375 million, subject to adjustment for voluntary prepayments and mandatory prepayments as applicable. The Term Loan is subject to varying rates of interest based on whether the term loan is a term benchmark loan or an alternate base rate loan. Term benchmark loans bear interest at the adjusted term SOFR (which includes a credit spread adjustment and is subject to a floor that is 0.50%) plus an applicable margin equal to 2.50%. Alternate base rate loans bear interest at the alternate base rate plus an applicable margin equal to 1.50%. The current borrowings are considered benchmark loans and are carried at an interest rate of 3.30% as of March 31, 2022 (0.80% credit spread adjustment plus 2.50% margin).

The Term Loan is subject to a quarterly collateral coverage ratio test in which the Company’s PDP PV-10 value, net of derivative mark-to-market value, must be greater than 2.0x its secured debt commitments or all secured debt becomes callable. If necessary, outstanding ~~secured debt principal can be paid down within 45 days of the end of such fiscal quarter to come into~~

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~~compliance with this ratio, either by (i) prepaying the loans, (ii) prepaying the loans~~ under the ~~2018 (2022 as amended)~~2022 credit ~~facility, (iii) prepaying any other secured indebtedness that is secured by~~facility. The Company currently does not anticipate being required to supply a ~~lien, or some combination thereof. As~~materially greater amount of ~~March 31, 2022, the Company was in compliance with the quarterly coverage ratio test.~~

~~The Company’s obligations~~letters of credit under the Term Loan are guaranteed by each of the Company’s subsidiaries that guarantee the obligations under the 2018 (2022 as amended) credit facility and are secured by liens on substantially all the assets of the Company and the Company’s subsidiaries on an equal basis with the liens securing the obligations under the 2018 (2022 as amended) credit facility.its existing contracts.

Senior Notes

In January 2015, the Company completed a public offering of $1.0 billion aggregate principal amount of its 4.95% Senior Notes due 2025 (the “2025 Notes”). The interest rate on the 2025 Notes is determined based upon the public bond ratings from Moody’s and S&P. Downgrades on the 2025 Notes from either rating agency increase interest costs by 25 basis points per downgrade level and upgrades decrease interest costs by 25 basis points per upgrade level, up to the stated coupon rate, on the following semi-annual bond interest payment. Effective in July 2018, the interest rate for the 2025 Notes was 6.20%, reflecting a net downgrade in the Company’s bond ratings since their issuance. On April 7, 2020, S&P downgraded the Company’s bond

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rating to BB-, which had the effect of increasing the interest rate on the 2025 Notes to 6.45% following the July 23, 2020 interest payment due date. The first coupon payment to the 2025 Notes bondholders at the higher interest rate was paid in January 2021. On September 1, 2021, S&P upgraded the Company’s bond rating to BB, and on January 6, 2022, S&P further upgraded the Company’s bond rating to BB+, which decreased the interest rate on the 2025 Notes to 5.95% beginning with coupon payments paid after January 2022.

In August 2020, the Company completed a public offering of $350 million aggregate principal amount of its 8.375% Senior Notes due 2028 (the “2028 Notes”), with net proceeds from the offering totaling approximately $345 million after underwriting discounts and offering expenses. The 2028 Notes were sold to the public at 100% of their face value. The net proceeds from the notes, in conjunction with the net proceeds from the August 2020 common stock offering and borrowings under the 2018 credit facility, were utilized to fund a redemption of $510 million of Montage’s Notes in connection with the closing of the Montage Merger.

On August 30, 2021, Southwestern closed its public offering of $1,200 million aggregate principal amount of its 5.375% Senior Notes due 2030 (the “2030 Notes”), with net proceeds from the offering totaling $1,183 million after underwriting discounts and offering expenses. The proceeds were used to repurchase the remaining $618 million ofMay 31, 2022, Moody’s upgraded the Company’s ~~7.50% Senior Notes due 2026, $167 million of~~bond rating to Ba1, which decreased the ~~Company’s 4.95% Senior Notes due 2025 and $6 million of the Company’s 4.10% Senior Notes due 2022 for $845 million, and the Company recognized a $60 million loss~~interest rate on the extinguishment of debt, which included the write-off of $6 million in related unamortized debt discounts and debt issuance costs. The remaining proceeds were used to pay borrowings under its 2018 credit facility and for general corporate purposes.

Upon the close of the Indigo Merger on September 1, 2021, and pursuant to the terms of the Indigo Merger Agreement, Southwestern assumed $700 million in aggregate principal amount of Indigo’s 5.375% Senior Notes due 2029 (“Indigo Notes”). As part of purchase accounting, the assumption of the Indigo Notes resulted in a non-cash fair value adjustment of $26 million, based on the market price of 103.766% on September 1, 2021, the date that the Indigo Merger closed. Subsequent to the Indigo Merger, the Company exchanged the Indigo Notes for approximately $700 million of newly issued 5.375% Senior Notes due 2029, the offering of which was registered with the SEC in November 2021.

On December 22, 2021, Southwestern closed its public offering of $1,150 million aggregate principal amount of its 4.75% Senior Notes due 2032 (the “2032 Notes”), with net proceeds from the offering totaling $1,133 million after underwriting discounts and offering expenses. The net proceeds of this offering, along with the net proceeds from the Term Loan, were used to fund the cash consideration portion of the GEPH Merger, which closed on December 31, 2021, and to pay $332 million to fund tender offers for $300 million of the Company’s 2025 Notes from 5.95% to 5.70% for which the Company recorded an additional loss on extinguishment of debt of $33 million, which included the write-off of $1 million in related unamortized debt discounts and debt issuance costs. The remaining proceeds were used for general corporate purposes.coupon payments paid after July 2022.

In the first quarter of 2022, the Company ~~repurchased~~redeemed the remaining outstanding principal balance of $201 million of its 4.10% Senior Notes due 2022, $5 million of its 8.375% Senior Notes due 2028 and $15 million of its 7.75% Senior Notes due 2027 for a total of $223 million, and recognized a $2 million loss on debt extinguishment.

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

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~~(12)~~(11) COMMITMENTS AND CONTINGENCIES

Operating Commitments and Contingencies

As of March 31, ~~2022,~~2023, the Company’s contractual obligations for demand and similar charges under firm transportation and gathering agreements to guarantee access capacity on natural gas and liquids pipelines and gathering systems totaled approximately ~~$10.2~~$10 billion, ~~$857 million~~$1.3 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. The Company also had guarantee obligations of up to ~~$877~~$853 million of that total amount. As of March 31, ~~2022,~~2023, future payments under non-cancelable firm transportation and gathering agreements were as follows:


		Payments Due by Period													Payments Due by Period
(in millions)	(in millions)	Total		Less than 1 Year		1 to 3 Years		3 to 5 Years		5 to 8 Years		More than 8 Years		(in millions)	Total		Less than 1 Year		1 to 3 Years		3 to 5 Years		5 to 8 Years		More than 8 Years
Infrastructure currently in service	Infrastructure currently in service	$	9,301	$	1,066	$	1,943	$	1,729	$	2,085	$	2,478	Infrastructure currently in service	$	8,703	$	1,045	$	1,892	$	1,692	$	1,833	$	2,241
Pending regulatory approval and/or construction (1)	Pending regulatory approval and/or construction (1)	857		3		124		161		247		322		Pending regulatory approval and/or construction (1)	1,302		38		218		262		368		416
Total transportation charges	Total transportation charges	$	10,158	$	1,069	$	2,067	$	1,890	$	2,332	$	2,800	Total transportation charges	$	10,005	$	1,083	$	2,110	$	1,954	$	2,201	$	2,657

(1)Based on estimated in-service dates as of March 31, ~~2022.~~2023.

Prior to the Indigo Merger, in May 2021, Indigo closed on an agreement to divest its Cotton Valley natural gas and oil properties. Indigo retained certain contractual commitments related to volume commitments associated with natural gas gathering, for which Southwestern assumed the obligation to pay the gathering provider for any unused portion of the volume commitment under the agreement through 2027, depending on the buyer’s actual use. As of March 31, 2022, up to approximately $34 million of these contractual commitments remain (included in the table above), and the Company has recorded a $17 million liability for its portion of the estimated future payments.

Excluding the Cotton Valley gathering agreement (discussed above), the Company has recorded additional liabilities totaling $35 million as of March 31, 2022, primarily related to purchase or volume commitments associated with gathering, fresh water and sand. These amounts are reflected above and will be recognized as payments are made over the next ~~two~~ ~~years.~~

Environmental Risk

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

Litigation

The Company is subject to various litigation, claims and proceedings, most of which have arisen in the ordinary course of business, such as for alleged breaches of contract, miscalculation of royalties, employment matters, traffic accidents, pollution, contamination, encroachment on others’ property or nuisance. The Company accrues for litigation, claims and proceedings when a liability is both probable and the amount can be reasonably estimated. As of March 31, ~~2022,~~2023, the Company does not currently have any material amounts accrued related to litigation matters, including the ~~cases~~case discussed below. For any matters not accrued for, it is not possible at this time to estimate the amount of any additional loss, or range of loss, that is reasonably possible, but, based on the nature of the claims, management believes that current litigation, claims and proceedings, individually or in aggregate and after taking into account insurance, are not likely to have a material adverse impact on the Company’s financial position, results of operations or cash flows, for the period in which the effect of that outcome becomes reasonably estimable. Many of these matters are in early stages, so the allegations and the damage theories have not been fully developed, and are all subject to inherent uncertainties; therefore, management’s view may change in the future.

Bryant Litigation

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

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On June 12, 2018, a collection of 51 individuals and entities filed a lawsuit against 15fifteen oil and gas company defendants, including Indigo, in Louisiana state court claiming damages arising out of current and historical development and production activity on certain acreage located in DeSoto Parish, Louisiana. The plaintiffs, who claim to own the properties at issue, assert that Indigo’s actions and the actions of other current operators conducting development and production activity, combined with the improper plugging and abandoning of legacy wells by former operators, have caused environmental contamination to their properties. Among other things, the plaintiffs contend that the defendants’ conduct resulted in the migration of natural gas,

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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.~~litigation which the Company has opposed. Plaintiffs later filed seventh and eighth supplemental petitions naming additional defendants. Fact discovery for the case is ongoing.

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

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

Indemnifications

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

~~(13)~~(12) INCOME TAXES

The Company’s effective tax rate was approximately 1% and 0% for the three months ended March 31, ~~2022. The effective tax rate for~~2023 and 2022, respectively, primarily as a result of the ~~three months ended March 31, 2022 related to the effects~~partial release of a valuation ~~allowance~~allowances against the Company’s U.S. deferred tax ~~assets.~~assets in the first quarter of 2023. A valuation allowance for deferred tax assets, including net operating losses (“NOLs”), is recognized when it is more likely than not that some or all of the benefit from the deferred tax assets will not be realized. To assess that likelihood, the Company uses estimates and judgment regarding future taxable income and considers the tax consequences in the jurisdiction where such taxable income is generated, to determine whether a valuation allowance is required. Such evidence can include current financial position, results of operations, both actual and forecasted, the reversal of deferred tax liabilities and tax planning strategies as well as the current and forecasted business economics of the oil and gas industry.

For the year ended December 31, 2022, the Company maintained a full valuation allowance against its deferred tax assets based on its conclusion, considering all available evidence (both positive and negative), that it was more likely than not that the deferred tax assets would not be realized. A significant item of objective negative evidence considered was the cumulative pre-tax loss incurred over the three-year period ended December 31, 2022, primarily due to impairments of proved oil and gas properties recognized in 2020. As of the first quarter of ~~2022,~~2023, the Company ~~still maintains~~has sustained a ~~full~~three-year cumulative level of profitability. Based on this factor and other positive evidence such as forecasted income, the Company concluded that $523 million of its federal and state deferred tax assets were more likely than not to be realized and plan to release this portion of the valuation allowance in 2023. Accordingly, during the 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 will be released during subsequent quarters during 2023. The Company ~~also retained~~expects to keep a valuation allowance of ~~$59~~$66 million related to ~~net operating losses~~NOLs in jurisdictions in which it no longer ~~operates. Management will continue to assess available positive~~operates and ~~negative evidence to estimate whether sufficient future taxable income will be generated to permit~~against the ~~use~~portion of deferred tax assets. The amount of the deferred tax asset considered realizable, however, could be adjusted based on changes in subjective estimates of future taxable income or if objective negative evidence is no longer present.

~~The Company intends to continue a full valuation allowance on~~ its federal and state deferred tax assets ~~until there is sufficient evidence~~such as capital

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losses and interest carryovers, which may expire before being fully utilized due to ~~support~~ the ~~reversal of all or some portion~~application of the ~~allowance. However, if current commodity prices are sustained~~limitations under Section 382 and ~~absent any additional objective negative evidence, it is reasonably possible that sufficient positive evidence will exist within~~ the ~~next 12 months to adjust the current valuation allowance position. Exact timing and amount of the adjustment to the valuation allowance is unknown at this time.~~ordering in which such attributes may be applied.

The Company’s effective tax rate was approximately 0% for the three months ended March 31, 2021. The effective tax rate for the three months ended March 31, 2021 related to the effects of the valuation allowance against the Company’s U.S. deferred tax assets.

Due to the issuance of common stock associated with the Indigo Merger, ~~as discussed in~~ ~~Note 2~~, the Company incurred a cumulative ownership change and as such, the Company’s ~~net operating losses (“NOLs”)~~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, with a corresponding decrease in the Company’s valuation allowance.~~available. At March 31, ~~2022,~~2023, the Company had approximately $4 billion of federal

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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. The non-expiring~~used and accordingly, no value has been ascribed to these NOLs ~~remain subject to a full valuation allowance.~~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.

~~For three months ended March 31,~~The Inflation Reduction Act of 2022 (the “IRA”) was enacted on August 16, 2022 and may impact how the ~~Company recorded current~~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 ~~expense of approximately $4 million as it expects to pay cash income taxes for the year ended~~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.

~~(14)~~(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.~~compensation (the “Plan”). As part of an ongoing effort to reduce costs, the Company elected to freeze ~~its pension plan~~the Plan effective January 1, 2021. Employees that were participants in the ~~pension plan~~Plan prior to January 1, 2021 continued to receive the interest component of the ~~plan~~Plan but no longer received the service component. On September 13, 2021, the Compensation Committee of the Board ~~of Directors~~ approved terminating the ~~Company’s pension plan,~~Plan, effective December 31, ~~2021, subject to approval by the Internal Revenue Service.~~2021. This decision, among other benefits, will provide ~~plan~~Plan participants quicker access to, and greater flexibility in, the management of participants’ respective benefits due under the ~~plan.~~Plan.

The Company ~~has~~ commenced the ~~pension plan~~Plan termination process, ~~but~~and, on April 6, 2022, the ~~specific date for~~Internal Revenue Service issued a favorable determination letter, concurring that the ~~completion~~Plan met all of the ~~process is unknown at this time~~qualification requirements under the Internal Revenue Code. In December 2022, the Company distributed approximately 40% 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 ~~will depend on certain legal and regulatory requirements or approvals. As~~former employee participants as part of the Plan termination ~~process,~~process.

