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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q

(Mark One)

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

Exchange Act of 1934

For the quarterly period ended ~~September 30, 2021~~March 31, 2022

☐ 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”,~~filer,” “accelerated ~~filer”,~~filer,” “smaller reporting ~~company”~~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 ~~November 1, 2021~~April 26, 2022
Common Stock, Par Value $0.01						~~1,014,978,197~~1,116,176,673

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SOUTHWESTERN ENERGY COMPANY

INDEX TO FORM 10-Q

FOR THE QUARTERLY PERIOD ENDED ~~SEPTEMBER 30, 2021~~MARCH 31, 2022


PART I – FINANCIAL INFORMATION			Page

Item 1.	Financial Statements		34
	Consolidated Statements of Operations		34
	Consolidated Statements of Comprehensive Income (Loss)		45
	Consolidated Balance Sheets		56
	Consolidated Statements of Cash Flows		67
	Consolidated Statements of Changes in Equity		78
	Notes to Consolidated Financial Statements		9
		Note 1. Basis of Presentation	9
		Note 2. Acquisition	9
		Note 3. Restructuring Charges	13
		Note 4. Revenue Recognition	1314
		Note 5. Cash and Cash Equivalents	15
		Note 6. Natural Gas and Oil Properties	15
		Note 7. Earnings per Share	16
		Note 8. Derivatives and Risk Management	17
		Note 9. Reclassifications From Accumulated Other Comprehensive Income (Loss)	2523
		Note 10. Fair Value Measurements	2623
		Note 11. Debt	2926
		Note 1 2 . Commitments and Contingencies	31
		Note 1 3 . Income Taxes	3332
		Note 1 4 . Pension Plan and Other ~~Postretirement~~Post r etirement Benefits	3433
		Note 15. Long-Term Incentive Compensation	3534
		Note 1 6 . Segment Information	3937
		Note 1 7 . New Accounting Pronouncements	4138
		~~Note 18. Subsequent Events~~	41
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		4139
	Results of Operations		4442
	Liquidity and Capital Resources		5349
Item 3.	Quantitative and Qualitative Disclosures About Market Risk		5855
Item 4.	Controls and Procedures		5956

PART II – OTHER INFORMATION

Item 1.	Legal Proceedings		5957
Item 1A.	Risk Factors		5957
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds		6257
Item 3.	Defaults Upon Senior Securities		6257
Item 4.	Mine Safety Disclosures		6257
Item 5.	Other Information		6257
Item 6.	Exhibits		6258

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CAUTIONARY STATEMENT ABOUT FORWARD-LOOKING STATEMENTS

~~All~~This Quarterly Report on Form 10-Q (“Quarterly Report”) includes certain statements ~~other than historical fact or present financial information,~~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

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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~~ (including regional basis ~~differentials~~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;~~pandemic or other world health event;

•our ability to fund our planned capital investments;

•a change in our credit rating and an increase in interest ~~rates and any adverse impacts from the discontinuation of the London Interbank Offered Rate (“LIBOR”);~~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;~~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 Merger (discussed~~Mergers (defined below);

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

•integration of operations and results subsequent to the ~~Indigo Merger;~~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;

•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;~~weather or power outages;

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•increased competition;

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

•the comparative cost of alternative fuels;

•credit risk relating to the risk of loss as a result of non-performance by our counterparties;

•our hedging strategy and results;

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

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

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

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

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

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PART I – FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

SOUTHWESTERN ENERGY COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)


		For the three months ended September 30,				For the nine months ended September 30,					For the three months ended March 31,
(in millions, except share/per share amounts)	(in millions, except share/per share amounts)	2021		2020		2021		2020		(in millions, except share/per share amounts)	2022		2021
Operating Revenues:	Operating Revenues:									Operating Revenues:
Gas sales	Gas sales	$	811	$	199	$	1,708	$	611	Gas sales	$	1,692	$	464
Oil sales	Oil sales	110		40		297		111		Oil sales	111		81
NGL sales	NGL sales	255		68		607		158		NGL sales	272		173
Marketing	Marketing	418		219		1,102		645		Marketing	866		352
Other	Other	4		1		6		4		Other	2		2
		1,598		527		3,720		1,529			2,943		1,072
Operating Costs and Expenses:	Operating Costs and Expenses:									Operating Costs and Expenses:
Marketing purchases	Marketing purchases	420		226		1,109		675		Marketing purchases	862		356
Operating expenses	Operating expenses	296		202		805		577		Operating expenses	381		250
General and administrative expenses	General and administrative expenses	32		31		104		89		General and administrative expenses	44		38
Merger-related expenses	Merger-related expenses	35		3		39		3		Merger-related expenses	25		1
Restructuring charges	Restructuring charges	—		—		7		12		Restructuring charges	—		6

Depreciation, depletion and amortization	Depreciation, depletion and amortization	138		70		334		267		Depreciation, depletion and amortization	275		96
Impairments		6		361		6		2,495

Taxes, other than income taxes	Taxes, other than income taxes	35		15		86		38		Taxes, other than income taxes	57		24
		962		908		2,490		4,156			1,644		771
Operating Income (Loss)		636		(381)		1,230		(2,627)
Operating Income										Operating Income	1,299		301
Interest Expense:	Interest Expense:									Interest Expense:
Interest on debt	Interest on debt	56		43		154		123		Interest on debt	68		50
Other interest charges	Other interest charges	3		2		9		7		Other interest charges	3		3
Interest capitalized	Interest capitalized	(25)		(23)		(68)		(67)		Interest capitalized	(30)		(22)
		34		22		95		63			41		31

Gain (Loss) on Derivatives		(2,399)		(192)		(3,461)		38
Gain (Loss) on Early Extinguishment of Debt		(59)		—		(59)		35
Other Income (Loss), Net		(1)		2		(1)		3
Loss on Derivatives										Loss on Derivatives	(3,927)		(191)
Loss on Early Extinguishment of Debt										Loss on Early Extinguishment of Debt	(2)		—
Other Income, Net										Other Income, Net	—		1

Loss Before Income Taxes		(1,857)		(593)		(2,386)		(2,614)
Income (Loss) Before Income Taxes										Income (Loss) Before Income Taxes	(2,671)		80
Provision (Benefit) for Income Taxes:	Provision (Benefit) for Income Taxes:									Provision (Benefit) for Income Taxes:
Current	Current	—		—		—		(2)		Current	4		—
Deferred	Deferred	—		—		—		408		Deferred	—		—
		—		—		—		406			4		—
Net Loss		$	(1,857)	$	(593)	$	(2,386)	$	(3,020)
Net Income (Loss)										Net Income (Loss)	$	(2,675)	$	80

Loss Per Common Share:
Earnings (Loss) Per Common Share:										Earnings (Loss) Per Common Share:
Basic	Basic	$	(2.36)	$	(1.04)	$	(3.34)	$	(5.48)	Basic	$	(2.40)	$	0.12
Diluted	Diluted	$	(2.36)	$	(1.04)	$	(3.34)	$	(5.48)	Diluted	$	(2.40)	$	0.12

Weighted Average Common Shares Outstanding:	Weighted Average Common Shares Outstanding:									Weighted Average Common Shares Outstanding:
Basic	Basic	787,032,414		571,872,413		713,455,662		551,162,559		Basic	1,114,610,964		675,385,145
Diluted	Diluted	787,032,414		571,872,413		713,455,662		551,162,559		Diluted	1,114,610,964		679,867,825

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

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SOUTHWESTERN ENERGY COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(Unaudited)
For the three months ended September 30, For the nine months ended September 30,
(in millions) 2021 2020 2021 2020
Net loss $ (1,857) $ (593) $ (2,386) $ (3,020)
Change in value of pension and other postretirement liabilities:
Settlement adjustment (1)
1 1 4 1
Comprehensive loss $ (1,856) $ (592) $ (2,382) $ (3,019)


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

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

Comprehensive income (loss)	$	(2,675)	$	80

(1)~~Tax benefits~~Settlement adjustment was less than $1 million for the three months ended ~~September 30, 2021 and 2020 were immaterial. Net of $1 million in taxes for the nine months ended September 30, 2021 and 2020, respectively.~~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)