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

Upon issuance of the group annuity contract, the pension benefit obligations and annuity administration for the remaining participants was irrevocably transferred from the Plan to the insurer. By transferring these obligations through the payment to the insurer in March 2023, 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 three months ended March 31, 2023 as a result of the settlement of the Plan.

As of March 31, 2023, the Company had residual Plan assets of $13 million. The Company has not transferred the residual Plan assets to a qualified replacement plan ~~participants, which~~as of March 31, 2023 as the reconciliation process with the insurance company is ~~dependent on the participants’ elections.~~ongoing.

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.

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Net periodic pension costs include the following components for the three months ended March 31, ~~2022~~2023 and ~~2021:~~2022:

Consolidated Statements of
Operations Classification of
Net Periodic Benefit Cost For the three months ended March 31,
(in millions) 2022 2021
Service cost General and administrative expenses $ — $ —
Interest cost Other Income (Loss), Net 1 1
Expected return on plan assets Other Income (Loss), Net — (1)
Amortization of net loss Other Income (Loss), Net — —
Settlement loss Other Income (Loss), Net — —
Net periodic benefit cost $ 1 $ —

~~The Company recognized an immaterial non-cash settlement loss in the first quarter of 2022.~~



	Consolidated Statements of Operations Classification of Net Periodic Benefit Cost	For the three months ended March 31,
(in millions)		2023		2022
Service cost	General and administrative expenses	$	—	$	—
Interest cost	Other Income (Loss), Net	—		1
Expected return on plan assets	Other Income (Loss), Net	(1)		—
Amortization of prior service cost	Other Income (Loss), Net	—		—

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

The Company’s other postretirement benefit plan had a net periodic benefit cost of less than $1 million for ~~each of~~both the three months ended March 31, ~~2022~~2023 and ~~2021.~~2022.

The Company did not make any contributions to the Plan during 2023 and does not expect to ~~make any additional contributions~~do so throughout the completion of the Plan termination process. The Company recognized residual pension assets of $13 million and net pension assets of $15 million related to its pension ~~plan during~~benefits as of March 31, 2023 and December 31, 2022, ~~or thereafter until the plan termination is completed.~~respectively. The Company recognized liabilities of ~~$12~~$10 million and ~~$13~~$9 million related to its ~~pension and~~ other postretirement benefits as of ~~both~~ March 31, ~~2022~~2023 and December 31, ~~2021.~~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 ~~1,745~~1,455 shares at March 31, ~~2022~~2023 and ~~2,035~~1,743 shares at December 31, ~~2021.~~

2022.

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~~(15)~~(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 ~~seven~~10 years from the date of grant. However, the Company has not granted stock options since ~~February~~ 2017. The Company issues shares of restricted stock and restricted stock units ~~or performance cash awards~~ to employees and directors which generally vest over three years.

Restricted stock, restricted stock units and stock options granted ~~to participants~~ under the ~~2013~~Southwestern Energy Company 2022 Incentive Plan ~~as amended and restated,~~(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 ~~2019, 2020~~2021, 2022 and ~~2021~~2023 cliff-vest at the end of three years.

~~In February~~

Table of 2021, the Company notified employees of a workforce reduction plan as a result of strategic realignments of the Company’s organizational structure. The reduction was substantially complete by the end of the first quarter of 2021. Affected employees were offered a severance package which, if applicable, included the current value of unvested long-term incentive awards that were forfeited. Stock-based compensation costs recognized prior to the cancellation as either general and administrative expense or capitalized expense were reversed, and the severance payments were subsequently recognized as restructuring charges for the three months ended March 31, 2021.Contents

The Company recognized the following amounts in total related to long-term incentive compensation costs for the three months ended March 31, ~~2022~~2023 and ~~2021:~~2022:


		For the three months ended March 31,				For the three months ended March 31,
(in millions)	(in millions)	2022		2021			(in millions)	2023		2022
Long-term incentive compensation – expensed	Long-term incentive compensation – expensed	$	11	$	13		Long-term incentive compensation – expensed	$	4	$	11
Long-term incentive compensation – capitalized	Long-term incentive compensation – capitalized	$	7	$	5		Long-term incentive compensation – capitalized	$	3	$	7

Equity-Classified Awards

The Company recognized the following amounts in employee equity-classified stock-based compensation costs for the three months ended March 31, ~~2022~~2023 and ~~2021:~~2022:

For the three months ended March 31,
(in millions) 2022 2021
Equity-classified awards – expensed $ 1 $ —
Equity-classified awards – capitalized $ — $ —

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	For the three months ended March 31,
(in millions)	2023		2022
Equity-classified awards – expensed	$	1	$	1
Equity-classified awards – capitalized	$	1	$	—

Equity-Classified Stock Options

The following table summarizes equity-classified stock option activity for the three months ended March 31, ~~2022~~2023 and provides information for options outstanding and options exercisable as of March 31, ~~2022:~~2023:


		Number of Options	Weighted Average Exercise Price			Number of Options	Weighted Average Exercise Price
		(in thousands)				(in thousands)
Outstanding at December 31, 2021		3,006	$	8.98
Outstanding at December 31, 2022					Outstanding at December 31, 2022	997	$	8.59
Granted	Granted	—	$	—	Granted	—	$	—
Exercised	Exercised	—	$	—	Exercised	—	$	—
Forfeited or expired	Forfeited or expired	(152)	$	26.35	Forfeited or expired	(177)	$	8.60
Outstanding at March 31, 2022		2,854	$	8.06
Exercisable at March 31, 2022		2,854	$	8.06
Outstanding at March 31, 2023					Outstanding at March 31, 2023	820	$	8.59
Exercisable at March 31, 2023					Exercisable at March 31, 2023	820	$	8.59

Equity-Classified Restricted Stock

~~The following table summarizes equity-classified restricted stock activity for the three months ended March 31, 2022 and provides information for unvested shares as of March 31, 2022:~~

Number
of Shares Weighted Average
Fair Value
(in thousands)
Unvested shares at December 31, 2021 242 $ 5.12
Granted — $ —
Vested (43) $ 4.90
Forfeited — $ —
Unvested shares at March 31, 2022 199 $ 5.17

As of March 31, ~~2022,~~2023, there was less than $1 million of total unrecognized compensation cost related to the Company’s unvested equity-classified restricted stock grants. This cost is expected to be recognized over a weighted-average period of ~~1.6~~0.7 years. The following table summarizes equity-classified restricted stock activity for the three months ended March 31, 2023 and provides information for unvested shares as of March 31, 2023:


	Number of Shares	Weighted Average Fair Value
	(in thousands)
Unvested shares at December 31, 2022	211	$	5.81
Granted	—	$	—
Vested	(70)	$	5.15
Forfeited	—	$	—
Unvested shares at March 31, 2023	141	$	6.14

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Equity-Classified Restricted Stock Units

As of March 31, ~~2022,~~2023, there was $7$11 million of total unrecognized compensation cost related to the Company’s unvested equity-classified restricted stock units. This cost is expected to be recognized over a weighted-average period of ~~2.6~~1.9 years. The following table summarizes equity-classified restricted stock units for the three months ended March 31, ~~2022~~2023 and provides information for unvested units as of March 31, ~~2022.~~2023.


		Number of Shares	Weighted Average Fair Value			Number of Shares	Weighted Average Fair Value
		(in thousands)				(in thousands)
Unvested units at December 31, 2021		37	$	3.05
Unvested units at December 31, 2022					Unvested units at December 31, 2022	1,645	$	4.44
Granted	Granted	1,699	$	4.45	Granted	1,539	$	4.83
Vested	Vested	—	$	—	Vested	(545)	$	4.45
Forfeited	Forfeited	(2)	$	3.05	Forfeited	—	$	—
Unvested units at March 31, 2022		1,734	$	4.42
Unvested units at March 31, 2023					Unvested units at March 31, 2023	2,639	$	4.67

Equity-Classified Performance Units

In each year beginning with 2018, the Company granted performance units that vest at the end of, or over, a ~~three-year~~three-year period and are payable in either cash or ~~shares at the option of the Compensation Committee of the Company’s Board of Directors.~~shares. The ~~awards~~performance units granted from ~~2018~~2020 through 2021 were accounted for as liability-classified awards as ~~the intention of the awards was to settle in cash.~~further described below. In 2022 and 2023, two types of performance units were granted. The first type of awards were ~~granted, one of which was accounted for as liability classified awards~~liability-classified given the ~~intention to settle~~awards are payable only in ~~cash.~~cash as prescribed under the compensation agreements. The ~~other~~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 and accordingly are~~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.~~TSR (as defined below). The fair values of the market conditions were calculated by Monte Carlo models as of the grant date. As of March 31, ~~2022,~~2023, there was

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$5 $8 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 ~~2.9~~2.5 years.


		Number of Shares	Weighted Average Fair Value			Number of Shares	Weighted Average Fair Value
		(in thousands)				(in thousands)
Unvested units at December 31, 2021		—	$	—
Unvested units at December 31, 2022					Unvested units at December 31, 2022	817	$	6.04
Granted	Granted	850	$	6.04	Granted	940	$	6.12
Vested	Vested	—	$	—	Vested	—	$	—
Forfeited	Forfeited	—	$	—	Forfeited	—	$	—
Unvested units at March 31, 2022		850	$	6.04
Unvested units at March 31, 2023					Unvested units at March 31, 2023	1,757	$	6.08

Liability-Classified Awards

The Company recognized the following amounts in employee liability-classified stock-based compensation costs for the three months ended March 31, ~~2022:~~2023:


		For the three months ended March 31,				For the three months ended March 31,
(in millions)	(in millions)	2022		2021			(in millions)	2023		2022
Liability-classified stock-based compensation cost – expensed	Liability-classified stock-based compensation cost – expensed	$	8	$	13		Liability-classified stock-based compensation cost – expensed	$	1	$	8
Liability-classified stock-based compensation cost – capitalized	Liability-classified stock-based compensation cost – capitalized	$	6	$	5		Liability-classified stock-based compensation cost – capitalized	$	—	$	6

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Liability-Classified Restricted Stock Units

In the first quarter of each year beginning with 2018, the Company granted restricted stock units that vest over a period of four years and are payable in either cash or shares at the option of the Compensation Committee of the Company’s ~~Board of Directors.~~Board. The ~~liability classified~~liability-classified awards granted in 2021 vest over a period of three years. The Company has accounted for these as liability-classified awards, and accordingly changes in the market value of the instruments will be recorded to general and administrative expense and capitalized expense over the vesting period of the award. As of March 31, ~~2022,~~2023, there was ~~$23~~$5 million of total unrecognized compensation cost related to liability-classified restricted stock units that is expected to be recognized over a weighted-average period of ~~1.6~~0.9 years. The amount of unrecognized compensation cost for liability-classified awards will fluctuate over time as they are marked to market.


		Number of Units	Weighted Average Fair Value			Number of Units	Weighted Average Fair Value
		(in thousands)				(in thousands)
Unvested units at December 31, 2021		7,937	$	4.08
Unvested units at December 31, 2022					Unvested units at December 31, 2022	3,950	$	4.81
Granted	Granted	—	$	—	Granted	—	$	—
Vested	Vested	(3,806)	$	4.47	Vested	(2,206)	$	4.84
Forfeited	Forfeited	(12)	$	7.01	Forfeited	(3)	$	5.57
Unvested units at March 31, 2022		4,119	$	5.83
Unvested units at March 31, 2023					Unvested units at March 31, 2023	1,741	$	3.69

Liability-Classified Performance Units

In each year beginning with 2018, the Company granted performance units that vest at the end of, or over, a ~~three-year~~three-year period and are payable in either cash or ~~shares~~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 of Directors.~~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 ~~accounted for these~~been liability-classified while the other type is equity-classified as ~~liability-classified awards, and accordingly changes~~further discussed above. Changes in the fair market value of the instruments for liability-classified awards will be recorded to general and administrative expense and capitalized expense over the vesting period of the awards. The performance unit awards granted in 2019 include performance conditions based on return on average capital employed and two market conditions based on total shareholder return (“TSR”), one based on absolute TSR and the other on relative TSR.

The performance units granted in 2020 include a performance condition based on return on average capital employed and a market condition based on relative ~~TSR.~~total shareholder return (“TSR”). In 2021, 2of the two types of performance ~~unit awards were granted. One~~units granted, the first type of award includes a performance condition based on return on capital employed and a performance condition based on a reinvestment rate, and the second type of award includes one market condition based on relative TSR. InThe liability-classified performance units granted in 2022 ~~two types of performance unit awards were granted. One type of award includes a~~and 2023 include performance conditions based on return on capital employed and reinvestment rate. The ~~other 2022 awards granted were accounted for as equity classified awards. The~~ fair values of ~~the~~all market conditions discussed above are calculated by Monte Carlo models on a quarterly basis.

As of March 31, ~~2022,~~2023, there was ~~$18~~$9 million of total unrecognized compensation cost related to liability-classified performance units. This cost is expected to be recognized over a weighted-average period of ~~1.8~~2.4 years. The amount of unrecognized compensation cost for liability-classified

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awards will fluctuate over time as they are marked to market. The final value of the performance unit awards is contingent upon the Company’s actual performance against these performance measures.


		Number of Units	Weighted Average Fair Value			Number of Units	Weighted Average Fair Value
		(in thousands)				(in thousands)
Unvested units at December 31, 2021		9,515	$	2.88
Unvested units at December 31, 2022					Unvested units at December 31, 2022	10,982	$	2.25
Granted	Granted	3,798	$	1.00	Granted	5,136	$	4.83
Vested (1)	Vested (1)	(1,910)	$	6.45	Vested (1)	(3,966)	$	6.13
Forfeited	Forfeited	—	$	—	Forfeited	—	$	—
Unvested units at March 31, 2022		11,403	$	3.51
Unvested units at March 31, 2023					Unvested units at March 31, 2023	12,152	$	1.09

~~(1)~~

Table of Contents~~The 2019 Performance Unit Awards were treated as liability classified awards given the ability to settle in cash or stock. Upon vesting in February 2022, the determination was made to settle in stock.~~

Cash-Based Compensation

The Company recognized the following amounts in performance cash award compensation costs for the three months ended March 31, ~~2022~~2023 and ~~2021:~~2022:


		For the three months ended March 31,					For the three months ended March 31,
(in millions)	(in millions)	2022		2021		(in millions)	2023		2022
Performance cash awards – expensed	Performance cash awards – expensed	$	2	$	—	Performance cash awards – expensed	$	2	$	2
Performance cash awards – capitalized	Performance cash awards – capitalized	$	1	$	—	Performance cash awards – capitalized	$	2	$	1

Performance Cash Awards

~~In 2021 and~~From 2020 through 2022 the Company granted performance cash awards that vest over a ~~4-year~~four-year period and are payable in cash on an annual basis. In 2023, the Company granted performance cash awards that vest over a three-year period and are payable in cash on an annual basis. The value of each unit of the award equals one dollar. The Company recognizes the cost of these awards as general and administrative expense and capitalized expense over the vesting period of the awards. The performance cash awards granted ~~in 2021 and~~from 2020 through 2023 include a performance condition determined annually by the Company. For ~~both~~all years, the performance measure is a targeted discretionary cash flow amount. If the Company, in its sole discretion, determines that the threshold was not met, the amount for that vesting period will not vest and will be cancelled. As of March 31, ~~2022,~~2023, there was ~~$42~~$52 million of total unrecognized compensation cost related to performance cash awards. This cost is expected to be recognized over a weighted-average period of ~~3.2~~2.6 years. The final value of the performance cash awards is contingent upon the Company’s actual performance against these performance measures.


		Number of Units	Weighted Average Fair Value			Number of Units	Weighted Average Fair Value
		(in thousands)				(in thousands)
Unvested units at December 31, 2021		28,272	$	1.00
Unvested units at December 31, 2022					Unvested units at December 31, 2022	39,994	$	1.00
Granted	Granted	24,416	$	1.00	Granted	27,493	$	1.00
Vested	Vested	(8,483)	$	1.00	Vested	(12,896)	$	1.00
Forfeited	Forfeited	(675)	$	1.00	Forfeited	(577)	$	1.00
Unvested units at March 31, 2022		43,530	$	1.00
Unvested units at March 31, 2023					Unvested units at March 31, 2023	54,014	$	1.00

~~(16)~~(15) SEGMENT INFORMATION

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

Summarized financial information for the Company’s reportable segments is shown in the following table. The accounting policies of the segments are the same as those described in Note 1 of the Notes to Consolidated Financial Statements included in Item 8 of the ~~2021~~2022 Annual Report. Management evaluates the performance of its segments based on operating income, defined as operating revenues less operating costs. Income before income taxes, for the purpose of reconciling the operating income amount shown below to consolidated income before income taxes, is the sum of operating income, interest expense, gain (loss) on derivatives, gain on early extinguishment of debt and other income (loss). The “Other” column includes items

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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.

Exploration and Production Marketing Other Total
Three months ended March 31, 2022 (in millions)
Revenues from external customers $ 2,077 $ 866 $ — $ 2,943
Intersegment revenues (3) 1,889 — 1,886
Depreciation, depletion and amortization expense 274 1 — 275
Impairments — — — —
Operating income 1,278 (1) 21 — 1,299
Interest expense (2)
41 — — 41
Loss on derivatives (3,925) — (2) (3,927)
Loss on extinguishment of debt — — (2) (2)
Other income, net — — — —
Provision for income taxes (2)
4 — — 4
Assets 10,766 (3) 969 112 11,847
Capital investments (4)
544 — — 544
Three months ended March 31, 2021
Revenues from external customers $ 719 $ 353 $ — $ 1,072
Intersegment revenues (14) 644 — 630
Depreciation, depletion and amortization expense 94 2 — 96
Operating income 295 (1) 6 — 301
Interest expense (2)
31 — — 31
Loss on derivatives (191) — — (191)
Other income, net 1 — — 1
Assets 4,741 (3) 396 110 5,247
Capital investments (4)
266 — — 266

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	Exploration and Production			Marketing		Other		Total

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

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

Three months ended March 31, 2022
Revenues from external customers	$	2,077		$	866	$	—	$	2,943
Intersegment revenues	(3)			1,889		—		1,886
Depreciation, depletion and amortization expense	274			1		—		275

Operating income	1,278		(4)	21		—		1,299
Interest expense (1)	41			—		—		41
Loss on derivatives	(3,925)			—		(2)		(3,927)
Loss on early extinguishment of debt	—			—		(2)		(2)
Other income, net	—			—		—		—
Provision from income taxes (1)	4			—		—		4
Assets	10,766		(2)	969		112		11,847
Capital investments (3)	544			—		—		544

(1)Operating income (loss) for the E&P segment includes $6 million of restructuring charges for the three months ended 2021. The E&P segment operating income (loss) also includes $25 million and $1 million of merger-related expenses for the three months ended March 31, 2022 and 2021, respectively.

~~(2)~~Interest expense and provision (benefit) for income taxes by segment is an allocation of corporate amounts as they are incurred at the corporate level.

~~(3)~~(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.

~~(4)~~(3)Capital investments include ~~increases~~a decrease of ~~$43~~$6 million and ~~$38~~an increase of $43 million for the three months ended March 31, ~~2022~~2023 and ~~2021,~~March 31, 2022, respectively, relating to the change in accrued expenditures between periods.

(4)The E&P segment operating income includes $25 million of merger-related expenses related to the Indigo and GEPH Mergers for the three months ended March 31, 2022.

The following table presents the breakout of other assets, which represent corporate assets not allocated to segments and assets for non-reportable segments at March 31, ~~2022~~2023 and ~~2021:~~2022:


		As of March 31,					As of March 31,
(in millions)	(in millions)	2022		2021		(in millions)	2023			2022
Cash and cash equivalents	Cash and cash equivalents	$	21	$	4	Cash and cash equivalents	$	3		$	21
Accounts receivable	Accounts receivable	1		—		Accounts receivable	1			1

Prepayments	Prepayments	6		6		Prepayments	12			6
Property, plant and equipment	Property, plant and equipment	10		15		Property, plant and equipment	19			10
Unamortized debt expense	Unamortized debt expense	9		11		Unamortized debt expense	18			9
Right-of-use lease assets	Right-of-use lease assets	63		70		Right-of-use lease assets	55			63
Non-qualified retirement plan	Non-qualified retirement plan	2		4		Non-qualified retirement plan	2			2

Long-term assets						Long-term assets	15		(1)	—
		$	112	$	110		$	125		$	112

(1)Consists primarily of residual assets associated with the Company’s pension plan. See Note 13 for discussion on the Company’s pension plan.

~~(17)~~(16) NEW ACCOUNTING PRONOUNCEMENTS

New Accounting Standards Implemented in this Report

In March 2020, the FASB issued ASU 2020-04, Reference Rate Reform, as a new ASC Topic, ASC 848. The purpose of ASC 848 is to provide optional guidance to ease the potential effects on financial reporting of the market-wide migration awayNone.

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from Interbank Offered Rates, such as LIBOR, to alternative reference rates. ASC 848 applies only to contracts, hedging relationships, debt arrangements and other transactions that reference a benchmark reference rate expected to be discontinued because of reference rate reform. ASC 848 contains optional expedients and exceptions for applying U.S. GAAP to transactions affected by this reform. The amendments in the ASU are effective for all entities as of March 12, 2020 through December 31, 2022.

~~As discussed in~~ ~~Note 11~~, the Company amended and extended its credit facility which is subject to SOFR interest rates beginning in the second quarter of 2022. The change from LIBOR to SOFR rates will not have a material impact on the Company’s consolidated financial statements.

New Accounting Standards Not Yet Adopted in this Report

None that are expected to have a material impact.

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

The following updates information as to Southwestern Energy Company’s financial condition provided in our ~~2021~~ Annual Report on Form 10-K for the year ended December 31, 2022 (the “2022 Annual Report”) and analyzes the changes in the results of operations between the three month periods ended March 31, ~~2022~~2023 and ~~2021.~~2022. For definitions of commonly used natural gas and oil terms used in this Quarterly Report, please refer to the “Glossary of Certain Industry Terms” provided in our ~~2021~~2022 Annual Report.

The following discussion contains forward-looking statements that involve risks and uncertainties. Our actual results could differ materially from those anticipated in forward-looking statements for many reasons, including the risks described in “Cautionary Statement About Forward-Looking Statements” in the forepart of this Quarterly Report and in Item 1A, “Risk Factors” in Part I and elsewhere in our ~~2021~~2022 Annual Report. You should read the following discussion with our consolidated financial statements and the related notes included in this Quarterly Report.

OVERVIEW

Background

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

E&P. Our primary business is the development and production of natural gas as well as associated NGLs and oil, with our ongoing operations focused on the development of unconventional natural gas reservoirs located in Pennsylvania, West Virginia, Ohio and Louisiana. Our operations in Pennsylvania, West Virginia and Ohio, which we refer to as “Appalachia,” are focused on the Marcellus Shale, the Utica and the Upper Devonian unconventional natural gas and liquids reservoirs. Our operations in Louisiana, which we refer to as “Haynesville,” are primarily focused on the Haynesville and Bossier natural gas reservoirs. We also have drilling rigs located in Appalachia and Haynesville, and we provide certain oilfield products and services, principally serving our E&P operations through vertical integration. ~~In just over one year,~~Over the past three years, we have completed three strategic acquisitions which have added scale to our ~~operations and have laid the foundation for our future:~~operations:

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

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

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

The Indigo Merger and GEPH Merger ~~are the result of~~extended our ~~strategy to diversify our operations by expanding 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. ~~This expansion lowered~~These mergers progressed our ability to lower our enterprise business risk, ~~expanded~~expand our economic inventory, opportunity set and business optionality and ~~enabled immediate~~capture operating synergies and cost structure savings. ~~See~~ ~~Note 2~~ ~~to the consolidated financial statements for more information on the Mergers.~~

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.

~~Table of Contents~~

Recent Financial and Operating Results

Significant first quarter ~~2022~~2023 operating and financial results include:

Total Company

•Net income of $1,939 million, or $1.76 per diluted share, increased compared to a net loss of $2,675 million, or ($2.40) per diluted share, ~~decreased compared to net income of $80 million, or $0.12 per diluted share,~~ for the same period in ~~2021.~~2022. Net ~~loss decreased~~income increased primarily from a positive change in our net derivative position of $5.3 billiondue to an increase in the mark to market position on our unsettled hedges of approximately $4.8 billion coupled with lower derivative losses on our settled hedges of approximately $572 millionas a ~~$998 million~~result of lower commodity pricing in 2023 as compared to 2022. The increase in operating income was more than offset by a $3,736 million reduction resulting from the impact of improved forward pricing on our derivatives position, $3,063 million of which was unrealized. Excluding the change in derivatives position, net income ~~increased $981 million in the first quarter of~~from 2022 ~~compared~~ to ~~the same period in 2021, primarily as a $998 million improvement in operating income~~2023 was partially offset by ~~a $2~~

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lower operating income of $693 million ~~loss~~associated with slightly lower production and lower realized pricing, higher depreciation, depletion and amortization (“DD&A”) expense of $38 million, higher losses on ~~the early extinguishment~~debt extinguishments of ~~debt recorded in the first quarter of 2022~~$17 million and ~~a $10 million~~an increase in ~~interest expense from~~ the ~~first quarter~~income tax provision of ~~2022 as compared to the same period in 2021.~~$8 million.

•Operating income of ~~$1,299~~$606 million ~~increased~~decreased compared to operating income of ~~$301~~$1,299 million for the same period in ~~2021~~2022 on a consolidated basis. Operating income ~~increased $1,871~~decreased as an $825 million ~~as increased commodity pricing and natural gas production were~~decrease in operating revenues was only partially offset by ~~increased~~decreased operating costs of ~~$873 million.~~$132 million associated with lower pricing and slightly lower production.

•Net cash provided by operating activities of ~~$972~~$1,137 million increased ~~180%~~17% from ~~$347~~$972 million for the same period in ~~2021~~2022 which was mostly attributable to higher production due to our recently acquired Haynesville assets coupled with improved commodity pricing. This increase was partially offset by an increased loss on settled derivatives combined with an increasechanges in ~~operating expenses associated with our recently acquired Haynesville assets.~~working capital balances period over period.

•Total capital investment of ~~$544~~$665 millionin the first quarter of ~~2022~~2023 increased ~~105%~~ 22%from ~~$266~~$544 million for the same period in ~~2021~~2022 primarily due to ~~the addition of the acquired Haynesville assets.~~increases in costs attributable to inflation.

E&P

•E&P operating income of ~~$1,278~~$578 millionin the first quarter of ~~2022 increased $983~~2023 decreased $700 million, compared to the same period in ~~2021,~~2022, primarily ~~as an $1,369~~due to a $645 million ~~increase~~decrease in E&P operating revenues resulting from a ~~$2.26~~$1.40 per Mcfe ~~increase~~decrease in our realized weighted average price per Mcfe (excluding derivatives) and ~~an 156~~a 14 Bcfe ~~increase~~ decreasein production volumes ~~was only partially offset by~~combined with a ~~$386~~$55 millionincrease in E&P operating costs and ~~expenses.~~expenses attributable to inflation.

•Total net production of ~~425~~411 Bcfe, which was comprised of ~~88%~~86% natural gas and ~~12%~~14% oil and NGLs, ~~increased 58%~~decreased 3% from ~~269~~425 Bcfe in the same period in ~~2021,~~2022, primarily due to a ~~76% increase~~6% decrease in our natural gas ~~production which was driven by the Haynesville assets acquired from Indigo and GEPH in September 2021 and December 2021, respectively.~~production.

•Excluding the effect of derivatives, our realized natural gas price of ~~$4.50~~$3.22 per Mcfe ~~increased 113%~~decreased 28%, our realized oil price of ~~$86.30~~$65.92 per barrel ~~increased 79%~~decreased 24% and our realized NGL price of ~~$39.33~~$24.39 per barrel ~~increased 72%~~decreased 38%, as compared to the same period in ~~2021.~~2022. Excluding the effect of derivatives, our total weighted average realized price of ~~$4.88~~$3.48 per Mcfe ~~increased 86%~~decreased 29% from the same period in ~~2021.~~2022.

•E&P segment invested ~~$544~~$664 million in capital; drilling 3331 wells, completing 3736 wells and placing 3236 wells to sales.

Outlook

Our primary focus in ~~2022~~2023 is to maintain our production ~~profile~~capacity and improve the safety and efficiency of our operations to optimize our ability to generate free cash flow, ~~(defined below)~~further reduce debt and ~~further strengthen our balance sheet.~~return capital to shareholders (subject to market and business conditions).

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

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

•Protecting Financial Strength. We intend to protect our financial strength by lowering our leverage ratio and total debt; extending the weighted average years to maturity of our debt; lowering our cost of debt; deploying hedges to protect against downward price movement; covering our costs and meeting other financial commitments; and maintaining a strong liquidity ~~position.~~

~~Table~~position and debt maturity profile; lowering our weighted average cost of ~~Contents~~debt; and deploying hedges to balance revenue protection with commodity upside exposure.

•Focus on Execution. We are focused on operating effectively and efficiently with HSE and ESG as core values; ~~building on~~leveraging our data analytics, operating execution, strategic sourcing, vertical integration and large-scale asset development expertise; 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 ~~create a competitive advantage through executing and integrating~~enhance our enterprise returns by leveraging the scale gained from our past strategic transactions ~~that we believe will enhance~~to deliver operating synergies, drive cost savings, expand our economic inventory, lower our enterprise ~~returns~~risk profile, and ~~deliver financial synergies and operational economies. We believe these transactions lower the risk of our business,~~ expand our opportunity set ~~increase business optionality~~ and ~~build upon our demonstrated record of asset integration. We strive to deliver those benefits of strategic transactions to our business.~~optionality.

We remain committed to achieving these objectives while maintaining our commitment to being environmentally ~~conscious.~~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 by both regulators and investors, the uncertainty of natural gas, oil and NGL prices in the United States, changes in laws, regulations and investor sentiment, and other key factors described in the ~~2021~~2022 Annual Report. As such, ~~we aim to monitor and seek ways to minimize the environmental impact of our operations. Additionally,~~ 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.