		September 30, 2021		December 31, 2020			March 31, 2022		December 31, 2021

ASSETS	ASSETS	(in millions)				ASSETS	(in millions)
Current assets:	Current assets:					Current assets:
Cash and cash equivalents	Cash and cash equivalents	$	12	$	13	Cash and cash equivalents	$	21	$	28
Accounts receivable, net	Accounts receivable, net	708		368		Accounts receivable, net	1,071		1,160
Derivative assets	Derivative assets	130		241		Derivative assets	103		183
Other current assets	Other current assets	52		49		Other current assets	43		42
Total current assets	Total current assets	902		671		Total current assets	1,238		1,413
Natural gas and oil properties, using the full cost method, including $2,175 million as of September 30, 2021 and $1,472 million as of December 31, 2020 excluded from amortization		31,486		27,261
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						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

Other	Other	503		523		Other	513		509
Less: Accumulated depreciation, depletion and amortization	Less: Accumulated depreciation, depletion and amortization	(23,987)		(23,673)		Less: Accumulated depreciation, depletion and amortization	(24,482)		(24,202)
Total property and equipment, net	Total property and equipment, net	8,002		4,111		Total property and equipment, net	10,215		9,938
Operating lease assets	Operating lease assets	144		163		Operating lease assets	186		187
Long-term derivative assets						Long-term derivative assets	126		226
Deferred tax assets	Deferred tax assets	—		—		Deferred tax assets	—		—
Other long-term assets	Other long-term assets	193		215		Other long-term assets	82		84
Total long-term assets	Total long-term assets	337		378		Total long-term assets	394		497
TOTAL ASSETS	TOTAL ASSETS	$	9,241	$	5,160	TOTAL ASSETS	$	11,847	$	11,848
LIABILITIES AND EQUITY	LIABILITIES AND EQUITY					LIABILITIES AND EQUITY
Current liabilities:	Current liabilities:					Current liabilities:
Current portion of long-term debt	Current portion of long-term debt	$	201	$	—	Current portion of long-term debt	$	5	$	206
Accounts payable	Accounts payable	955		573		Accounts payable	1,488		1,282
Taxes payable	Taxes payable	78		74		Taxes payable	80		93
Interest payable	Interest payable	42		58		Interest payable	49		75

Derivative liabilities	Derivative liabilities	2,769		245		Derivative liabilities	3,940		1,279
Current operating lease liabilities	Current operating lease liabilities	41		42		Current operating lease liabilities	44		42
Other current liabilities	Other current liabilities	76		20		Other current liabilities	64		75
Total current liabilities	Total current liabilities	4,162		1,012		Total current liabilities	5,670		3,052
Long-term debt	Long-term debt	4,036		3,150		Long-term debt	4,895		5,201
Long-term operating lease liabilities	Long-term operating lease liabilities	101		117		Long-term operating lease liabilities	139		142
Long-term derivative liabilities	Long-term derivative liabilities	960		183		Long-term derivative liabilities	1,023		632
Pension and other postretirement liabilities	Pension and other postretirement liabilities	31		45		Pension and other postretirement liabilities	25		23
Other long-term liabilities	Other long-term liabilities	237		156		Other long-term liabilities	214		251
Total long-term liabilities	Total long-term liabilities	5,365		3,651		Total long-term liabilities	6,296		6,249
Commitments and contingencies (Note 12)	Commitments and contingencies (Note 12)	0		0		Commitments and contingencies (Note 12)	0		0
Equity/(deficit):	Equity/(deficit):					Equity/(deficit):
Common stock, $0.01 par value; 2,500,000,000 shares authorized; issued 1,059,331,421 shares as of September 30, 2021 and 718,795,700 shares as of December 31, 2020		11		7
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						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

Additional paid-in capital	Additional paid-in capital	6,688		5,093		Additional paid-in capital	7,159		7,150
Accumulated deficit	Accumulated deficit	(6,749)		(4,363)		Accumulated deficit	(7,063)		(4,388)
Accumulated other comprehensive loss	Accumulated other comprehensive loss	(34)		(38)		Accumulated other comprehensive loss	(25)		(25)
Common stock in treasury, 44,353,224 shares as of September 30, 2021 and December 31, 2020		(202)		(202)
Common stock in treasury, 44,353,224 shares as of March 31, 2022 and December 31, 2021						Common stock in treasury, 44,353,224 shares as of March 31, 2022 and December 31, 2021	(202)		(202)
Total equity/(deficit)	Total equity/(deficit)	(286)		497		Total equity/(deficit)	(119)		2,547
TOTAL LIABILITIES AND EQUITY	TOTAL LIABILITIES AND EQUITY	$	9,241	$	5,160	TOTAL LIABILITIES AND EQUITY	$	11,847	$	11,848

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

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SOUTHWESTERN ENERGY COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)


		For the nine months ended September 30,					For the three months ended March 31,
(in millions)	(in millions)	2021		2020		(in millions)	2022		2021
Cash Flows From Operating Activities:	Cash Flows From Operating Activities:					Cash Flows From Operating Activities:
Net loss		$	(2,386)	$	(3,020)
Adjustments to reconcile net loss to net cash provided by operating activities:
Net income (loss)						Net income (loss)	$	(2,675)	$	80
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	334		267		Depreciation, depletion and amortization	275		96
Amortization of debt issuance costs	Amortization of debt issuance costs	6		6		Amortization of debt issuance costs	2		2
Impairments		6		2,495
Deferred income taxes		—		408

Loss on derivatives, unsettled	Loss on derivatives, unsettled	2,952		272		Loss on derivatives, unsettled	3,232		169
Stock-based compensation	Stock-based compensation	2		2		Stock-based compensation	1		—
Loss (gain) on early extinguishment of debt		59		(35)
Loss on early extinguishment of debt						Loss on early extinguishment of debt	2		—

Other	Other	3		3		Other	(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	(147)		106		Accounts receivable	89		(33)
Accounts payable	Accounts payable	58		(129)		Accounts payable	126		33
Taxes payable	Taxes payable	(10)		(12)		Taxes payable	(13)		(8)
Interest payable	Interest payable	(13)		3		Interest payable	(16)		(2)
Inventories	Inventories	(2)		3		Inventories	4		9
Other assets and liabilities	Other assets and liabilities	(32)		38		Other assets and liabilities	(54)		1
Net cash provided by operating activities	Net cash provided by operating activities	830		407		Net cash provided by operating activities	972		347

Cash Flows From Investing Activities:	Cash Flows From Investing Activities:					Cash Flows From Investing Activities:
Capital investments	Capital investments	(747)		(700)		Capital investments	(500)		(227)
Proceeds from sale of property and equipment	Proceeds from sale of property and equipment	4		2		Proceeds from sale of property and equipment	—		1
Cash acquired in Indigo Acquisition		55		—
Cash paid in Indigo Acquisition		(373)		—
Other	Other	(1)		—		Other	—		(1)
Net cash used in investing activities	Net cash used in investing activities	(1,062)		(698)		Net cash used in investing activities	(500)		(227)

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 long-term debt	Payments on long-term debt	(844)		(72)		Payments on long-term debt	(21)		—
Payments on revolving credit facility	Payments on revolving credit facility	(3,401)		(1,449)		Payments on revolving credit facility	(2,803)		(923)
Borrowings under revolving credit facility	Borrowings under revolving credit facility	3,366		1,415		Borrowings under revolving credit facility	2,517		790
Change in bank drafts outstanding	Change in bank drafts outstanding	33		(9)		Change in bank drafts outstanding	34		7
Repayment of Indigo revolving credit facility		(95)		—
Proceeds from issuance of long-term debt		1,200		350
Debt issuance/amendment costs		(25)		(5)

Proceeds from issuance of common stock, net		—		152
Cash paid for tax withholding	Cash paid for tax withholding	(3)		(1)		Cash paid for tax withholding	(4)		(3)

Net cash provided by financing activities		231		381
Net cash used in financing activities						Net cash used in financing activities	(479)		(129)

Increase (decrease) in cash and cash equivalents		(1)		90
Decrease in cash and cash equivalents						Decrease in cash and cash equivalents	(7)		(9)
Cash and cash equivalents at beginning of year	Cash and cash equivalents at beginning of year	13		5		Cash and cash equivalents at beginning of year	28		13
Cash and cash equivalents at end of period	Cash and cash equivalents at end of period	$	12	$	95	Cash and cash equivalents at end of period	$	21	$	4