~~COVID-19~~

During the first quarter of 2022, we did not experience any material impact to our ability to operate or market our production due to the direct or indirect impacts of the COVID-19 pandemic, and we continue to monitor its impact on all aspects of our business. The COVID-19 outbreak resulted in state and local governments implementing measures with various levels of stringency to help control the spread of the virus. The U.S. Department of Homeland Security classifies individuals engaged in and supporting development and production of natural gas, oil and NGLs as “essential critical infrastructure workforce,” and to date, state and local governments have followed this guidance and exempted these activities from business closures. Should this situation change, our access to supplies or workers to drill, complete and operate wells could be materially and adversely affected.

Ensuring the health and welfare of our employees, and all who visit our sites, is our top priority, and we are following all U.S. Centers for Disease Control and Prevention and state and local health department guidelines. Further, we implemented infection control measures at all our sites and put in place physical distancing measures. The degree to which the COVID-19 pandemic or any other public health crisis adversely impacts our operations will depend on future developments, which are uncertain and cannot be predicted, including, but not limited to, the duration and spread of the outbreak, its severity, the effectiveness of the vaccines and the actions to contain the virus or treat its impact, its impact on the economy and market conditions, and how quickly and to what extent normal economic and operating conditions can resume. We will continually monitor our capital investment program to take into account these changed conditions and proactively adjust our activities and plans. Therefore, while this continued matter could potentially disrupt our operations, the degree of the potentially adverse financial impact cannot be reasonably estimated at this time.

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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. ~~Restructuring charges, interest~~Interest expense, gain (loss) on derivatives, gain (loss) on early extinguishment of debt and income taxes are discussed on a consolidated basis.

E&P


		For the three months ended March 31,						For the three months ended March 31,
(in millions)	(in millions)	2022			2021				(in millions)	2023		2022
Revenues	Revenues	$	2,074		$	705			Revenues	$	1,429	$	2,074
Operating costs and expenses	Operating costs and expenses	796		(1)	410		(2)		Operating costs and expenses	851		796		(1)
Operating income	Operating income	$	1,278		$	295			Operating income	$	578	$	1,278

Gain (loss) on derivatives, settled		$	(695)		$	(22)
Loss on derivatives, settled									Loss on derivatives, settled	$	(123)	$	(695)

(1)Includes $25 million in merger-related expenses related to our Indigo and GEPH Mergers for the three months ended March 31, 2022.

~~(2)Includes $6 million in restructuring charges and $1 million in merger-related expenses for the three months ended March 31, 2021.~~

Operating Income (Loss)

•E&P segment operating income ~~increased $983~~decreased $700 millionfor the three months ended March 31, ~~2022,~~2023, compared to the same period in ~~2021. A $1,369~~2022. This was primarily due to a $645 million ~~increase~~decrease in E&P operating revenues resulting from ~~an 86% increase~~a 29% decrease in our realized weighted average price per Mcfe (excluding derivatives) and a ~~58% increase~~3% decrease in production volumes ~~was only partially offset by~~combined with a ~~$386~~$55 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 March 31,													Three months ended March 31,
(in millions except percentages)	(in millions except percentages)	Natural Gas			Oil			NGLs			Total			(in millions except percentages)	Natural Gas			Oil			NGLs			Total
2021 sales revenues (1)		$	451		$	80		$	173		$	704
2022 sales revenues (1)														2022 sales revenues (1)	$	1,690		$	110		$	272		$	2,072
Changes associated with prices	Changes associated with prices	897			49			114			1,060			Changes associated with prices	(450)			(29)			(123)			(602)
Changes associated with production volumes	Changes associated with production volumes	342			(19)			(15)			308			Changes associated with production volumes	(104)			13			52			(39)
2022 sales revenues (2)		$	1,690		$	110		$	272		$	2,072
Increase from 2021		275		%	38		%	57		%	194		%
2023 sales revenues (2)														2023 sales revenues (2)	$	1,136		$	94		$	201		$	1,431
Decrease from 2022														Decrease from 2022	(33		%)	(15		%)	(26		%)	(31		%)

(1)~~Excludes $1 million in other operating revenues for the three months ended March 31, 2021 primarily related to gas balancing.~~

~~(2)~~Excludes $2 million in other operating revenues for the three months ended March 31, 2022 primarily related to gas ~~balancing.~~balancing gains.

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

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Production Volumes

For the three months ended March 31, Increase/(Decrease)
Production volumes: 2022 2021
Natural Gas (Bcf)

Appalachia 210 214 (2)%
Haynesville (1)
166 — 100%
Total 376 214 76%
Oil (MBbls)
Appalachia 1,263 1,658 (24)%
Haynesville (1)
4 — 100%
Other 3 4 (25)%
Total 1,270 1,662 (24)%
NGL (MBbls)
Appalachia 6,919 7,577 (9)%
Other — 1 (100)%
Total 6,919 7,578 (9)%
Production volumes by area: (Bcfe)
Appalachia 259 269 (4)%
Haynesville (1)
166 — 100%
Total 425 269 58%
Production volumes by formation: (Bcfe)
Marcellus Shale 217 213 2%
Utica Shale 42 56 (25)%
Haynesville Shale (1)
105 — 100%
Bossier Shale (1)
61 — 100%
Total 425 269 58%

Production percentage:
Natural gas 88 % 79 %
Oil 2 % 4 %
NGL 10 % 17 %

~~(1)The Haynesville E&P assets were acquired through the Indigo Merger and the GEPH Merger in September 2021 and December 2021, respectively.~~


	For the three months ended March 31,				Increase/(Decrease)
Production volumes:	2023		2022
Natural Gas (Bcf)
Appalachia	193		210		(8)%
Haynesville	160		166		(4)%

Total	353		376		(6)%

Oil (MBbls)
Appalachia	1,409		1,263		12%
Haynesville	8		4		100%
Other	1		3		(67)%
Total	1,418		1,270		12%

NGL (MBbls)
Appalachia	8,240		6,919		19%



Production volumes by area: (Bcfe)
Appalachia	251		259		(3)%
Haynesville	160		166		(4)%

Total	411		425		(3)%

Production volumes by formation: (Bcfe)
Marcellus Shale	220		217		1%
Utica Shale	31		42		(26)%
Haynesville Shale	98		105		(7)%
Bossier Shale	62		61		2%

Total	411		425		(3)%

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

•E&P production volumes ~~increased~~decreased by ~~156~~14 Bcfe for the three months ended March 31, ~~2022,~~2023, compared to the same period in ~~2021,~~2022, primarily due to ~~the recent acquisitions of producing~~lower natural gas ~~and oil properties in Haynesville from Indigo in September 2021 and GEPH in December 2021. Production~~production attributable to our moderation of ~~166 Bcfe from these properties more than offset a 10 Bcfe~~activity related to the decrease in ~~Appalachia production, as compared to the same period in 2021, due to a higher capital allocation to our recently acquired Haynesville assets.~~near-term natural gas prices and inflation costs.

•Oil and NGL production ~~decreased 11%~~increased 18% for the three months ended March 31, ~~2022,~~2023, compared to the same period in ~~2021,~~2022, primarily due to ~~a higher~~management of our capital ~~allocation~~program to ~~our recently acquired Haynesville assets.~~capture more favorable liquids pricing.

Commodity Prices

The price we expect to receive for our production is a critical factor in determining the capital investments we make to develop our properties. Commodity prices fluctuate due to a variety of factors we can neither control nor predict, including increased supplies of natural gas, oil or NGLs due to greater development activities, weather conditions, political and economic events, ~~such as the response to the COVID-19 pandemic,~~ and competition from other energy sources. These factors impact supply and demand, which in turn determine the sales prices for our production. In addition to these factors, the prices we realize for our production are affected by our derivative activities as well as locational differences in market prices, including basis differentials. We will continue to evaluate the commodity price environments and adjust the pace of our activity in order to maintain appropriate liquidity and financial flexibility.

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		For the three months ended March 31,						Increase/(Decrease)	For the three months ended March 31,			Increase/(Decrease)
		2022			2021					2023					Increase/(Decrease)
Natural Gas Price:	Natural Gas Price:										Natural Gas Price:
NYMEX Henry Hub Price ($/MMBtu) (1)	NYMEX Henry Hub Price ($/MMBtu) (1)	$	4.95		$	2.69		84%			NYMEX Henry Hub Price ($/MMBtu) (1)	$	3.42					$	4.95		(31)%
Discount to NYMEX (2)	Discount to NYMEX (2)	(0.45)			(0.58)			(22)%			Discount to NYMEX (2)	(0.20)			(0.45)					56%
Average realized gas price, excluding derivatives ($/Mcf)	Average realized gas price, excluding derivatives ($/Mcf)	$	4.50		$	2.11		113%			Average realized gas price, excluding derivatives ($/Mcf)	$	3.22		$	4.50				(28)%
Gain on settled financial basis derivatives ($/Mcf)		0.01			0.19
Gain (loss) on settled commodity derivatives ($/Mcf)		(1.51)			0.03
Gain (loss) on settled financial basis derivatives ($/Mcf)											Gain (loss) on settled financial basis derivatives ($/Mcf)	(0.08)			0.01
Loss on settled commodity derivatives ($/Mcf)											Loss on settled commodity derivatives ($/Mcf)	(0.24)			(1.51)
Average realized gas price, including derivatives ($/Mcf)	Average realized gas price, including derivatives ($/Mcf)	$	3.00		$	2.33		29%			Average realized gas price, including derivatives ($/Mcf)	$	2.90		$	3.00				(3)%

Oil Price:	Oil Price:										Oil Price:
WTI oil price ($/Bbl) (3)	WTI oil price ($/Bbl) (3)	$	94.29		$	57.84		63%			WTI oil price ($/Bbl) (3)	$	76.13		$	94.29				(19)%
Discount to WTI (4)	Discount to WTI (4)	(7.99)			(9.70)			(18)%			Discount to WTI (4)	(10.21)			(7.99)					(28)%
Average oil price, excluding derivatives ($/Bbl)	Average oil price, excluding derivatives ($/Bbl)	$	86.30		$	48.14		79%			Average oil price, excluding derivatives ($/Bbl)	$	65.92		$	86.30				(24)%
Loss on settled derivatives ($/Bbl)	Loss on settled derivatives ($/Bbl)	(36.01)			(11.17)						Loss on settled derivatives ($/Bbl)	(7.75)			(36.01)
Average oil price, including derivatives ($/Bbl)	Average oil price, including derivatives ($/Bbl)	$	50.29		$	36.97		36%			Average oil price, including derivatives ($/Bbl)	$	58.17		$	50.29				16%

NGL Price:	NGL Price:										NGL Price:
Average realized NGL price, excluding derivatives ($/Bbl)	Average realized NGL price, excluding derivatives ($/Bbl)	$	39.33		$	22.86		72%			Average realized NGL price, excluding derivatives ($/Bbl)	$	24.39		$	39.33				(38)%
Loss on settled derivatives ($/Bbl)		(12.25)			(6.75)
Gain (loss) on settled derivatives ($/Bbl)											Gain (loss) on settled derivatives ($/Bbl)	0.19			(12.25)
Average realized NGL price, including derivatives ($/Bbl)	Average realized NGL price, including derivatives ($/Bbl)	$	27.08		$	16.11		68%			Average realized NGL price, including derivatives ($/Bbl)	$	24.58		$	27.08				(9)%
Percentage of WTI, excluding derivatives	Percentage of WTI, excluding derivatives	42		%	40		%				Percentage of WTI, excluding derivatives	32		%	42		%

Total Weighted Average Realized Price:	Total Weighted Average Realized Price:										Total Weighted Average Realized Price:
Excluding derivatives ($/Mcfe)	Excluding derivatives ($/Mcfe)	$	4.88		$	2.62		86%			Excluding derivatives ($/Mcfe)	$	3.48		$	4.88				(29)%
Including derivatives ($/Mcfe)	Including derivatives ($/Mcfe)	$	3.24		$	2.54		28%			Including derivatives ($/Mcfe)	$	3.18		$	3.24				(2)%

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

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

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

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

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

We regularly enter into various derivatives and other financial arrangements with respect to a portion of our projected natural gas, oil and NGL production in order to support certain desired levels of cash flow and to minimize the impact of price fluctuations, including fluctuations in locational market differentials. We refer you to Item 3, Quantitative and Qualitative Disclosures About Market Risk, and Note 8 7 to the consolidated financial statements, included in this Quarterly Report.

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The tables below present the amount of our future natural gas production in which the impact of basis volatility has been limited through derivatives and physical sales arrangements as of March 31, ~~2022:~~2023:


		Volume (Bcf)	Basis Differential			Volume (Bcf)	Basis Differential
Basis Swaps – Natural Gas	Basis Swaps – Natural Gas				Basis Swaps – Natural Gas
2022		277	$	(0.53)
2023	2023	250	(0.47)		2023	220	$	(0.63)
2024	2024	46	(0.71)		2024	46	(0.71)
2025	2025	9	(0.64)		2025	9	(0.64)

Total	Total	582			Total	275

Physical NYMEX Sales Arrangements – Natural Gas (1)	Physical NYMEX Sales Arrangements – Natural Gas (1)				Physical NYMEX Sales Arrangements – Natural Gas (1)
2022		621	$	(0.17)
2023	2023	565	(0.10)		2023	543	$	(0.13)
2024	2024	391	(0.07)		2024	504	(0.07)
2025	2025	303	(0.04)		2025	421	(0.05)
2026	2026	138	—		2026	345	(0.04)
2027	2027	126	0.01		2027	307	(0.03)
2028	2028	125	0.01		2028	285	(0.02)
2029	2029	125	0.01		2029	252	(0.01)
2030	2030	47	—		2030	105	(0.01)

Total	Total	2,441			Total	2,762

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

In addition to protecting basis, the table below presents the amount of our future production in which price is financially protected as of March 31, ~~2022:~~2023:


		Remaining 2022	Full Year 2023	Full Year 2024		Remaining 2023	Full Year 2024	Full Year 2025
Natural gas (Bcf)	Natural gas (Bcf)	982	938	279	Natural gas (Bcf)	714	583	99
Oil (MBbls)	Oil (MBbls)	3,413	2,114	603	Oil (MBbls)	2,219	1,717	41
Ethane (MBbls)	Ethane (MBbls)	4,142	1,308	—	Ethane (MBbls)	5,570	1,305	—
Propane (MBbls)	Propane (MBbls)	4,873	1,066	—	Propane (MBbls)	3,592	1,094	—
Normal Butane (MBbls)	Normal Butane (MBbls)	1,388	329	—	Normal Butane (MBbls)	591	329	—
Natural Gasoline (MBbls)	Natural Gasoline (MBbls)	1,497	359	—	Natural Gasoline (MBbls)	512	329	—
Total financial protection on future production (Bcfe)	Total financial protection on future production (Bcfe)	1,074	969	283	Total financial protection on future production (Bcfe)	789	612	99

We refer you to Note 8 7 of the consolidated financial statements included in this Quarterly Report for additional details about our derivative instruments.