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, 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 granted 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
Comprehensive loss:
Net loss — — — (609) — — — (609)
Other comprehensive income — — — — 3 — — 3
Total comprehensive loss — — — — — — — (606)
Stock-based compensation — — 2 — — — — 2
Issuance of restricted stock 148,700 — — — — — — —
Restricted units granted 41,879 — — — — — — —
Tax withholding – stock compensation (13,258) — — — — — — —
Balance at June 30, 2021 721,372,443 $ 7 $ 5,104 $ (4,892) $ (35) 44,353,224 $ (202) $ (18)
Comprehensive loss:
Net loss — — — (1,857) — — — (1,857)
Other comprehensive income — — — — 1 — — 1
Total comprehensive loss — — — — — — — (1,856)
Issuance of restricted stock 130,675 — — — — — — —
Restricted units granted 1,132 — — — — — — —
Indigo acquisition 337,827,171 4 1,584 — — — — 1,588
Balance at September 30, 2021 1,059,331,421 $ 11 $ 6,688 $ (6,749) $ (34) 44,353,224 $ (202) $ (286)


	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)

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

~~Table of Contents~~

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, 2019 585,555,923 $ 6 $ 4,726 $ (1,251) $ (33) 44,353,224 $ (202) $ 3,246
Comprehensive loss:
Net loss — — — (1,547) — — — (1,547)
Other comprehensive income — — — — — — — —
Total comprehensive loss — — — — — — — (1,547)
Stock-based compensation — — 1 — — — — 1
Issuance of restricted stock 12,397 — — — — — — —
Cancellation of restricted stock (167,130) — — — — — — —
Restricted units granted 1,005,976 — 1 — — — — 1
Tax withholding – stock compensation (383,731) — — — — — — —
Balance at March 31, 2020 586,023,435 $ 6 $ 4,728 $ (2,798) $ (33) 44,353,224 $ (202) $ 1,701
Comprehensive loss:
Net loss — — — (880) — — — (880)
Other comprehensive income — — — — — — — —
Total comprehensive loss — — — — — — — (880)
Stock-based compensation — — 1 — — — — 1
Issuance of restricted stock 222,489 — — — — — — —
Cancellation of restricted stock (1,079,515) — — — — — — —
Restricted units granted 1,649,294 — 2 — — — — 2
Tax withholding – stock compensation (222,163) — (1) — — — — (1)
Balance at June 30, 2020 586,593,540 $ 6 $ 4,730 $ (3,678) $ (33) 44,353,224 $ (202) $ 823
Comprehensive loss
Net loss — — — (593) — — — (593)
Other comprehensive income — — — — 1 — — 1
Total comprehensive loss — — — — — — — (592)
Stock-based compensation — — 1 — — — — 1
Issuance of common stock 63,250,000 1 151 — — — — 152
Issuance of restricted stock 63,344 — — — — — — —
Cancellation of restricted stock (5,196) — — — — — — —
Tax withholding – stock compensation (2,035) — — — — — — —
Balance at September 30, 2020 649,899,653 $ 7 $ 4,882 $ (4,271) $ (32) 44,353,224 $ (202) $ 384


	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

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

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SOUTHWESTERN ENERGY COMPANY AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

(1) BASIS OF PRESENTATION

Nature of Operations

Southwestern Energy Company (including its subsidiaries, collectively “Southwestern” or the “Company”) is an independent energy company engaged in natural gas, oil and NGLs development, exploration ~~development~~ and production (“E&P”) ~~of primarily natural gas as well as associated NGLs and oil.~~. 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 2 segments: E&P and Marketing.

E&P. Southwestern’s primary business is the ~~exploration for~~development and production of natural gas as well as associated NGLs and oil, with ongoing operations focused on ~~the development of~~ unconventional ~~hydrocarbon~~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 ~~focuses~~focused on the Haynesville and Bossier natural gas ~~reservoirs.~~reservoirs (“Haynesville and Bossier Shales”). The Company also operates drilling rigs ~~located in Appalachia,~~ and provides certain oilfield products and services, principally serving the Company’s E&P ~~activities~~operations through vertical integration.

Marketing. Southwestern’s marketing activities capture opportunities that arise through the marketing and transportation of natural gas, oil and ~~associated liquids,~~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 ~~of America~~ (“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 ~~2021~~2022 amounts to prior periods could be impacted as a result of the ~~Montage Merger (as defined below) with Montage Resources Corporation (“Montage”) in November 2020 and the~~ Indigo Merger (as defined below) ~~with Indigo Natural Resources in~~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, ~~2020~~2021 (“~~2020~~2021 Annual Report”).

The Company’s significant accounting policies, which have been reviewed and approved by the Audit Committee of the Company’s Board of Directors, are summarized in Note 1 in the Notes to the Consolidated Financial Statements included in the Company’s ~~2020~~2021 Annual Report.

(2) ~~ACQUISITION~~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.

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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.

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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 ~~of Indigo~~ (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. ~~Following the closing of the Indigo Merger, Southwestern's existing shareholders and Indigo's~~

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~~former equity holders owned approximately 67% and 33%, respectively, of the outstanding shares of the combined company.~~ 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 ~~and studies~~ necessary to complete the purchase price allocation ~~are~~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 for which not enough information is available to assess the final fair value of at this time.~~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.

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(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)	~~676~~693
Other property, plant and equipment	4
Other long-term assets	27
Total assets acquired	~~3,682~~3,699
Fair Value of Liabilities Assumed:
Accounts payable (1)	~~266~~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	~~1,721~~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.

~~Unevaluated oil~~With the completion of the Indigo Merger, Southwestern acquired proved and ~~gas~~unproved properties ~~were valued~~of approximately $2,724 million and $693 million, respectively, primarily ~~using a market approach based on comparable transactions for similar properties while~~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 ~~proved~~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.

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With the completion of the Indigo Merger, Southwestern acquired proved and unproved properties of approximately $2.7 billion and $676 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.

Deferred income taxes represent the tax effects of differences in the tax basis and merger-date fair values of assets acquired and liabilities assumed. The initial net balance of any deferred tax assets or liabilities is zero. A full valuation was placed on all deferred tax assets generated following the Indigo Merger consistent with the Company’s treatment of its deferred tax asset balance as of September 30, 2021. 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 ~~revolving~~2018 credit facility to approximate fair ~~value.~~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.

From the date of the Indigo Merger through September 30, 2021, revenues and operating income associated with the operations acquired through the merger totaled $132 million and $75 million, respectively.

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 ~~will assume~~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 ~~September 30, 2021,~~March 31, 2022, up to approximately ~~$34~~$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 ~~$81~~$35 million as of ~~September 30, 2021,~~March 31, 2022, primarily related to purchase or volume commitments associated with gathering and fresh ~~water and sand.~~water. These amounts will be recognized as payments are made over a period ~~ranging from~~ ~~two~~ ~~to seven years.~~

~~Montage Resources Merger~~

~~On August 12, 2020, Southwestern entered into an Agreement and Plan~~ of Merger (the “Montage Agreement and Plan of Merger”) with Montage whereby Montage would merge with and into Southwestern, with Southwestern continuing as the surviving company (the "Montage Merger"). On November 12, 2020, Montage’s stockholders voted to approve the Montage Merger, and it was made effective on November 13, 2020. The Montage Merger added to Southwestern’s oil and gas portfolio in Appalachia.

In exchange for each share of Montage common stock, Montage stockholders received 1.8656 shares of Southwestern common stock, plus cash in lieu of any fractional share of Southwestern common stock that otherwise would have been issued, based on the average price of $3.05 per share of Southwestern common stock on the NYSE on November 13, 2020. Following the closing of the Montage Merger, Southwestern's existing shareholders and Montage's existing shareholders owned approximately 90% and 10%, respectively, of the outstanding shares of the combined company.two years.

In anticipation of the Montage Merger, in August 2020 Southwestern issued $350 million of new senior unsecured notes and 63,250,000 shares of common stock for $152 million after deducting underwriting discounts and offering expenses. The Company used the net proceeds from the debt and common stock offerings and borrowings under its revolving credit facility to fund a redemption of $510 million aggregate principal amount of Montage's outstanding 8.875% senior notes due 2023 (the “Montage Notes”) and related accrued interest in connection with the closing of the Montage Merger. See
~~Note 7~~ ~~and~~ ~~Note 11~~ ~~for additional information.~~

The Montage Merger constituted a business combination, and was accounted for using the acquisition method of accounting. The following table presents the fair value of consideration transferred to Montage stockholders as a result of the Montage Merger:


~~(in millions, except share, per share amounts)~~	~~As of November 13, 2020~~
~~Shares of Southwestern common stock issued in respect of outstanding Montage common stock~~	~~67,311,166~~
~~Shares of Southwestern common stock issued in respect of Montage stock-based awards~~	~~2,429,682~~
	~~69,740,848~~
~~NYSE closing price per share of Southwestern common shares on November 13, 2020~~	$	~~3.05~~
~~Total consideration (fair value of Southwestern common shares issued)~~	$	~~213~~
~~Increase in Southwestern common stock ($0.01 par value per share)~~	1
~~Increase in Southwestern additional paid-in capital~~	$	~~212~~

~~Table of Contents~~

The assets acquired and liabilities assumed were recorded at their estimated fair values at the date of the Montage Merger. The following table sets forth the fair value of the assets acquired and liabilities assumed as of the acquisition date. The purchase price allocation related to the Montage Merger is substantially complete as of the date of this filing. The Company is currently finalizing its analysis on potential liabilities and natural gas and oil property valuation. Any final adjustments in the fourth quarter of 2021 are expected to be immaterial. For the nine months ended September 30, 2021 there were no changes to the allocation presented in the 2020 Form 10-K.


~~(in millions)~~	~~As of November 13, 2020~~
~~Consideration:~~
~~Fair value of Southwestern’s stock issued on November 13, 2020~~	$	~~213~~
~~Fair Value of Assets Acquired:~~
~~Cash and cash equivalents~~	3
~~Accounts receivable~~	73
~~Other current assets~~	1
~~Commodity derivative assets~~	11
~~Evaluated oil and gas properties~~	~~1,012~~
~~Unevaluated oil and gas properties~~	90
~~Other property, plant and equipment~~	28
~~Other long-term assets~~	26
~~Total assets acquired~~	~~1,244~~
~~Fair Value of Liabilities Assumed:~~
~~Accounts payable~~	~~145~~
~~Other current liabilities~~	49
~~Derivative liabilities~~	70
~~Revolving credit facility~~	~~200~~
~~Senior unsecured notes~~	~~522~~
~~Asset retirement obligations~~	28
~~Other noncurrent liabilities~~	17
~~Total liabilities assumed~~	~~1,031~~
~~Net Assets Acquired and Liabilities Assumed~~	$	~~213~~

~~For the nine months ended September 30, 2021, revenues and operating income associated with the operations acquired through the Montage Merger totaled $414 million and $219 million, respectively.~~

~~Pro Forma Information~~

The following table presents selected unaudited pro forma condensed financial information for the three and nine months ended September 30, 2020 as if the Montage Merger had occurred on January 1, 2019 and the Indigo Merger had occurred on January 1, 2020:

For the three months ended September 30, For the nine months ended September 30,
(in millions) 2021 2020 2021 2020
Revenues $ 1,864 $ 844 $ 4,531 $ 2,388
Loss from continuing operations $ (1,588) $ (871) $ (2,371) $ (3,337)

The unaudited pro forma information is not necessarily indicative of the operating results that would have occurred had the Montage Merger and the Indigo Merger (combined, the “Mergers”) been completed at January 1, 2019 and January 1, 2020, respectively, nor is it necessarily indicative of future operating results of the combined entities. The unaudited pro forma information gives effect to the Montage Merger and related equity and debt issuances along with the use of proceeds therefrom as if they had occurred on January 1, 2019. The unaudited pro forma information for 2020 is a result of combining the statements of operations of Southwestern with the pre-Montage Merger results of Montage and pre-Indigo Merger results of Indigo from January 1, 2020, and included adjustments for revenues and direct expenses. The pro forma results exclude any cost savings anticipated as a result of the Mergers, 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 the retirement of the Montage senior notes, the Montage credit facility, all related accrued interest and the associated decrease in amortization of issuance costs related to the Montage notes and revolving line of credit. This decrease was partially offset by increases in interest on debt associated with the issuance of

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$350 million in 8.375% Senior Notes due 2028 related to the Southwestern debt offering and borrowings under Southwestern’s credit facility used to pay off the Montage notes, Montage credit facility and related accrued interest. 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 credit facility, all related accrued interest and the associated decrease in amortization of issuance costs related to the revolving line of credit. Management believes the estimates and assumptions are reasonable, and the relative effects of the Mergers are properly reflected.

Merger-Related Expenses

The following table summarizes the merger-related expenses incurred:


											For the three months ended March 31,
		For the three months ended September 30,				For the nine months ended September 30,					2022						2021
(in millions)	(in millions)	2021		2020		2021		2020		(in millions)	Indigo Merger		GEPH Merger		Total		Montage Merger
Indigo Merger-related expenses		$	35	$	—	$	37	$	—
Montage Merger-related expenses		—		3		2		3
Transition services										Transition services	$	—	$	18	$	18	$	—
Professional fees (bank, legal, consulting)										Professional fees (bank, legal, consulting)	—		1		1		—

Contract buyouts, terminations and transfers										Contract buyouts, terminations and transfers	—		2		2		—
Due diligence and environmental										Due diligence and environmental	1		—		1		—
Employee-related										Employee-related	—		1		1		1
Other										Other	—		2		2		—
Total merger-related expenses	Total merger-related expenses	$	35	$	3	$	39	$	3	Total merger-related expenses	$	1	$	24	$	25	$	1

Pro Forma Information

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



(in millions)	For the three months ended March 31, 2021
Revenues	$	1,471
Net income attributable to common stock	$	30
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 ~~bank, legal~~the operating results that would have occurred had the Indigo Merger and ~~consulting fees~~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 ~~representation~~the use of proceeds therefrom, as if they had occurred on January 1, 2020 and ~~warranty insurance.~~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 ~~Montage Merger-related expenses primarily consist of employees and contractors that were temporarily assisting in the transition and integration~~pro forma results exclude any cost savings anticipated as a result of the ~~Montage Merger.~~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 ~~nine~~three months ended ~~September 30,~~March 31, 2021, and were substantially complete by the end of the first quarter of 2021.

~~In February 2020, the Company notified employees~~

Table of a workforce reduction plan as a result of a strategic realignment of the Company’s organizational structure. 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 nine months ended September 30, 2020, and were substantially complete by the end of the first quarter of 2020.Contents

The ~~following table presents a summary of the restructuring charges included in Operating Income (Loss) for the three and nine months ended September 30, 2021 and 2020:~~

For the three months ended September 30, For the nine months ended September 30,
(in millions) 2021 2020 2021 2020
Severance (including payroll taxes) (1)
$ — $ — $ 7 $ 12

~~(1)Total restructuring charges were $7 million and $12 million for the Company’s E&P segment for the nine months ended September 30, 2021 and 2020, respectively.~~

~~The following table presents a reconciliation of the liability~~Company had no liabilities associated with ~~the Company’s~~ restructuring activities at ~~September 30, 2021, which is reflected in accounts payable on the consolidated balance sheet:~~


~~(in millions)~~
~~Liability at December 31, 2020~~	$	3
~~Additions~~	7
~~Distributions~~	~~(10)~~
~~Liability at September 30, 2021~~	$	—

March 31, 2022 and December 31, 2021.

(4) 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

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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 ~~company~~companies as well as other joint ~~interest~~ owners ~~that~~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.

Disaggregation of Revenues

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

(in millions) E&P Marketing Intersegment
Revenues Total
Three months ended September 30, 2021
Gas sales $ 799 $ — $ 12 $ 811
Oil sales 108 — 2 110
NGL sales 255 — — 255
Marketing — 1,365 (947) 418
Other (1)
3 1 — 4
Total $ 1,165 $ 1,366 $ (933) $ 1,598
Three months ended September 30, 2020
Gas sales $ 190 $ — $ 9 $ 199
Oil sales 39 — 1 40
NGL sales 68 — — 68
Marketing — 495 (276) 219
Other 1 — — 1
Total $ 298 $ 495 $ (266) $ 527

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(in millions)	(in millions)	E&P		Marketing		Intersegment Revenues		Total		(in millions)	E&P		Marketing		Intersegment Revenues		Total
Nine months ended September 30, 2021
Three months ended March 31, 2022										Three months ended March 31, 2022
Gas sales	Gas sales	$	1,671	$	—	$	37	$	1,708	Gas sales	$	1,690	$	—	$	2	$	1,692
Oil sales	Oil sales	293		—		4		297		Oil sales	110		—		1		111
NGL sales	NGL sales	606		—		1		607		NGL sales	272		—		—		272
Marketing	Marketing	—		3,344		(2,242)		1,102		Marketing	—		2,755		(1,889)		866
Other (1)	Other (1)	4		2		—		6		Other (1)	2		—		—		2
Total	Total	$	2,574	$	3,346	$	(2,200)	$	3,720	Total	$	2,074	$	2,755	$	(1,886)	$	2,943

Nine months ended September 30, 2020
Three months ended March 31, 2021										Three months ended March 31, 2021
Gas sales	Gas sales	$	584	$	—	$	27	$	611	Gas sales	$	451	$	—	$	13	$	464
Oil sales	Oil sales	107		—		4		111		Oil sales	80		—		1		81
NGL sales	NGL sales	158		—		—		158		NGL sales	173		—		—		173
Marketing	Marketing	—		1,432		(787)		645		Marketing	—		996		(644)		352
Other (2)	Other (2)	4		—		—		4		Other (2)	1		1		—		2
Total	Total	$	853	$	1,432	$	(756)	$	1,529	Total	$	705	$	997	$	(630)	$	1,072

(1)For the ~~nine~~three months ended ~~September 30,~~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.