Operating Costs and Expenses
For the three months ended March 31, Increase/(Decrease)
(in millions except percentages) 2022 2021
Lease operating expenses $ 401 $ 250 60%
General & administrative expenses 39

35

11%
Merger-related expenses 25 1 2,400%
Restructuring charges — 6 (100)%
Taxes, other than income taxes 57 24 138%
Full cost pool amortization 269 90 199%
Non-full cost pool DD&A 5 4 25%
Total operating costs $ 796 $ 410 94%


	For the three months ended March 31,				Increase/(Decrease)
(in millions except percentages)	2023		2022
Lease operating expenses	$	430	$	401	7%
General & administrative expenses	42		39		8%
Merger-related expenses	—		25		(100)%

Taxes, other than income taxes	67		57		18%
Full cost pool amortization	308		269		14%
Non-full cost pool DD&A	4		5		(20)%

Total operating costs	$	851	$	796	7%

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		For the three months ended March 31,						Increase/	For the three months ended March 31,				Increase/
Average unit costs per Mcfe:	Average unit costs per Mcfe:	2022			2021			(Decrease)		Average unit costs per Mcfe:	2023		2022			(Decrease)
Lease operating expenses (1)	Lease operating expenses (1)	$	0.94		$	0.93		1%		Lease operating expenses (1)	$	1.05	$	0.94		12%
General & administrative expenses	General & administrative expenses	$	0.09	(2)	$	0.13	(3)	(31)%		General & administrative expenses	$	0.10	$	0.09	(2)	11%
Taxes, other than income taxes	Taxes, other than income taxes	$	0.13		$	0.09		44%		Taxes, other than income taxes	$	0.16	$	0.13		23%
Full cost pool amortization	Full cost pool amortization	$	0.63		$	0.33		91%		Full cost pool amortization	$	0.75	$	0.63		19%

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

(2)Excludes $25 million in merger-related expenses related to the Indigo and GEPH Mergers for the three months ended March 31, 2022.

~~(3)Excludes $6 million in restructuring charges and $1 million in merger-related expenses three months ended March 31, 2021.~~

Lease Operating Expenses

•Lease operating expenses per Mcfe increased ~~$0.01~~$0.11 per Mcfe for the three months ended March 31, ~~2022,~~2023 compared to the same period in ~~2021,~~2022, primarily due to increased operating costs associated with ~~processing fees, and fuel and electricity.~~the impact of inflation.

General and Administrative Expenses

•General and administrative expenses increased $4$3 million or $0.01 per Mcfe for the three months ended March 31, ~~2022~~2023 compared to the same period in ~~2021,~~2022, primarily due to increased personnel costs associated with our expanded operations in Haynesville. General and administrative expenses decreased $0.04 per Mcfe or 31% primarily due to the increased volumes associated with the 2021 Haynesville acquisitions.period over period.

Merger-Related Expenses

•~~Beginning with the Montage Merger in 2020, we~~We focused on building scale and geographic diversification throughout 2021. As a result of this strategy, we merged with Indigo in September 2021 and GEPH on December 31, ~~2021.~~2021 which resulted in merger-related expenses during 2022. The ~~table~~tables below ~~presents~~present the charges incurred for our merger-related activities for the three months ended March 31, ~~2022 and 2021:~~2022:


		For the three months ended March 31,
		2022						2021			For the three months ended March 31, 2022
(in millions)	(in millions)	Indigo Merger		GEPH Merger		Total		Montage Merger		(in millions)	Indigo Merger		GEPH Merger		Total
Transition services	Transition services	$	—	$	18	$	18	$	—	Transition services	$	—	$	18	$	18

Professional fees (advisory, bank, legal, consulting)	Professional fees (advisory, bank, legal, consulting)	—		1		1		—		Professional fees (advisory, bank, legal, consulting)	—		1		1

Contract buyouts, terminations and transfers	Contract buyouts, terminations and transfers	—		2		2		—		Contract buyouts, terminations and transfers	—		2		2
Due diligence and environmental	Due diligence and environmental	1		—		1		—		Due diligence and environmental	1		—		1
Employee-related	Employee-related	—		1		1		1		Employee-related	—		1		1
Other	Other	—		2		2		—		Other	—		2		2
Total merger-related expenses	Total merger-related expenses	$	1	$	24	$	25	$	1	Total merger-related expenses	$	1	$	24	$	25

We refer you to Note 2 of the consolidated financial statements included in this Quarterly Report for additional details about the ~~Mergers.~~

~~Restructuring Charges~~

•~~In February 2021, employees were notified of a workforce reduction plan as part of an ongoing strategic effort to reposition our portfolio, optimize operational performance~~Indigo and improve margins. Affected employees were offered a severance package, which included a one-time cash payment depending on length of service and, if applicable, the current value of unvested long-term incentive awards that were forfeited. These costs were recognized as restructuring chargesGEPH Mergers. We had no merger-related expenses for the three months ended March 31, ~~2021 and were substantially completed by the end of the first quarter of 2021.~~

~~See~~ ~~Note 3~~ ~~of the consolidated financial statements included in this Quarterly Report for additional details about our restructuring charges.~~2023.

Taxes, Other than Income Taxes

•On a per Mcfe basis, taxes, other than income taxes may vary from period to period due to changes in ad valorem and severance taxes that result from the mix of our production volumes, ~~and~~ fluctuations in commodity ~~prices.~~prices and changes in the tax rates enacted by the respective states we operate in. Taxes, other than income taxes, per Mcfe increased ~~$0.04~~$0.03 for the three months ended March 31, ~~2022~~2023, compared to the same period in ~~2021,~~2022, primarily due to ~~the impact of~~ higher ~~commodity pricing on our severance taxes in West Virginia, which are~~

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~~calculated as fixed percentage of revenue net of allowable production expenses, and the impact of incremental severance and~~ ad valorem taxes ~~associated with our assets in Louisiana.~~period over period.

~~Full Cost Pool Amortization~~Operating Costs and Expenses


	For the three months ended March 31,				Increase/(Decrease)
(in millions except percentages)	2023		2022
Lease operating expenses	$	430	$	401	7%
General & administrative expenses	42		39		8%
Merger-related expenses	—		25		(100)%

Taxes, other than income taxes	67		57		18%
Full cost pool amortization	308		269		14%
Non-full cost pool DD&A	4		5		(20)%

Total operating costs	$	851	$	796	7%

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	For the three months ended March 31,					Increase/
Average unit costs per Mcfe:	2023		2022			(Decrease)
Lease operating expenses (1)	$	1.05	$	0.94		12%
General & administrative expenses	$	0.10	$	0.09	(2)	11%
Taxes, other than income taxes	$	0.16	$	0.13		23%
Full cost pool amortization	$	0.75	$	0.63		19%

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

(2)Excludes $25 million in merger-related expenses related to the Indigo and GEPH Mergers for the three months ended March 31, 2022.

Lease Operating Expenses

•~~Our full cost pool amortization rate~~Lease operating expenses per Mcfe increased ~~$0.30~~$0.11 per Mcfe for the three months ended March 31, ~~2022, as~~2023 compared to the same period in ~~2021,~~2022, primarily ~~as a result~~due to increased operating costs associated with the impact of ~~our acquisitions of natural gas~~inflation.

General and ~~oil properties in Haynesville.~~Administrative Expenses

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

•~~Unevaluated costs excluded from amortization were $2,228~~administrative expenses increased $3 million and $2,231 million at March 31, 2022 and at December 31, 2021, respectively. The unevaluated costs excluded from amortization decreased slightly as the impact of $224 million of unevaluated capital invested during the period was more than offset by the evaluation of previously unevaluated properties totaling $227 million.

~~Marketing~~
For the three months ended March 31, Increase/
(Decrease)
(in millions except volumes and percentages) 2022 2021
Marketing revenues $ 2,755 $ 996 177%
Other operating revenues — 1 (100)%
Marketing purchases 2,728 986 177%
Operating costs and expenses 6

5

20%
Operating income $ 21 $ 6 250%

Volumes marketed (Bcfe)
538

345 56%

Percent natural gas production marketed from affiliated E&P operations 91 %

93 %
Affiliated E&P oil and NGL production marketed 83 % 80 %

~~Operating Income~~

•~~Operating income for our Marketing segment increased $15 million~~or $0.01 per Mcfe for the three months ended March 31, ~~2022,~~2023 compared to the same period in ~~2021,~~2022, primarily due to ~~a $17 million increase in the marketing margin (discussed below) which was slightly offset by lower other operating revenues and slightly higher operating costs.~~increased personnel costs period over period.

Merger-Related Expenses

•We focused on building scale and geographic diversification throughout 2021. As a result of this strategy, we merged with Indigo in September 2021 and GEPH on December 31, 2021 which resulted in merger-related expenses during 2022. The ~~margin generated from marketing~~tables below present the charges incurred for our merger-related activities ~~was $27 million and $10 million~~ for the three months ended March 31, ~~2022~~2022:


	For the three months ended March 31, 2022
(in millions)	Indigo Merger		GEPH Merger		Total
Transition services	$	—	$	18	$	18

Professional fees (advisory, bank, legal, consulting)	—		1		1

Contract buyouts, terminations and transfers	—		2		2
Due diligence and environmental	1		—		1
Employee-related	—		1		1
Other	—		2		2
Total merger-related expenses	$	1	$	24	$	25

We refer you to Note 2 of the consolidated financial statements included in this Quarterly Report for additional details about the Indigo and 2021, respectively. The marketing margin increased in 2022, compared to the same period in 2021, primarily due to increased volumes marketed and optimization of a larger transportation portfolio due to increased volumes available for marketing.

Marketing margins are driven primarily by volumes marketed and may fluctuate depending on the prices paid for commodities, related cost of transportation and the ultimate disposition of those commodities. Increases and decreases in revenues due to changes in commodity prices and volumes marketed are largely offset by corresponding changes in purchase expenses. Efforts to optimize the cost of our transportation can result in greaterGEPH Mergers. We had no merger-related expenses ~~and therefore lower marketing margins.~~

~~Revenues~~

•~~Revenues from our marketing activities increased $1,759 million~~ for the three months ended March 31, ~~2022~~2023.

Taxes, Other than Income Taxes

•On a per Mcfe basis, taxes, other than income taxes may vary from period to period due to changes in ad valorem and severance taxes that result from the mix of our production volumes, fluctuations in commodity prices and changes in the tax rates enacted by the respective states we operate in. Taxes, other than income taxes, per Mcfe increased $0.03 for the three months ended March 31, 2023, compared to the same period in ~~2021,~~2022, primarily due to ~~a 77% increase in the price received for volumes marketed and a 193 Bcfe increase in the volumes marketed.~~higher ad valorem taxes period over period.

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Operating Costs and Expenses


	For the three months ended March 31,				Increase/(Decrease)
(in millions except percentages)	2023		2022
Lease operating expenses	$	430	$	401	7%
General & administrative expenses	42		39		8%
Merger-related expenses	—		25		(100)%

Taxes, other than income taxes	67		57		18%
Full cost pool amortization	308		269		14%
Non-full cost pool DD&A	4		5		(20)%

Total operating costs	$	851	$	796	7%

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	For the three months ended March 31,					Increase/
Average unit costs per Mcfe:	2023		2022			(Decrease)
Lease operating expenses (1)	$	1.05	$	0.94		12%
General & administrative expenses	$	0.10	$	0.09	(2)	11%
Taxes, other than income taxes	$	0.16	$	0.13		23%
Full cost pool amortization	$	0.75	$	0.63		19%

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

(2)Excludes $25 million in merger-related expenses related to the Indigo and GEPH Mergers for the three months ended March 31, 2022.

Lease Operating Expenses

•Lease operating expenses per Mcfe increased $0.11 per Mcfe for the three months ended March 31, 2023 compared to the same period in 2022, primarily due to increased operating costs associated with the impact of inflation.

General and Administrative Expenses

•General and administrative expenses increased $3 million or $0.01 per Mcfe for the three months ended March 31, 2023 compared to the same period in 2022, primarily due to increased personnel costs period over period.

Merger-Related Expenses

•We focused on building scale and geographic diversification throughout 2021. As a result of this strategy, we merged with Indigo in September 2021 and GEPH on December 31, 2021 which resulted in merger-related expenses during 2022. The tables below present the charges incurred for our merger-related activities for the three months ended March 31, 2022:


	For the three months ended March 31, 2022
(in millions)	Indigo Merger		GEPH Merger		Total
Transition services	$	—	$	18	$	18

Professional fees (advisory, bank, legal, consulting)	—		1		1

Contract buyouts, terminations and transfers	—		2		2
Due diligence and environmental	1		—		1
Employee-related	—		1		1
Other	—		2		2
Total merger-related expenses	$	1	$	24	$	25

We refer you to Note 2 of the consolidated financial statements included in this Quarterly Report for additional details about the Indigo and GEPH Mergers. We had no merger-related expenses for the three months ended March 31, 2023.

Taxes, Other than Income Taxes

•On a per Mcfe basis, taxes, other than income taxes may vary from period to period due to changes in ad valorem and severance taxes that result from the mix of our production volumes, fluctuations in commodity prices and changes in the tax rates enacted by the respective states we operate in. Taxes, other than income taxes, per Mcfe increased $0.03 for the three months ended March 31, 2023, compared to the same period in 2022, primarily due to higher ad valorem taxes period over period.

Full Cost Pool Amortization

•Our full cost pool amortization rate increased $0.12 per Mcfe for the three months ended March 31, 2023, as compared to the same period in 2022, primarily as a result of increases in development costs as a result of inflation.

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

•Unevaluated costs excluded from amortization were $2,185 million and $2,217 million at March 31, 2023 and December 31, 2022, respectively. The unevaluated costs excluded from amortization decreased as the impact of $56

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million of unevaluated capital invested during the period was more than offset by the evaluation of previously unevaluated properties totaling $88 million.

Marketing


	For the three months ended March 31,						Increase/ (Decrease)
(in millions except volumes and percentages)	2023			2022
Marketing revenues	$	2,041		$	2,755		(26)%
Other operating revenues	—			—			—%
Marketing purchases	2,007			2,728			(26)%
Operating costs and expenses	6			6			—%


Operating income	$	28		$	21		33%

Volumes marketed (Bcfe)	551			538			2%

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

Operating Income

•Operating income for our Marketing segment increased $7 million for the three months ended March 31, 2023, compared to the same period in 2022, primarily due to a $7 million increase in the marketing margin (discussed below).

•The margin generated from marketing activities was $34 million and $27 million for the three months ended March 31, 2023 and 2022, respectively. The marketing margin increased for the three months ended March 31, 2023, compared to the same period in 2022, primarily from utilizing existing transportation capacity to take advantage of low in-basin pricing on the purchase and sale of third-party natural gas.

Revenues

•Revenues from our marketing activities decreased $714 million for the three months ended March 31, 2023, respectively, as compared to the same period in 2022. The decrease was primarily due to a 28% decrease in the price received for volumes marketed for the three months ended March 31, 2023, partially offset by a 13 Bcfe increase in the volumes marketed for the three months ended March 31, 2023, as compared to the same period in 2022.