~~(2)~~Table of Contents~~For the nine months ended September 30, 2020, other E&P revenues consists primarily of gains on purchaser imbalances associated with certain NGLs.~~

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


		For the three months ended September 30,				For the nine months ended September 30,					For the three months ended March 31,
(in millions)	(in millions)	2021		2020		2021		2020		(in millions)	2022		2021
Appalachia	Appalachia	$	1,033	$	297	$	2,441	$	852	Appalachia	$	1,321	$	704
Haynesville	Haynesville	132		—		132		—		Haynesville	753		—
Other	Other	—		1		1		1		Other	—		1
Total	Total	$	1,165	$	298	$	2,574	$	853	Total	$	2,074	$	705

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)	September 30, 2021		December 31, 2020		(in millions)	March 31, 2022		December 31, 2021
Receivables from contracts with customers	Receivables from contracts with customers	$	678	$	350	Receivables from contracts with customers	$	972	$	1,085
Other accounts receivable	Other accounts receivable	30		18		Other accounts receivable	99		75
Total accounts receivable	Total accounts receivable	$	708	$	368	Total accounts receivable	$	1,071	$	1,160

Amounts recognized against the Company’s allowance for doubtful accounts related to receivables arising from contracts with customers were immaterial for the three ~~and nine~~ months ended ~~September 30,~~March 31, 2022 and 2021, ~~and 2020.~~respectively. The Company has no contract assets or contract liabilities associated with its revenues from contracts with customers.

(5) CASH AND CASH EQUIVALENTS

The following table presents a summary of cash and cash equivalents as of ~~September 30, 2021~~March 31, 2022 and December 31, ~~2020:~~2021:


(in millions)	(in millions)	September 30, 2021		December 31, 2020		(in millions)	March 31, 2022		December 31, 2021
Cash	Cash	$	12	$	13	Cash	$	21	$	28
Marketable securities (1)	Marketable securities (1)	—		—		Marketable securities (1)	—		—

Total	Total	$	12	$	13	Total	$	21	$	28

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

(6) NATURAL GAS AND OIL PROPERTIES

The Company utilizes the full cost method of accounting for costs related to the development, exploration ~~development~~ and acquisition of natural gas and oil properties. Under this method, all such costs (productive and nonproductive), including salaries, benefits

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and other internal costs directly attributable to these activities, are capitalized on a country-by-country basis and amortized over the estimated lives of the properties using the units-of-production method. These capitalized costs are subject to a ceiling test that limits such pooled costs, net of applicable deferred taxes, to the aggregate of the present value of future net revenues attributable to proved natural gas, oil and NGL reserves discounted at 10% (standardized measure). Any costs in excess of the ceiling are written off as a non-cash expense. The expense may not be reversed in future periods, even though higher natural gas, oil and NGL prices may subsequently increase the ceiling. Companies using the full cost method are required to use the average quoted price from the first day of each month from the previous 12 months, including the impact of derivatives designated for hedge accounting, to calculate the ceiling value of their reserves. The Company had no hedge positions that were designated for hedge accounting as of ~~September 30, 2021.~~March 31, 2022. Prices used to calculate the ceiling value of reserves were as follows:
September 30, 2021 September 30, 2020
Natural gas (per MMBtu)
$ 2.94 $ 1.97
Oil (per Bbl)
$ 57.69 $ 43.40
NGLs (per Bbl)
$ 23.26 $ 9.26


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

Using the average quoted prices above, adjusted for market differentials, the Company’s net book value of its United States natural gas and oil properties did not exceed the ceiling amount at ~~September 30, 2021.~~March 31, 2022. 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.~~

~~No impairment expense was recorded for the nine months ended September 30, 2021 in relation~~impairments to the ~~recently acquired Montage~~Company’s natural gas and oil properties. ~~These properties were recorded at fair value as~~

Table of ~~November 13, 2020, in accordance with Accounting Standards Codification (“ASC”) Topic 820 – Fair Value Measurement. In the fourth quarter of 2020, pursuant~~Contents

The Company did not record an impairment expense related to SEC guidance, the Company determined that the fair value of the properties acquired at the closing of the Montage Merger clearly exceeded the related full-cost ceiling limitation beyond a reasonable doubt and received a waiver from the SEC to exclude the properties acquired in the Montage Merger from the ceiling test calculation. This waiver was granted for all reporting periods through and including the quarter ending September 30, 2021, as long as the Company can continue to demonstrate that the fair value of properties acquired clearly exceeds the fullits other non-full cost ceiling limitation beyond a reasonable doubt in each reporting period. As part of the waiver received from the SEC, the Company is required to disclose what the full cost ceiling test impairment amounts for all periods presented in each applicable quarterly and annual filing would have been if the waiver had not been granted. The fair value of the properties acquired in the Montage Merger was based on forward natural gas and oil pricing existing at the date of the Montage Merger, and the Company affirmed that there has not been a material decline to the fair value of these acquired assets since the Montage Merger. The properties acquired in the Montage Merger have an unamortized cost at September 30, 2021 of $1,183 million. Due to the improvement in commodity prices in the second and third quarters of 2021, no impairment charge would have been recorded for the three and nine months ended September 30, 2021 had the acquired Montage naturalpool gas and oil properties ~~been included in~~during the ~~full cost ceiling test.~~

~~The Company’s net book value of its United States natural gas and oil properties exceeded the ceiling by $1.5 billion at~~three months ended March 31, ~~2020, $650 million at June 30, 2020 and $361 million at September 30, 2020, resulting in a non-cash ceiling test impairment for the first, second and third quarters of 2020.~~2022 or 2021.

(7) 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.

In August 2020, the Company completed an underwritten public offering of 63,250,000 shares of its common stock with an offering price to the public of $2.50 per share. Net proceeds after deducting underwriting discounts and offering expenses were approximately $152 million. See ~~Note 2~~ ~~for additional details regarding the Company’s use of proceeds from the equity offering.~~

~~Table of Contents~~

The following table presents the computation of earnings per share for the three ~~and nine~~ months ended ~~September 30, 2021~~March 31, 2022 and ~~2020:~~2021:


		For the three months ended September 30,				For the nine months ended September 30,					For the three months ended March 31,
(in millions, except share/per share amounts)	(in millions, except share/per share amounts)	2021		2020		2021		2020		(in millions, except share/per share amounts)	2022		2021
Net loss		$	(1,857)	$	(593)	$	(2,386)	$	(3,020)
Net income (loss)										Net income (loss)	$	(2,675)	$	80

Number of common shares:	Number of common shares:									Number of common shares:
Weighted average outstanding	Weighted average outstanding	787,032,414		571,872,413		713,455,662		551,162,559		Weighted average outstanding	1,114,610,964		675,385,145
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	—		—		—		—		Effect of issuance of non-vested restricted common stock	—		870,541
Effect of issuance of non-vested restricted units	Effect of issuance of non-vested restricted units	—		—		—		—		Effect of issuance of non-vested restricted units	—		804,944
Effect of issuance of non-vested performance units	Effect of issuance of non-vested performance units	—		—		—		—		Effect of issuance of non-vested performance units	—		2,807,195
Weighted average and potential dilutive outstanding	Weighted average and potential dilutive outstanding	787,032,414		571,872,413		713,455,662		551,162,559		Weighted average and potential dilutive outstanding	1,114,610,964		679,867,825

Loss per common share
Earnings (loss) per common share										Earnings (loss) per common share
Basic	Basic	$	(2.36)	$	(1.04)	$	(3.34)	$	(5.48)	Basic	$	(2.40)	$	0.12
Diluted	Diluted	$	(2.36)	$	(1.04)	$	(3.34)	$	(5.48)	Diluted	$	(2.40)	$	0.12

The following table presents the common stock shares equivalent excluded from the calculation of diluted earnings per share for the three ~~and nine~~ months ended ~~September 30,~~March 31, 2022 and 2021, ~~and 2020,~~ as they would have had an antidilutive effect:


		For the three months ended September 30,		For the nine months ended September 30,			For the three months ended March 31,
		2021	2020	2021	2020		2022	2021
Unexercised stock options	Unexercised stock options	3,699,448	4,425,886	3,742,486	4,519,385	Unexercised stock options	2,948,488	3,795,091
Unvested share-based payment		762,945	939,941	827,279	946,547
Stock-based compensation						Stock-based compensation	1,436,920	—
Restricted stock units	Restricted stock units	3,434,189	1,935,781	3,509,603	2,001,621	Restricted stock units	2,528,005	3,987,291
Performance units	Performance units	2,251,254	2,282,211	2,196,073	2,027,985	Performance units	1,917,579	—
Total	Total	10,147,836	9,583,819	10,275,441	9,495,538	Total	8,830,992	7,782,382

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(8) DERIVATIVES AND RISK MANAGEMENT

The Company is exposed to volatility in market prices and basis differentials for natural gas, oil and NGLs which impacts the predictability of its cash flows related to the sale of those commodities. These risks are managed by the Company’s use of certain derivative financial instruments. As of ~~September 30, 2021,~~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 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.

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

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



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

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

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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 ~~fair value of the Company’s derivative assets and liabilities includes a non-performance risk factor. See~~ ~~Note 10~~ ~~for additional details regarding the Company’s fair value measurements of its derivatives position. The~~ Company presents its derivatives position on a gross basis and does not net the asset and liability positions.

~~Table of Contents~~

The following tables provide information about the Company’s financial instruments that are sensitive to changes in commodity prices and that are used to protect the Company’s exposure. None of the financial instruments below are designated for hedge accounting treatment. The tables present the notional amount, the weighted average contract prices and the fair value by expected maturity dates as of ~~September 30, 2021:~~March 31, 2022:


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 September 30, 2021 (in millions)			Volume (Bcf)	Swaps		Sold Puts		Purchased Puts		Sold Calls		Basis Differential		Fair Value at March 31, 2022 (in millions)
Natural Gas	Natural Gas														Natural Gas
2021
Fixed price swaps		102	$	2.83	$	—	$	—	$	—	$	—	$	(314)
Two-way costless collars		88	—		—		2.70		3.04		—		(253)
Three-way costless collars		84	—		2.19		2.54		2.91		—		(251)
Total		274											$	(818)
2022	2022														2022
Fixed price swaps	Fixed price swaps	539	$	2.77	$	—	$	—	$	—	$	—	$	(868)	Fixed price swaps	627	$	3.04	$	—	$	—	$	—	$	—	$	(1,672)
Two-way costless collars	Two-way costless collars	141	—		—		2.66		3.06		—		(253)		Two-way costless collars	78	—		—		2.53		2.92		—		(216)
Three-way costless collars	Three-way costless collars	333	—		2.06		2.51		2.94		—		(493)		Three-way costless collars	277	—		2.03		2.48		2.88		—		(784)
Total	Total	1,013											$	(1,614)	Total	982											$	(2,672)
2023	2023														2023
Fixed price swaps	Fixed price swaps	274	$	2.76	$	—	$	—	$	—	$	—	$	(192)	Fixed price swaps	504	$	3.08	$	—	$	—	$	—	$	—	$	(675)
Two-way costless collars	Two-way costless collars	83	—		—		2.69		2.92		—		(43)		Two-way costless collars	219	—		—		3.03		3.55		—		(217)
Three-way costless collars	Three-way costless collars	215	—		2.09		2.54		3.00		—		(159)		Three-way costless collars	215	—		2.09		2.54		3.00		—		(355)
Total	Total	572											$	(394)	Total	938											$	(1,247)
2024	2024														2024
Fixed price swaps	Fixed price swaps	57	$	2.43	$	—	$	—	$	—	$	—	$	(42)	Fixed price swaps	224	$	2.96	$	—	$	—	$	—	$	—	$	(174)
Two-way costless collars															Two-way costless collars	44	—		—		3.07		3.53		—		(19)
Three-way costless collars	Three-way costless collars	11	—		2.25		2.80		3.54		—		(6)		Three-way costless collars	11	—		2.25		2.80		3.54		—		(12)
Total	Total	68											$	(48)	Total	279											$	(205)

Basis Swaps	Basis Swaps														Basis Swaps
2021		71	$	—	$	—	$	—	$	—	$	(0.36)	$	19
2022	2022	284	—		—		—		—		(0.38)		17		2022	277	$	—	$	—	$	—	$	—	$	(0.53)	$	72
2023	2023	197	—		—		—		—		(0.49)		2		2023	250	—		—		—		—		(0.47)		20
2024	2024	46	—		—		—		—		(0.71)		3		2024	46	—		—		—		—		(0.71)		9
2025	2025	9	—		—		—		—		(0.64)		1		2025	9	—		—		—		—		(0.64)		3

Total	Total	607											$	42	Total	582											$	104

Table of Contents


	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)

Table of Contents

Volume
(MBbls)
Weighted Average Strike Price per Bbl
Fair Value at
September 30, 2021
(in millions)
Swaps Sold Puts Purchased Puts Sold Calls
Oil
2021
Fixed price swaps 780 $ 48.94 $ — $ — $ — $ (20)
Two-way costless collars 46 — — 37.50 45.50 (1)
Three-way costless collars 550 — 39.18 48.95 54.35 (11)
Total 1,376 $ (32)
2022
Fixed price swaps 3,203 $ 53.54 $ — $ — $ — $ (53)
Three-way costless collars 1,380 — 39.89 50.23 57.05 (20)
Total 4,583 $ (73)
2023
Fixed price swaps 846 $ 55.98 $ — $ — $ — $ (7)
Three-way costless collars 1,268 — 33.97 45.51 56.12 (16)
Total 2,114 $ (23)
2024
Fixed price swaps 54 $ 53.15 $ — $ — $ — $ —
Ethane
2021
Fixed price swaps 2,483 $ 9.74 $ — $ — $ — $ (19)
Two-way costless collars 147 — — 7.14 10.40 (1)
Total 2,630 $ (20)
2022
Fixed price swaps 3,361 $ 10.01�� $ — $ — $ — $ (16)
Two-way costless collars 135 — — 7.56 9.66 (1)
Total 3,496 $ (17)
Propane
2021
Fixed price swaps 2,107 $ 23.98 $ — $ — $ — $ (74)
2022
Fixed price swaps 4,471 $ 26.96 $ — $ — $ — $ (84)
Three-way costless collars 305 — 16.80 21.00 31.92 (5)
Total 4,776 $ (89)
Normal Butane
2021
Fixed price swaps 617 $ 29.08 $ — $ — $ — $ (22)
2022
Fixed price swaps 1,295 $ 29.16 $ — $ — $ — $ (28)
Natural Gasoline
2021
Fixed price swaps 635 $ 43.62 $ — $ — $ — $ (19)
2022
Fixed price swaps 1,256 $ 46.41 $ — $ — $ — $ (26)

~~Table of Contents~~

Other Derivative Contracts
Volume
(Bcf)
Weighted Average Strike Price per MMBtu
Fair Value at
September 30, 2021
(in millions)
Call Options – Natural Gas (Net)
2021 19 $ 3.19 $ (52)
2022 77 3.00 (118)
2023 46 2.94 (37)
2024 9 3.00 (9)
Total 151 $ (216)
Put Options – Natural Gas
2021 5 $ 2.00 $ —
2022 5 2.00 —
Total 10 $ —
Volume
(MBbls)
Weighted Average Strike Price per Bbl
Fair Value at
September 30, 2021
(in millions)
Call Options – Oil
2021 57 $ 60.00 $ (1)
Volume
(Bcf)
Weighted Average Strike Price per MMBtu
Fair Value at
September 30, 2021
(in millions)
Swaptions – Natural Gas
2021 (1)
18 $ 3.00 $ (26)

~~(1)The Company has sold swaptions with an underlying tenor of January 2022 to December 2022, with an exercise date of December 23, 2021.~~

Volume
(Bcf)
Weighted Average Strike Price per MMBtu
Fair Value at
September 30, 2021
(in millions)
Swaps Basis Differential
Storage (1)

2021
Purchased fixed price swaps — $ 2.20 $ — $ 1
Purchased basis swaps — — (0.88) —
Fixed price swaps — 3.17 — —
Basis swaps — — (0.57) —
Total — $ 1
2022
Purchased fixed price swaps — $ 2.14 $ — $ 1
Fixed price swaps 2 2.82 — (5)
Basis swaps 1 — (0.57) —
Total 3 $ (4)


	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.