Operating Costs and Expenses

•Operating costs and expenses for the marketing segment ~~increased by $1 million~~remained flat for the three months ended March 31, ~~2022~~2023 compared to the same period in ~~2021, primarily due to increased personnel costs associated with the 2021 Haynesville acquisitions.~~2022.

Consolidated

Interest Expense


		For the three months ended March 31,				Increase/(Decrease)	For the three months ended March 31,				Increase/(Decrease)
(in millions except percentages)	(in millions except percentages)	2022		2021				(in millions except percentages)	2023				Increase/(Decrease)
Gross interest expense:	Gross interest expense:									Gross interest expense:
Senior notes	Senior notes	$	58	$	44	32%				Senior notes	$	56			$	58		(3)%
Credit arrangements	Credit arrangements	10		6		67%				Credit arrangements	7		10				(30)%
Amortization of debt costs	Amortization of debt costs	3		3		—%				Amortization of debt costs	3		3				—%
Total gross interest expense	Total gross interest expense	71		53		34%				Total gross interest expense	66		71				(7)%
Less: capitalization	Less: capitalization	(30)		(22)		36%				Less: capitalization	(30)		(30)				—%
Net interest expense	Net interest expense	$	41	$	31	32%				Net interest expense	$	36	$	41			(12)%

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•Interest expense ~~related to our senior notes increased~~decreased for the three months ended March 31, ~~2022,~~2023, compared to the same period in ~~2021, as a result of~~2022, due to lower revolver borrowings and the ~~assumption of Indigo Notes, which were exchanged for $700 million aggregate principal amount~~effects of our ~~5.375%~~debt repurchase activity in 2022 and the full redemption of our 7.75% Senior Notes due ~~2029,~~2027 during the ~~September 2021 public offering~~first quarter of ~~$1,200 million aggregate principal amount of our 5.375% Senior Notes due 2030, and the December 2021 public offering of $1,150 million aggregate principal amount of our 4.75% Senior Notes due 2032.~~2023.

•Capitalized interest ~~increased~~remained flat for the three months ended March 31, ~~2022,~~2023, as compared to the same period in ~~2021, primarily due to the incremental capitalized interest associated with the recently acquired Haynesville unevaluated properties.~~2022.

•Capitalized interest as a percentage of gross interest expense ~~remained flat~~increased for the three months ended March 31, ~~2022,~~2023, compared to the same period in ~~2021.~~2022, primarily related to a smaller percentage change in our unevaluated natural gas and oil properties balance as compared to the larger percentage decrease in our gross interest expense over the same period.

•We refer you to Note 111 0 to the consolidated financial statements included in this Quarterly Report for additional details about our debt and our financing activities.

Gain (Loss) on Derivatives


		For the three months ended March 31,				For the three months ended March 31,

(in millions)	(in millions)	2022		2021			(in millions)	2023		2022
Loss on unsettled derivatives		$	(3,237)	$	(169)
Gain (loss) on unsettled derivatives							Gain (loss) on unsettled derivatives	$	1,528	$	(3,237)
Loss on settled derivatives	Loss on settled derivatives	(695)		(22)			Loss on settled derivatives	(123)		(695)
Non-performance risk adjustment	Non-performance risk adjustment	5		—			Non-performance risk adjustment	(4)		5
Loss on derivatives		$	(3,927)	$	(191)
Gain (loss) on derivatives							Gain (loss) on derivatives	$	1,401	$	(3,927)

We refer you to Note 8 7 to the consolidated financial statements included in this Quarterly Report for additional details about our gain (loss) on derivatives.

Gain/Loss on Early Extinguishment of Debt

During the three months ended March 31, 2023, we redeemed all of the outstanding 7.75% Senior Notes due 2027 at a redemption price equal to 103.875% of the principal amount thereof plus accrued and unpaid interest of $13 million for a total payment of $450 million. We recognized a $19 million loss on the extinguishment of debt, which included the write off of $3 million in related unamortized debt discounts and debt issuance costs.

For the three months ended March 31, 2022, we recorded a loss on early debt extinguishment of $2 million as a result of our repurchase of ~~$221~~$221 million in aggregate principal amount of our outstanding senior notes for $223 million. Included as part of the repurchase was the full redemption of our 4.10% Senior Notes due March 2022 with an aggregate principal amount retired of $201 million.

See Note 111 0 to the consolidated financial statements of this Quarterly Report for more information on our long-term debt.

Income Taxes


	For the three months ended March 31,
(in millions except percentages)	2023			2022
Income tax expense	$	12		$	4
Effective tax rate	1		%	0		%

Our effective tax rate was approximately 1% and 0% for the three months ended March 31, 2023 and 2022, respectively, primarily as a result of the release of the valuation allowances against our U.S. deferred tax assets. A valuation allowance for deferred tax assets, including NOLs, is recognized when it is more likely than not that some or all of the benefit from the deferred tax assets will not be realized. To assess that likelihood, we used estimates and judgment regarding future taxable income and considered the tax consequences in the jurisdiction where such taxable income is generated, to determine whether a valuation allowance is required. Such evidence can include current financial position, results of operations, both actual and forecasted, the reversal of deferred tax liabilities and tax planning strategies as well as the current and forecasted business economics of the oil and gas industry.

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~~Income Taxes~~
For the three months ended March 31,
(in millions except percentages) 2022 2021
Income tax expense $ 4 $ —
Effective tax rate 0 % 0 %

~~In 2020, due to significant pricing declines~~million of its federal and ~~the material write-down of the carrying value of our natural gas and oil properties in addition to other negative evidence, management concluded that it was~~state deferred tax assets were more likely than not ~~that a portion of our deferred tax assets would not~~to be realized and ~~recorded a~~plan to release this portion of the valuation allowance in 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. ~~As of the first quarter of 2022, we still maintain a full~~The remaining valuation ~~allowance. We also retained~~allowance will be released during subsequent quarters during 2023. The Company expects to keep a valuation allowance of ~~$59~~$66 million related to ~~net operating losses~~NOLs in jurisdictions in which weit no longer ~~operate. Management will continue to assess available positive~~operates and ~~negative evidence to estimate whether sufficient future taxable income will be generated to permit~~against the ~~use~~portion of deferred tax assets. The amount of the deferred tax asset considered realizable, however, could be adjusted based on changes in subjective estimates of future taxable income or if objective negative evidence is no longer present.

~~We expect to continue a full valuation allowance on~~ our federal and state deferred tax assets ~~until there is sufficient evidence~~such as capital losses and interest carryovers, which may expire before being fully utilized due to ~~support~~ the ~~reversal of all or some portion~~application of the ~~allowance. However, if current commodity prices are sustained~~limitations under Section 382 and ~~absent any additional objective negative evidence, it is reasonably possible that sufficient positive evidence will exist within~~ the ~~next 12 months to adjust the current valuation allowance position. Exact timing and amount of the adjustment to the valuation allowance is unknown at this time.~~ordering in which such attributes may be applied.

Due to the issuance of common stock associated with the Indigo Merger, ~~as discussed in~~ ~~Note 2~~, we incurred a cumulative ownership change and as such, our ~~net operating losses (“NOLs”)~~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, with a corresponding decrease in our valuation allowance.~~available. At March 31, ~~2022,~~2023, we had approximately $4 billion of federal NOL carryovers, of which approximately $3 billion have an expiration date between 2035 and 2037 and $1 billion have an indefinite carryforward life. We currently estimate that approximately $2 billion of these federal NOLs will expire before they are able to be ~~used. The non-expiring~~used and accordingly, no value has been ascribed to these NOLs ~~remain subject to a full valuation allowance.~~on our balance sheet. If a subsequent ownership change were to occur as a result of future transactions in our common stock, our use of remaining U.S. tax attributes may be further limited.

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

New Accounting Standards Implemented in this Report

Refer to Note 171 6 to the consolidated financial statements of this Quarterly Report for a discussion of new accounting standards that have been implemented.

New Accounting Standards Not Yet Implemented in this Report

Refer to Note 171 6 to the consolidated financial statements of this Quarterly Report for a discussion of new accounting standards that have not yet been implemented.

LIQUIDITY AND CAPITAL RESOURCES

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

Effective August 4, 2022, we elected to temporarily increase by $500 million our commitments under the ~~2018~~2022 credit facility ~~throughout this Quarterly Report as it was~~ in ~~effect as~~the form of ~~the quarter ended~~an additional tranche of short-term revolving commitments (the “Short-Term Tranche”). Through March 31, ~~2022.~~2023, we have had no borrowings under the Short-Term Tranche and the short-term commitments will expire on April 30, 2023.

~~We depend primarily on funds generated from~~On April 5, 2023, our operations, our 2018 credit facility, our cash and cash equivalents balance and capital markets as our primary sources of liquidity. In October 2021, the banks participating in our 2018 credit facility reaffirmed our elected borrowing base was reaffirmed at $3.5 billion and ~~aggregate commitments to be~~both our Five-Year Tranche and Short-Term Tranche were reaffirmed at $2.0 ~~billion.~~billion and $500 million, respectively. At March 31, ~~2022,~~2023, we had approximately ~~$1.7~~$2.2 billion of total available liquidity, which exceeds our currently modeled needs as we remain committed to our strategy of capital discipline.

In November 2021 in conjunction with the GEPH Merger, we amended our 2018 credit facility agreement to permit access to additional secured debt capacity in the form of a term loan for incremental capital up to $900 million, ranking equally with our 2018 credit facility. In December 2021, we raised $550 million in term loan financing to partially fund the GEPH Merger, with no impact to our liquidity. As of March 31, 2022 we had borrowings under the term loan of $549 million. The remaining $351 million of incremental term loan capacity remains accessible through November 2022 and provides access to another

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~~secured debt capital source for liquidity purposes. The flexibility to access this term loan capacity through November 2022 is included in our 2022 credit facility.~~

Our flexibility to access incremental secured debt capital is derived from our excess asset collateral value above the elected $3.5 billion maximum revolving credit amount and borrowing base of our 2022 credit facility and the elected ~~$2.0 billion of~~ aggregate revolving commitments from our bank group. Our ability to issue secured debt is governed by the limitations of our 2022 credit facility as well as our secured debt capacity (as defined by our senior note indentures) which was ~~$6.5~~$5.6 billion as of March 31, ~~2022,~~2023, based on 25% of adjusted consolidated net tangible assets. If we were to realize a return to investment grade ratings and the subsequent conversion of our secured credit facility to an unsecured credit facility, we would expect to have access to additional liquidity capital beyond our elected aggregate revolving commitments, either by increasing commitments to the 2022 credit facility up to the $3.5 billion aggregate size or otherwise on a similarly unsecured basis, given our current ~~excess~~ asset collateral value and credit quality.

Throughout 2022, we expect to continue to generate free cash flow, which is defined as cash flow from operations, net of changes in working capital, in excess of our expected capital investments, and we intend to utilize free cash flow to pay down our debt. We refer you to Note 1 110 to the consolidated financial statements included in this Quarterly Report and the section below under “Credit Arrangements and Financing Activities” for additional discussion of our 2022 credit facility and related covenant requirements.

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

Looking forward, we intend to prioritize the use of any free cash flow to pay down our debt in order to progress toward our debt and leverage targets.

Our cash flow from operating activities is highly dependent upon our ability to sell and the sales prices that we receive for our natural gas and liquids production. Natural gas, oil and NGL prices are subject to wide fluctuations and are driven by market supply and demand, which is impacted by many factors. See "Risk Factors" in Item 1A of our ~~2021~~2022 Annual Report for additional discussion about current and potential future market conditions. The sales price we receive for our production is also influenced by our commodity derivative program. Our derivative contracts allow us to support a certain level of cash flow to fund our operations. Although we are continually assessing adding ~~additional~~ derivative positions for portions of our expected ~~2022,~~ 2023, 2024, and ~~2024~~2025 production, there can be no assurance that we will be able to add derivative positions to cover the remainder of our expected production at favorable prices. We again refer you to “Risk Factors” in Item 1A of our ~~2021~~2022 Annual Report.

Our commodity hedging activities are subject to the credit risk of our counterparties being financially unable to settle the transaction. We actively monitor the credit status of our counterparties, performing both quantitative and qualitative assessments based on their credit ratings and credit default swap rates where applicable, and to date have not had any credit defaults associated with our transactions. However, any future failures by one or more counterparties could negatively impact our cash flow from operating activities. Additionally, we do not expect recent developments within the banking industry to have a material impact on our expected results of operations, financial performance, or liquidity. However, if there are issues in the wider financial system and if other financial institutions fail, our business, liquidity and financial condition could be materially affected, including as a result of impacts of any such issues or failures on our counterparties.

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

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

Credit Arrangements and Financing Activities

In April 2018, we entered into a revolving credit facility (the “2018 credit facility”) with a group of banks that, as amended, has a maturity date of April 2024. The 2018 credit facility has an aggregate maximum revolving credit amount of $3.5 billion and, in October 2021, the banks participating in our 2018 credit facility reaffirmed the elected borrowing base to be $2.0 billion, which also reflected our aggregate commitments. The borrowing base is subject to redetermination at least twice a year, which typically occurs in April and October, and is subject to change based primarily on drilling results, commodity prices, our future derivative position, the level of capital investment and operating costs. The 2018 credit facility is secured by substantially all of our assets and our subsidiaries’ assets (taken as a whole). The permitted lien provisions in the senior note indentures currently limit liens securing indebtedness to the greater of $2.0 billion or 25% of adjusted consolidated net tangible assets. We may utilize the 2018 credit facility in the form of loans and letters of credit. As of March 31, 2022, we had $174 million of borrowings on our 2018 credit facility and $147 million in outstanding letters of credit. We currently do not anticipate being required to supply a materially greater amount of letters of credit under our existing contracts. We refer you to ~~Note 11~~ ~~to the consolidated financial statements included in this Quarterly Report for additional discussion of our 2018 credit facility.~~

As of March 31, 2022, we were in compliance with all of the applicable covenants contained in the credit agreement governing our 2018 credit facility. Our ability to comply with financial covenants in future periods depends, among other

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~~things, on the success of our development program and upon other factors beyond our control, such as the market demand and prices for natural gas and liquids. We refer you to~~ ~~Note 11~~ ~~of the consolidated financial statements included in this Quarterly Report for additional discussion of the covenant requirements of our 2018 credit facility.~~

In April 2022, we entered into an amended and restated credit agreement that ~~replaces~~replaced the 2018 credit facility (the “2022 credit facility”) with a group of banks that, as amended, has a maturity date of April 2027. The 2022 credit facility has an

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aggregate maximum revolving credit amount and borrowing base of $3.5 billion and, as of March 31, 2023, elected commitments comprised of the Five-Year Tranche and Short-Term Tranche of $2.0 ~~billion.~~ billion and $500 million, respectively. On April 5, 2023, our borrowing base was reaffirmed at $3.5 billion and both the Five-Year Tranche and Short-Term Tranche were reaffirmed at $2.0 billion and $500 million, respectively. The Short-Term Tranche will expire on April 30, 2023.