Purchased Fixed Price Swaps – Marketing (Natural Gas) (1)
Volume
(Bcf)
Weighted Average Strike Price per MMBtu
Fair Value at
September 30, 2021
(in millions)
2021 1 $ 2.44 $ 2

~~(1)The Company has entered into a limited number of derivatives to protect the value of certain long-term sales contracts.~~

At ~~September 30, 2021,~~March 31, 2022, the net fair value of the Company’s financial instruments was a ~~$3,491~~$4,734 million liability, which included ~~a $1 million asset related to interest rate swaps and a~~ net reduction of the liability of $7$8 million related to non-performance risk. See Note 10 for additional details regarding the Company’s fair value measurements of its derivatives position.

~~Table of Contents~~

As of ~~September 30, 2021,~~March 31, 2022, 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 ~~gain~~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 ~~(none of which~~ are ~~designated for hedge accounting treatment) is~~ summarized below as of ~~September 30, 2021~~March 31, 2022 and December 31, ~~2020, and excludes net liability reductions of $7 million and $1 million respectively, for non-performance risk:~~2021:


Derivative Assets	Derivative Assets						Derivative Assets
			Fair Value						Fair Value
(in millions)	(in millions)	Balance Sheet Classification	September 30, 2021		December 31, 2020		(in millions)	Balance Sheet Classification	March 31, 2022		December 31, 2021
Derivatives not designated as hedging instruments:	Derivatives not designated as hedging instruments:						Derivatives not designated as hedging instruments:

Purchased fixed price swaps – natural gas		Derivative assets	$	2	$	1

Fixed price swaps – natural gas	Fixed price swaps – natural gas	Derivative assets	—		37		Fixed price swaps – natural gas	Derivative assets	$	—	$	79
Fixed price swaps – oil		Derivative assets	—		13

Fixed price swaps – ethane							Fixed price swaps – ethane	Derivative assets	—		2
Fixed price swaps – propane							Fixed price swaps – propane	Derivative assets	—		2
Fixed price swaps – normal butane							Fixed price swaps – normal butane	Derivative assets	—		1
Two-way costless collars – natural gas	Two-way costless collars – natural gas	Derivative assets	11		54		Two-way costless collars – natural gas	Derivative assets	10		9

Three-way costless collars – natural gas	Three-way costless collars – natural gas	Derivative assets	13		57		Three-way costless collars – natural gas	Derivative assets	9		12
Three-way costless collars – oil	Three-way costless collars – oil	Derivative assets	1		15		Three-way costless collars – oil	Derivative assets	1		1
Basis swaps – natural gas	Basis swaps – natural gas	Derivative assets	66		60		Basis swaps – natural gas	Derivative assets	82		77
Call options – natural gas		Derivative assets	35		4

Purchased fixed price swaps – natural gas storage	Purchased fixed price swaps – natural gas storage	Derivative assets	2		—		Purchased fixed price swaps – natural gas storage	Derivative assets	1		—

Fixed price swaps – natural gas	Fixed price swaps – natural gas	Other long-term assets	—		7		Fixed price swaps – natural gas	Other long-term assets	—		64
Fixed price swaps – oil		Other long-term assets	—		2

Two-way costless collars – natural gas	Two-way costless collars – natural gas	Other long-term assets	17		20		Two-way costless collars – natural gas	Other long-term assets	44		100

Three-way costless collars – natural gas	Three-way costless collars – natural gas	Other long-term assets	41		87		Three-way costless collars – natural gas	Other long-term assets	12		37
Three-way costless collars – oil	Three-way costless collars – oil	Other long-term assets	4		15		Three-way costless collars – oil	Other long-term assets	1		3
Basis swaps – natural gas	Basis swaps – natural gas	Other long-term assets	44		15		Basis swaps – natural gas	Other long-term assets	70		22

Interest rate swaps	Interest rate swaps	Other long-term assets	1		—		Interest rate swaps	Other long-term assets	—		2
Total derivative assets	Total derivative assets		$	237	$	387	Total derivative assets		$	230	$	411

2220

Table of Contents


Derivative Liabilities	Derivative Liabilities						Derivative Liabilities
			Fair Value						Fair Value
(in millions)	(in millions)	Balance Sheet Classification	September 30, 2021		December 31, 2020		(in millions)	Balance Sheet Classification	March 31, 2022		December 31, 2021
Derivatives not designated as hedging instruments:	Derivatives not designated as hedging instruments:						Derivatives not designated as hedging instruments:

Fixed price swaps – natural gas		Derivative liabilities	$	1,010	$	7
Fixed price swaps – oil		Derivative liabilities	60		12
Fixed price swaps – ethane		Derivative liabilities	32		10
Fixed price swaps – propane		Derivative liabilities	143		36
Fixed price swaps – normal butane		Derivative liabilities	44		8
Fixed price swaps – natural gasoline		Derivative liabilities	40		13
Two-way costless collars – natural gas		Derivative liabilities	495		43
Two-way costless collars – oil		Derivative liabilities	1		1
Two-way costless collars – ethane		Derivative liabilities	2		—
Three-way costless collars – natural gas		Derivative liabilities	650		82
Three-way costless collars – oil		Derivative liabilities	28		15
Three-way costless collars – propane		Derivative liabilities	4		—
Basis swaps – natural gas		Derivative liabilities	48		3
Call options – natural gas		Derivative liabilities	182		12
Call options – oil		Derivative liabilities	1		—
Put options – natural gas		Derivative liabilities	—		1
Swaptions – natural gas		Derivative liabilities	26		2

Fixed price swaps – natural gas storage	Fixed price swaps – natural gas storage	Derivative liabilities	5		—		Fixed price swaps – natural gas storage	Derivative liabilities	$	—	$	1
Fixed price swaps – natural gas	Fixed price swaps – natural gas	Long-term derivative liabilities	406		3		Fixed price swaps – natural gas	Derivative liabilities	1,999		565
Fixed price swaps – oil	Fixed price swaps – oil	Long-term derivative liabilities	20		2		Fixed price swaps – oil	Derivative liabilities	101		60
Fixed price swaps – ethane	Fixed price swaps – ethane	Long-term derivative liabilities	3		—		Fixed price swaps – ethane	Derivative liabilities	28		10
Fixed price swaps – propane	Fixed price swaps – propane	Long-term derivative liabilities	15		2		Fixed price swaps – propane	Derivative liabilities	122		78
Fixed price swaps – normal butane	Fixed price swaps – normal butane	Long-term derivative liabilities	6		1		Fixed price swaps – normal butane	Derivative liabilities	44		27
Fixed price swaps – natural gasoline	Fixed price swaps – natural gasoline	Long-term derivative liabilities	5		2		Fixed price swaps – natural gasoline	Derivative liabilities	59		33
Two-way costless collars – natural gas	Two-way costless collars – natural gas	Long-term derivative liabilities	82		21		Two-way costless collars – natural gas	Derivative liabilities	316		104

Two-way costless collars – ethane							Two-way costless collars – ethane	Derivative liabilities	—		1
Three-way costless collars – natural gas	Three-way costless collars – natural gas	Long-term derivative liabilities	313		102		Three-way costless collars – natural gas	Derivative liabilities	977		298
Three-way costless collars – oil	Three-way costless collars – oil	Long-term derivative liabilities	24		15		Three-way costless collars – oil	Derivative liabilities	49		24
Three-way costless collars – propane	Three-way costless collars – propane	Long-term derivative liabilities	1		—		Three-way costless collars – propane	Derivative liabilities	6		4
Basis swaps – natural gas							Basis swaps – natural gas	Derivative liabilities	43		9
Call options – natural gas							Call options – natural gas	Derivative liabilities	201		67

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

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

Basis swap – natural gas	Basis swap – natural gas	Long-term derivative liabilities	20		7		Basis swap – natural gas	Long-term derivative liabilities	5		22
Call options – natural gas	Call options – natural gas	Long-term derivative liabilities	69		28		Call options – natural gas	Long-term derivative liabilities	57		42

Total derivative liabilities	Total derivative liabilities		$	3,735	$	428	Total derivative liabilities		$	4,972	$	1,916


Net Derivative Position
	March 31, 2022		December 31, 2021
(in millions)
Net current derivative liabilities	$	(3,842)	$	(1,098)
Net long-term derivative liabilities	(900)		(407)
Non-performance risk adjustment	8		3
Net total derivative liabilities	$	(4,734)	$	(1,502)