The borrowing base is subject to redetermination at least twice a year, which typically occurs in April and October, and is subject to change based primarily on drilling results, commodity prices, our future derivative position, the level of capital investment and operating costs. The 2022 credit facility is secured by substantially all of our assets and our subsidiaries’ assets (taken as a whole). The permitted lien provisions in the senior note indentures currently limit liens securing indebtedness to the greater of $2.0 billion or 25% of adjusted consolidated net tangible assets, which was ~~$6.5~~$5.6 billion as of March 31, ~~2022.~~2023. The 2022 credit facility ~~utilizes~~contains the ability to utilize SOFR index rates for purposes of calculating interest expense.

The 2022 credit facility has certain financial covenant requirements ~~that currently mirror those of our 2018 credit facility,~~ but ~~provide~~provides certain fall away features should we receive an Investment Grade Rating (defined as an index debt rating of BBB- or higher with S&P, Baa3 or higher with Moody’s, or BBB- or higher with Fitch) and meet other criteria in the future. We refer you to Note 111 0 to the consolidated financial statements included in this Quarterly Report for additional discussion of our 2022 credit facility.

As of March 31, 2023, we were in compliance with all of the applicable covenants contained in the credit agreement governing our 2022 credit facility. Our ability to comply with financial covenants in future periods depends, among other things, on the success of our development program and upon other factors beyond our control, such as the market demand and prices for natural gas, oil and NGLs. We refer you to Note 1 0 of the consolidated financial statements included in this Quarterly Report for additional discussion of the covenant requirements of our 2022 credit facility.

As of March 31, 2023, we had $210 million of borrowings on our 2022 credit facility and $89 million in outstanding letters of credit. We currently do not anticipate being required to supply a materially greater amount of letters of credit under our existing contracts. We refer you to Note 1 0 to the consolidated financial statements included in this Quarterly Report for additional discussion of our 2022 credit facility.

The credit status of the financial institutions participating in our 2022 credit facility could adversely impact our ability to borrow funds under the 2022 credit facility. Although we believe all of the lenders under the facility have the ability to provide funds, we cannot predict whether each will be able to meet their obligation to us. We refer you to Note 111 0 to the consolidated financial statements included in this Quarterly Report for additional discussion of our revolving credit facility.

In contemplation of the GEPH Merger, on December 22, 2021, we entered into a term loan credit agreement with a group of lenders that provided for a $550 million secured term loan facility which matures on June 22, 2027 (the “Term Loan”). As of March 31, 2022, we had borrowings under the Term Loan of $549 million.

Other key financing activities over the last 3three months are as follows:

Debt Repurchases

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

•In January 2022, we repurchased the remaining outstanding principal balance of $201 million on our 2022 ~~Senior Notes~~senior notes using our ~~2018~~ credit facility. As a result of the focused work on refinancing and repayment of our debt in recent years, coupled with the amendment and restatement of our credit facility on April 8, 2022, ~~the only~~none of our outstanding debt balance is scheduled to become due prior to ~~2025 is $15 million of our Term Loan principal.~~2025.

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

As of April ~~26, 2022,~~25, 2023, we had long-term debt issuer ratings of ~~Ba2~~Ba1 by Moody’s (rating upgraded and stable outlook affirmed on ~~November 29, 2021)~~May 31, 2022), BB+ by S&P (rating upgraded to BB+ ~~with stable~~and outlook upgraded to positive on January ~~6, 2022)~~18, 2023) and BBBB+ by Fitch Ratings (rating ~~and stable~~upgraded to BB+ with positive outlook ~~affirmed~~ on ~~November 29, 2021)~~August 10, 2022). Effective in ~~July 2018,~~January 2022, the interest rate for our 4.95% senior notes due January 2025 ~~Notes~~(“2025 Notes”) was ~~6.20%~~5.95%, reflecting a net downgrade in our bond ratings since their issuance. ~~In April 2020, S&P downgraded~~On May 31, 2022, Moody’s upgraded our bond rating to ~~BB-,~~Ba1, which ~~had the effect of increasing~~decreased the interest rate on the 2025 Notes from 5.95% to 6.45% in July 2020, with the first coupon payment at the higher interest rate in January 2021. On September 1, 2021, S&P upgraded our bond rating to BB, and on January 6, 2022 S&P further upgraded our bond rating to BB+, which will have the effect of decreasing the interest rate on the 2025 Notes to 5.95%, beginning with5.70% for coupon payments paid after ~~January~~July 2022. Any further upgrades or downgrades in our public debt ratings by Moody’s or S&P could decrease or increase our cost of funds, respectively, as our 2025 ~~senior notes~~Notes are subject to ratings driven changes.

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Cash Flows


		For the three months ended March 31,					For the three months ended March 31,
(in millions)	(in millions)	2022		2021		(in millions)	2023		2022
Net cash provided by operating activities	Net cash provided by operating activities	$	972	$	347	Net cash provided by operating activities	$	1,137	$	972
Net cash used in investing activities	Net cash used in investing activities	(500)		(227)		Net cash used in investing activities	(670)		(500)
Net cash used in financing activities	Net cash used in financing activities	(479)		(129)		Net cash used in financing activities	(514)		(479)

Cash Flow from Operations


		For the three months ended March 31,					For the three months ended March 31,
(in millions)	(in millions)	2022		2021		(in millions)	2023		2022
Net cash provided by operating activities	Net cash provided by operating activities	$	972	$	347	Net cash provided by operating activities	$	1,137	$	972
Add back (subtract) changes in working capital	Add back (subtract) changes in working capital	(136)		—		Add back (subtract) changes in working capital	(373)		(136)
Net cash provided by operating activities, net of changes in working capital	Net cash provided by operating activities, net of changes in working capital	$	836	$	347	Net cash provided by operating activities, net of changes in working capital	$	764	$	836

•Net cash provided by operating activities increased ~~180%~~17%, or ~~$625~~$165 million, for the three months ended March 31, ~~2022,~~2023, compared to the same period in ~~2021,~~2022, primarily due to a ~~$1,060~~$572 million improvement in our settled derivative losses, $237 million increase ~~resulting from higher commodity prices, a $308 million increase related to increased production, a $136 million increased impact of~~in working capital, ~~and~~ a ~~$17~~$7 million increase in our marketing margin, and a $5 million decrease in interest expense partially offset by a ~~$673~~$602 million decrease ~~in our settled derivatives,~~resulting from lower commodity prices, a ~~$188~~$39 million decrease related to decreased production, and a $17 million increase in operating costs and ~~expenses and a $10 million increase in interest expense.~~expenses.

•Net cash provided by operating activities, net of changes in working capital, exceeded our cash requirements for capital investments for the three months ended March 31, ~~2022~~2023 and ~~2021.~~2022.

Cash Flow from Investing Activities

•Total E&P capital investments increased ~~$278~~$120 million for the three months ended March 31, ~~2022,~~2023, compared to the same period in ~~2021,~~2022, primarily attributable to higher costs due to an increase of $306 million related to our newly acquired Haynesville assets partially offset by a $28 million decrease in our Appalachia investment due to higher capital allocation to our recently acquired Haynesville assets.inflation.


		For the three months ended March 31,					For the three months ended March 31,
(in millions)	(in millions)	2022		2021		(in millions)	2023		2022
Additions to properties and equipment	Additions to properties and equipment	$	500	$	227	Additions to properties and equipment	$	670	$	500
Adjustments for capital investments	Adjustments for capital investments					Adjustments for capital investments
Changes in capital accruals	Changes in capital accruals	43		38		Changes in capital accruals	(6)		43
Other (1)	Other (1)	1		1		Other (1)	1		1
Total capital investing	Total capital investing	$	544	$	266	Total capital investing	$	665	$	544

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

Capital Investing


		For the three months ended March 31,				Increase/(Decrease)	For the three months ended March 31,				Increase/(Decrease)
(in millions except percentages)	(in millions except percentages)	2022		2021				(in millions except percentages)	2023				Increase/(Decrease)
E&P capital investing	E&P capital investing	$	544	$	266	105%				E&P capital investing	$	664			22%
Other capital investing (1)	Other capital investing (1)	—		—		—%				Other capital investing (1)	1				—		100%
Total capital investing	Total capital investing	$	544	$	266	105%				Total capital investing	$	665	$	544		22%

(1)Other capital investing ~~was immaterial~~relates to information technology purchases for the three months ended March 31, ~~2022 and 2021.~~2023.

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		For the three months ended March 31,				For the three months ended March 31,
(in millions)	(in millions)	2022		2021			(in millions)	2023		2022
E&P Capital Investments by Type:	E&P Capital Investments by Type:						E&P Capital Investments by Type:
Development and exploration, including workovers	Development and exploration, including workovers	$	460	$	215		Development and exploration, including workovers	$	584	$	460
Acquisition of properties	Acquisition of properties	26		10			Acquisition of properties	24		26

Other	Other	4		4			Other	5		4
Capitalized interest and expenses	Capitalized interest and expenses	54		37			Capitalized interest and expenses	51		54
Total E&P capital investments	Total E&P capital investments	$	544	$	266		Total E&P capital investments	$	664	$	544

E&P Capital Investments by Area:	E&P Capital Investments by Area:						E&P Capital Investments by Area:
Appalachia	Appalachia	$	235	$	263		Appalachia	$	276	$	235
Haynesville ~~(1)~~	Haynesville ~~(1)~~	306		—			Haynesville ~~(1)~~	381		306
Other E&P	Other E&P	3		3			Other E&P	7		3
Total E&P capital investments	Total E&P capital investments	$	544	$	266		Total E&P capital investments	$	664	$	544

~~(1)Our Haynesville assets were acquired in part on September 1, 2021 through the Indigo Merger and additional Haynesville assets were acquired on December 31, 2021 through the GEPH Merger.~~


		For the three months ended March 31,		For the three months ended March 31,
		2022	2021			2023	2022
Gross Operated Well Count Summary:	Gross Operated Well Count Summary:				Gross Operated Well Count Summary:
Drilled	Drilled	33	23		Drilled	31	33
Completed	Completed	37	29		Completed	36	37
Wells to sales	Wells to sales	32	17		Wells to sales	36	32

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

Cash Flow from Financing Activities

•For the three months ended March 31, 2022, we fully redeemed our 4.10% Senior Notes due 2022 for $201 million and paid down additional aggregate principal balances on our senior notes of $20 million and paid down $286 million on our ~~2018 credit facility.~~

•~~In the first three months of 2021, we paid down $133 million on our 2018~~2022 credit facility.

We refer you to Note 111 0 of the consolidated financial statements included in this Quarterly Report for additional discussion of our outstanding debt and credit facilities.

Working Capital

We had negative working capital of ~~$4,432~~$967 million at March 31, ~~2022, a $2,793~~2023, an $850 million ~~decrease~~increase from December 31, ~~2021, and mostly~~2022, primarily attributable to a ~~$2,741~~$1,226 million ~~reduction~~increase in the current mark-to-market value of our derivatives position related to ~~improved forward~~commodity pricing ~~across all commodities,~~declines, a ~~reduction in accounts receivable of $89 million, and an increase~~decrease in our accounts payable of ~~$206~~$286 million, a decrease of interest payables of $59 million, a decrease in other current liabilities of $36 million and a decrease in taxes payable of $27 million, which was partially offset by ~~the full repayment~~a decrease in accounts receivable of ~~our 4.10% Senior Notes of $201~~$734 million, and ~~decreases to various payables~~cash and cash equivalents of ~~$48~~$47 million as compared to December 31, ~~2021.~~2022. We believe that our existing cash and cash equivalents, our anticipated cash flows from operations and our available 2022 credit facility will be sufficient to meet our working capital and operational spending requirements.

Off-Balance Sheet Arrangements

We may enter into off-balance sheet arrangements and transactions that can give rise to material off-balance sheet obligations. As of March 31, ~~2022,~~2023, our material off-balance sheet arrangements and transactions include operating service arrangements and ~~$147~~$89 million in letters of credit outstanding against our ~~2018~~2022 credit facility. There are no other transactions, arrangements or other relationships with unconsolidated entities or other persons that are reasonably likely to materially affect our liquidity or availability of our capital resources. For more information regarding off-balance sheet arrangements, we refer you to “Contractual Obligations and Contingent Liabilities and Commitments” below for more information.

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Contractual Obligations and Contingent Liabilities and Commitments

We have various contractual obligations in the normal course of our operations and financing activities. Other than the firm transportation and gathering agreements discussed below, there have been no material changes to our contractual obligations from those disclosed in our ~~2021~~2022 Annual Report.

Contingent Liabilities and Commitments

As of March 31, ~~2022,~~2023, we had commitments for demand and similar charges under firm transportation and gathering agreements to guarantee access capacity on natural gas and liquids pipelines and gathering systems totaling approximately ~~$10.2~~$10 billion, ~~$857 million~~$1.3 billion of which related to access capacity on future pipeline and gathering infrastructure projects that still require the granting of regulatory approvals and/or additional construction efforts. This amount also included guarantee obligations of up to ~~$877~~$853 million. As of March 31, ~~2022,~~2023, future payments under non-cancelable firm transportation and gathering agreements are as follows:


		Payments Due by Period													Payments Due by Period
(in millions)	(in millions)	Total		Less than 1 Year		1 to 3 Years		3 to 5 Years		5 to 8 years		More than 8 Years		(in millions)	Total		Less than 1 Year		1 to 3 Years		3 to 5 Years		5 to 8 years		More than 8 Years
Infrastructure currently in service	Infrastructure currently in service	$	9,301	$	1,066	$	1,943	$	1,729	$	2,085	$	2,478	Infrastructure currently in service	$	8,703	$	1,045	$	1,892	$	1,692	$	1,833	$	2,241
Pending regulatory approval and/or construction (1)	Pending regulatory approval and/or construction (1)	857		3		124		161		247		322		Pending regulatory approval and/or construction (1)	1,302		38		218		262		368		416
Total transportation charges	Total transportation charges	$	10,158	$	1,069	$	2,067	$	1,890	$	2,332	$	2,800	Total transportation charges	$	10,005	$	1,083	$	2,110	$	1,954	$	2,201	$	2,657

(1)Based on the estimated in-service dates as of March 31, ~~2022.~~2023.

Prior to ~~the Indigo Merger, in May~~January 1, 2021, Indigo closed on an agreement to divest its Cotton Valley natural gas and oil properties. Indigo retained certain contractual commitments related to volume commitments associated with natural gas gathering, for which we will assume the obligation to pay the gathering provider for any unused portion of the volume commitment under the agreement through 2027, depending on the buyer’s actual use. As of March 31, 2022, up to approximately $34 million of these contractual commitments remain (included in the table above), and we have recorded a $17 million liability for the estimated future payments.

Excluding the Cotton Valley gathering agreement (discussed above), the Company has recorded additional liabilities totaling $35 million as of March 31, 2022, primarily related to purchase or volume commitments associated with gathering, fresh water and sand. These amounts are reflected above and will be recognized as payments are made over the next two years.

~~Substantially~~substantially all of our employees ~~who~~ were ~~employed prior to January 1, 2021 are~~ covered by the defined benefit ~~and postretirement benefit plans.~~pension plan, a cash balance plan that provided benefits based upon a fixed percentage of an employee’s annual compensation (the “Plan”). As part of an ongoing effort to reduce costs, we elected to freeze the ~~pension plan~~Plan effective January 1, 2021. Employees ~~who~~that were participants in the ~~pension plan~~Plan prior to January 1, 2021 continued to receive the interest component of the ~~plan~~Plan but no longer received the service component.

On September 13, 2021, the Compensation Committee of the Board ~~of Directors~~ approved terminating ~~our pension plan,~~the Plan, effective December 31, 2021. This decision, among other benefits, will provide ~~plan~~Plan participants quicker access to, and greater flexibility in, the management of participants’ respective benefits due under the ~~plan.~~ Plan.

We have commenced the ~~pension plan~~Plan termination process, ~~but~~and, on April 6, 2022, the ~~specific date for~~Internal Revenue Service issued a favorable determination letter, concurring that the ~~completion~~Plan met all of the ~~process is unknown at this time~~qualification requirements under the Internal Revenue Code. In December 2022, we distributed approximately 40% 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 ~~will depend on certain legal and regulatory requirements or approvals. As~~former employee participants as part of the Plan termination ~~process,~~process.

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

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

For the three months ended March 31, ~~2022,~~2023, we have not made contributions to the pension ~~and~~plan or postretirement benefit plans, and we do not expect to contribute additional funds to our pension plan during the remainder of ~~2022.~~2023. We recognized assets of $13 million and $15 million related to our pension plan benefits and liabilities of ~~$25~~$10 million and $9 million related to our other postretirement benefits as of March 31, ~~2022~~2023 and December 31, ~~2021, as a result of our pension and other postretirement benefit plans.~~2022, respectively. See Note 141 3 to the consolidated financial statements included in this Quarterly Report for additional discussion about our pension and other postretirement benefits.

We are subject to various litigation, claims and proceedings that arise in the ordinary course of business, such as for alleged breaches of contract, miscalculation of royalties, employment matters, traffic incidents, pollution, contamination, encroachment on others’ property or nuisance. We accrue for such items when a liability is both probable and the amount can be reasonably estimated. Management believes that current litigation, claims and proceedings, individually or in aggregate and after taking into account insurance, are not likely to have a material adverse impact on our financial position, results of operations or cash flows, although it is possible that adverse outcomes could have a material adverse effect on our results of operations or cash

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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.

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

For further information, we refer you to “Litigation” and “Environmental Risk” in Note 121 1 to the consolidated financial statements included in Item 1 of Part I of this Quarterly Report.

Supplemental Guarantor Financial Information

As discussed in Note 111 0, in April ~~2018~~2022 the Company entered into the ~~2018~~2022 credit facility. Pursuant to requirements under the indentures governing our senior notes, each 100% owned subsidiary that ~~became~~becomes a guarantor of the ~~2018~~2022 credit facility is also ~~became~~required to become a guarantor of each of our senior notes (the “Guarantor Subsidiaries”) ~~and such subsidiaries are also guarantors of our 2022 credit facility.~~. The Guarantor Subsidiaries also granted liens and security interests to support their guarantees under the ~~2018 credit facility and~~ 2022 credit facility, but not of the senior notes. These guarantees are full and unconditional and joint and several among the Guarantor Subsidiaries. Certain of our operating units are accounted for on a consolidated basis do not guarantee the ~~2018 credit facility,~~ 2022 credit facility and senior notes.

~~Upon the closing of the Indigo Merger and the GEPH Merger, discussed further in~~ ~~Note 2~~ to the consolidated financials included in this Quarterly Report, certain acquired entities owning oil and gas properties became guarantors to the 2018 credit facility and are guarantors of our 2022 credit facility.

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

SEC Regulation S-X Rule 13-01 requires the presentation of “Summarized Financial Information” to replace the “Condensed Consolidating Financial Information” required under Rule 3-10. Rule 13-01 allows the omission of Summarized Financial Information if assets, liabilities and results of operations of the Guarantor Subsidiaries are not materially different than the corresponding amounts presented in the consolidated financial statements of the Company. The Parent and Guarantor Subsidiaries comprise the material operations of the Company. Therefore, the Company concluded that the presentation of the Summarized Financial Information is not required as the Summarized Financial Information of the Company’s Guarantors is not materially different from our consolidated financial statements.

Critical Accounting Policies and Estimates

There have been no material changes to our critical accounting policies and estimates as compared to the critical accounting policies and estimates described in our ~~2021~~2022 Annual Report.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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

Credit Risk

Our exposure to concentrations of credit risk consists primarily of trade receivables and derivative contracts associated with commodities trading. Concentrations of credit risk with respect to receivables are limited due to the large number of our purchasers and their dispersion across geographic areas. AtFor the three months ended March 31, ~~2022,~~2023, one purchaser accounted for ~~18%~~14% of our revenues. For the year ended December 31, ~~2021,~~2022, one purchaser accounted for ~~12% of our revenues. If we had completed the Indigo Merger and GEPH Merger at the beginning of 2021, this same purchaser would have accounted for approximately 16%~~17% of our revenues. No other individual purchasers accounted for more than 10% of our revenues in either of these respective periods. A default on this account could have a material impact on the Company. See “Commodities Risk” below for discussion of credit risk associated with commodities trading.

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Interest Rate Risk

As of March 31, ~~2022,~~2023, we had approximately ~~$4,209~~$3,743 million of outstanding senior notes with a weighted average interest rate of ~~5.74%~~5.46%, ~~$549~~and $210 million of borrowings under our ~~Term Loan and $174 million of borrowings under our 2018~~2022 credit facility. As of March 31, ~~2022,~~2023, we had long-term debt issuer ratings of BB+ by S&P, ~~Ba2~~Ba1 by Moody’s and BBBB+ by Fitch Ratings. On September 1, 2021 S&P upgraded our bond rating to BB, and on January 6, 2022, S&P further upgraded our bond rating to BB+, which decreased the interest rate on the 2025 notes to 5.95%, beginning with coupon payments paid after January 2022. On May 31, 2022, Moody’s upgraded the Company’s bond rating to Ba1, which decreased the interest rate on the 2025 Notes from 5.95% to 5.70% with coupon payments paid after July 2022. Any further upgrades or downgrades in our public debt ratings by Moody’s or S&P could decrease or increase our cost of funds, respectively, as our 2025 ~~senior notes~~Notes are subject to ratings driven changes.


		Expected Maturity Date																					Expected Maturity Date
($ in millions except percentages)	($ in millions except percentages)	2022			2023			2024			2025			2026			Thereafter			Total				($ in millions except percentages)	2023			2024			2025			2026			2027			Thereafter			Total
Fixed rate payments (1)	Fixed rate payments (1)	$	—		$	—		$	—		$	389		$	—		$	3,820		$	4,209			Fixed rate payments (1)	$	—		$	—		$	389		$	—		$	—		$	3,354		$	3,743
Weighted average interest rate	Weighted average interest rate	—		%	—		%	—		%	5.95		%	—		%	5.72		%	5.74		%		Weighted average interest rate	—		%	—		%	5.70		%	—		%	—		%	5.43		%	5.46		%

Variable rate payments (1)	Variable rate payments (1)	$	4		$	6		$	179		$	6		$	5		$	523		$	723			Variable rate payments (1)	$	—		$	—		$	—		$	—		$	210		$	—		$	210
Weighted average interest rate	Weighted average interest rate	3.30		%	3.30		%	2.42		%	3.30		%	3.30		%	3.30		%	3.08		%		Weighted average interest rate	—		%	—		%	—		%	—		%	6.69		%	—		%	6.69		%

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

Commodities Risk

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

The primary market risks relating to our derivative contracts are the volatility in market prices and basis differentials for our production. However, the market price risk is offset by the gain or loss recognized upon the related sale or purchase of the production that is financially protected. Credit risk relates to the risk of loss as a result of non-performance by our counterparties. The counterparties are primarily major banks and integrated energy companies that management believes present minimal credit risks. The credit quality of each counterparty and the level of financial exposure we have to each counterparty are closely monitored to limit our credit risk exposure. Additionally, we perform both quantitative and qualitative assessments of these counterparties based on their credit ratings and credit default swap rates where applicable. We have not incurred any counterparty losses related to non-performance and do not anticipate any losses given the information we have currently. However, we cannot be certain that we will not experience such losses in the future. The fair value of our derivative assets and liabilities includes a non-performance risk factor. We refer you to Note 8 7 and Note 10 9 of the consolidated financial statements included in this Quarterly Report for additional details about our derivative instruments and their fair value.

ITEM 4. CONTROLS AND PROCEDURES

Disclosure Controls and Procedures

We have performed an evaluation under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of our disclosure controls and procedures, as defined in Rule 13a-15(e) and 15d-15(e) under the Exchange Act as of the end of the period covered by this Quarterly Report. Our disclosure controls and procedures are the controls and other procedures that we have designed to ensure that we record, process, accumulate and communicate information to our management, including our Chief Executive Officer and Chief Financial Officer, to allow timely decisions regarding required disclosures and submission within the time periods specified in the SEC’s rules and forms. All internal control systems, no matter how well designed, have inherent limitations. Therefore, even those determined to be effective can provide only a level of reasonable assurance with respect to financial statement preparation and presentation. Based on the evaluation, our management, including our Chief Executive Officer and Chief Financial Officer, concluded that our disclosure controls and procedures were effective as of March 31, ~~2022~~2023 at a reasonable assurance level.

Changes in Internal Control over Financial Reporting

On December 31, 2021, the Company completed its acquisition of GEP Haynesville, LLC. As part of the ongoing integration of the acquired business, we are in the process of incorporating the controls and related procedures of GEPH. Other than incorporating the GEPH controls, thereThere were no changes in our internal control over financial reporting (as defined in Rule 13a-15(f) and 15d-15(f) under the Exchange Act) that occurred during the quarter ended March 31, ~~2022~~2023 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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PART II - OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

Refer to “Litigation” and “Environmental Risk” in Note 121 1 to the consolidated financial statements included in Item 1 of Part I of this Quarterly Report for a discussion of the Company’s legal proceedings.

ITEM 1A. RISK FACTORS

There were no additions or material changes to our risk factors as disclosed in Item 1A of Part I in the Company’s ~~2021~~2022 Annual Report.

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

Not applicable.

ITEM 3. DEFAULTS UPON SENIOR SECURITIES

Not applicable.

ITEM 4. MINE SAFETY DISCLOSURES

Not applicable.

ITEM 5. OTHER INFORMATION

Not applicable.

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ITEM 6. EXHIBITS


(2.1)			Agreement and Plan of Merger, dated August 12, 2020, by and among Southwestern Energy Company and Montage Resources Corporation (Incorporated by reference to Exhibit 2.1 to the Registrant's Current Report on Form 8-K/A filed on August 12, 2020).
(2.2)			Agreement and Plan of Merger, dated June 1, 2021, by and among Southwestern Energy Company, Ikon Acquisition Company, LLC, Indigo Natural Resources LLC, and Ibis Unitholder Representative, LLC solely in its capacity as the Unitholder Representative (Incorporated by reference to Exhibit 2.1 to the Registrant's Current Report on Form 8-K filed on June 2, 2021).
(2.3)			Agreement and Plan of Merger, dated November 3, 2021, by and among Southwestern Energy Company, Mustang Acquisition Company, LLC, GEP Haynesville, LLC, and GEPH Unitholder Rep, LLC solely in its capacity as the Unitholder Representative (Incorporated by reference to Exhibit 2.1 to the Registrant's Current Report on Form 8-K filed on November 5, 2021).
(3.1)			Amended and Restated Certificate of Incorporation of Southwestern Energy Company (Incorporated by reference to Exhibit 3.1 to the Registrant’s Current Report on Form 8-K filed May 24, 2010).
(3.2)			Certificate of Amendment and Restated Certificate of Incorporation , dated September 1, 2021 (Incorporated by reference to Exhibit 3.1 to the Re gistrant ’s Current Report on Form 8-K filed September 1, 2021).
(3.3)			Amended and Restated Bylaws of Southwestern Energy Company, as amended ~~on April 28, 2020~~through March 21, 2023 (Incorporated by reference to Exhibit ~~3.2 to the Registrant’s Quarterly Report on Form 10-Q filed April 30, 2020).~~
~~(4.1)~~			Sixth Supplemental Indenture, dated as of January 4, 2022, among Southwestern Energy Company, the guarantors party thereto and The Bank of New York Mellon Trust, N.A., as trustee (Incorporated by reference to Exhibit 4.13.1 to the Registrant’s Current Report on Form 8-K filed on ~~January 5, 2022)~~March 22, 2023).






(10.1)*			Southwestern Energy Company 2022 Incentive Plan Form of Performance Cash Unit Award Agreement, for awards granted on or after February 2 1 , 2023 .
~~(4.2)~~(10.2)*			~~Eighth Supplemental Indenture, dated as of January 4, 2022, among~~ Southwestern Energy Company ~~the guarantors party thereto and Regions Bank, as trustee (Incorporated by reference to Exhibit 4.2 to the Registrant’s Current Report~~2022 Incentive Plan Form of Performance Unit Award Agreement, for awards granted on ~~Form 8-K filed on January 5, 2022).~~or after February 21, 2023.
~~(4.3)~~(10.3)*			~~Eighth Supplemental Indenture, dated as of January 4, 2022, among~~ Southwestern Energy Company ~~the guarantors party thereto and U.S. Bank National Association, as trustee (Incorporated by reference to Exhibit 4.3 to the Registrant’s Current Report~~2022 Incentive Plan Form of Restricted Stock Unit Award Agreement, for awards granted on ~~Form 8-K filed on January 5, 2022).~~
~~(4.4)~~			Fifth Supplemental Indenture, dated as of January 4, 2022, among Southwestern Energy Company, the guarantors party thereto and Regions Bank, as trustee (Incorporated by reference to Exhibit 4.4 to the Registrant’s Current Report on Form 8-K filed on January 5, 2022).
~~(10.1)~~			Amended and Restated Credit Agreement, dated April 8, 2022 among Southwestern Energy Company, JPMorgan Chase Bank, N.A., as Administrative Agent and the lenders from time to time party thereto (Incorporated by reference to Exhibit 10.1 to the Registrant’s Current Report on Form 8-K filed on April 12, 2022).or after February 21, 2023.
(31.1)*			Certification of CEO filed pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
(31.2)*			Certification of CFO filed pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
(32.1)**			Certification of CEO furnished pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
(32.2)**			Certification of CFO furnished pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
(101.INS)			Inline Interactive Data File Instance Document
(101.SCH)			Inline Interactive Data File Schema Document
(101.CAL)			Inline Interactive Data File Calculation Linkbase Document
(101.LAB)			Inline Interactive Data File Label Linkbase Document
(101.PRE)			Inline Interactive Data File Presentation Linkbase Document
(101.DEF)			Inline Interactive Data File Definition Linkbase Document
(104.1)			Cover Page Interactive Data File – the cover page from this Quarterly Report on Form 10-Q, formatted in inline XBRL (included within the Exhibit 101 attachments)

* Filed herewith

** Furnished herewith

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Signatures

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


		SOUTHWESTERN ENERGY COMPANY
		Registrant

Dated:	April ~~28, 2022~~27, 2023	/s/ CARL F. GIESLER, JR.
		Carl F. Giesler, Jr. Executive Vice President and Chief Financial Officer

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