2321

Table of Contents

The following tables summarize the before-tax effect of the Company’s derivative instruments on the consolidated statements of operations for the three ~~and nine~~ months ended ~~September 30, 2021~~March 31, 2022 and ~~2020:~~2021:

Unsettled Gain (Loss) on Derivatives Recognized in Earnings
Consolidated Statement of Operations Classification of Gain (Loss) on Derivatives, Unsettled For the three months ended September 30, For the nine months ended September 30,
Derivative Instrument 2021 2020 2021 2020
(in millions)
Purchased fixed price swaps – natural gas Gain (Loss) on Derivatives $ (1) $ 4 $ 1 $ 4
Fixed price swaps – natural gas Gain (Loss) on Derivatives (748) (138) (991) (74)
Fixed price swaps – oil Gain (Loss) on Derivatives — (20) (81) 54
Fixed price swaps – ethane Gain (Loss) on Derivatives (12) (13) (25) (23)
Fixed price swaps – propane Gain (Loss) on Derivatives (32) (17) (120) (25)
Fixed price swaps – normal butane Gain (Loss) on Derivatives (7) — (41) —
Fixed price swaps – natural gasoline Gain (Loss) on Derivatives 1 — (30) —
Two-way costless collars – natural gas Gain (Loss) on Derivatives (358) (34) (518) (45)
Two-way costless collars – oil Gain (Loss) on Derivatives 1 (5) — 4
Two-way costless collars – ethane Gain (Loss) on Derivatives (1) — (2) —
Two-way costless collars – propane Gain (Loss) on Derivatives — (1) — (2)
Three-way costless collars – natural gas Gain (Loss) on Derivatives (619) (98) (869) (195)
Three-way costless collars – oil Gain (Loss) on Derivatives — (4) (47) 15
Three-way costless collars – propane Gain (Loss) on Derivatives (3) — (5) —
Basis swaps – natural gas Gain (Loss) on Derivatives (70) 54 (23) 40
Call options – natural gas Gain (Loss) on Derivatives (143) (16) (180) (25)
Call options – oil Gain (Loss) on Derivatives — — (1) 1
Put options – natural gas Gain (Loss) on Derivatives — — 1 —
Swaptions – natural gas Gain (Loss) on Derivatives (21) — (24) —
Purchased fixed price swap – natural gas storage Gain (Loss) on Derivatives 1 1 2 —
Fixed price swap – natural gas storage Gain (Loss) on Derivatives (3) (2) (5) (2)
Interest rate swaps Gain (Loss) on Derivatives — — 1 —
Total loss on unsettled derivatives $ (2,015) $ (289) $ (2,957) $ (273)

~~Table of Contents~~

Settled Gain (Loss) on Derivatives Recognized in Earnings (1)
Consolidated Statement of Operations Classification of Gain (Loss) on Derivatives, Settled For the three months ended September 30, For the nine months ended September 30,
Derivative Instrument 2021 2020 2021 2020
(in millions)
Purchased fixed price swaps – natural gas Gain (Loss) on Derivatives $ 4 $ (2) $ 5 $ (4)
Fixed price swaps – natural gas Gain (Loss) on Derivatives (111) 61 (2) (112) 150 (2)
Fixed price swaps – oil Gain (Loss) on Derivatives (18) 17 (63) 44
Fixed price swaps – ethane Gain (Loss) on Derivatives (13) (2) (23) 6
Fixed price swaps – propane Gain (Loss) on Derivatives (53) 2 (113) 19
Fixed price swaps – normal butane Gain (Loss) on Derivatives (17) — (33) —
Fixed price swaps – natural gasoline Gain (Loss) on Derivatives (16) — (38) —
Two-way costless collars – natural gas Gain (Loss) on Derivatives (79) (5) (79) 1
Two-way costless collars – oil Gain (Loss) on Derivatives (1) 4 (3) 13
Two-way costless collars – ethane Gain (Loss) on Derivatives (1) — (1) —
Two-way costless collars – propane Gain (Loss) on Derivatives — — — 2
Three-way costless collars – natural gas Gain (Loss) on Derivatives (84) — (91) 43
Three-way costless collars – oil Gain (Loss) on Derivatives (10) 1 (16) 5
Basis swaps – natural gas Gain (Loss) on Derivatives 27 20 76 29
Call options – natural gas Gain (Loss) on Derivatives (16) — (16) —
Call options – oil Gain (Loss) on Derivatives (1) — (1) —
Put options – natural gas Gain (Loss) on Derivatives — — (2) (3) —
Purchased fixed price swaps – natural gas storage Gain (Loss) on Derivatives 1 — 1 —
Fixed price swaps – natural gas storage Gain (Loss) on Derivatives — 1 — 2
Total gain (loss) on settled derivatives $ (388) $ 97 $ (509) $ 310

Total Gain (Loss) on Derivatives Recognized in Earnings
For the three months ended September 30, For the nine months ended September 30,
2021 2020 2021 2020
(in millions)
Total loss on unsettled derivatives (2,015) (289) (2,957) (273)
Total gain (loss) on settled derivatives (388) 97 (509) 310
Non-performance risk adjustment 4 — 5 1
Total gain (loss) on derivatives $ (2,399) $ (192) $ (3,461) $ 38


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)

(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 $4$2 million ~~and $8 million~~ in amortization of premiums paid related to certain natural gas fixed price options for the three and nine months ended September 30, 2020, which is included in gain (loss) on derivatives on the consolidated statements of operations.

~~(3)Includes $2 million~~ amortization of premiums paid related to certain natural gas put options for the ~~nine~~three months ended ~~September 30,~~March 31, 2021, which is included in gain (loss) on derivatives on the consolidated statements of operations.

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

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

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

~~Changes in accumulated other comprehensive income for the first nine months of 2021 were related to the Company’s pension and other postretirement benefits.~~ The following tables detail the components of accumulated other comprehensive income and the related tax effects for the ~~nine~~three months ended ~~September 30, 2021:~~March 31, 2022:

(in millions) Pension and Other Postretirement Foreign Currency Total
Beginning balance December 31, 2020 $ (24) $ (14) $ (38)
Other comprehensive income before reclassifications — — —
Amounts reclassified from other comprehensive income (1)
4 — 4
Net current-period other comprehensive income 4 — 4
Ending balance September 30, 2021 $ (20) $ (14) $ (34)

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~~Details about Accumulated Other Comprehensive Income~~

~~Affected Line Item in the Consolidated Statement of Operations~~

~~Amount Reclassified from Accumulated Other Comprehensive Income~~

For the nine months ended
September 30, 2021

~~(in millions)~~

~~Pension and other postretirement:~~

~~Settlement adjustment~~ ~~(1)~~

~~Other Income (Loss), Net~~

~~Provision (Benefit) for Income Taxes~~

~~Net Income~~

~~Total reclassifications for the period~~

~~Net Income~~


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

(1)For 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.

(10) 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 ~~September 30, 2021~~March 31, 2022 and December 31, ~~2020~~2021 were as follows:


		September 30, 2021				December 31, 2020					March 31, 2022				December 31, 2021
(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	$	12	$	12	$	13	$	13	Cash and cash equivalents	$	21	$	21	$	28	$	28
2018 revolving credit facility due April 2024	2018 revolving credit facility due April 2024	665		665		700		700		2018 revolving credit facility due April 2024	174		174		460		460
Term Loan B due 2027										Term Loan B due 2027	549		549		550		550
Senior notes (1)	Senior notes (1)	3,580		3,886		2,471		2,609		Senior notes (1)	4,209		4,318		4,430		4,745
Derivative instruments, net	Derivative instruments, net	(3,491)		(3,491)		(41)		(41)		Derivative instruments, net	(4,734)		(4,734)		(1,502)		(1,502)

(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. ~~Due to limited trading activity, the fair value of the Company’s 4.10% Senior Notes due March 2022 is considered to be a Level 2 measurement on the fair value hierarchy.~~ The fair values of the Company’s ~~more actively traded remaining~~ senior notes are considered ~~the~~to be a Level 1 ~~measurement.~~measurement as these are actively traded in the market. The carrying values of the borrowings under both the Company’s ~~revolving~~2018 credit facility (to the extent utilized) and Term Loan approximates fair value because the interest ~~rate is~~

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

Derivative Instruments: The Company measures the fair value of its derivative instruments based upon a pricing model that utilizes market-based inputs, including, but not limited to, the contractual price of the underlying position, current market prices, natural gas and liquids forward curves, discount rates ~~such as the LIBOR curve~~ 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. As of ~~September 30, 2021~~March 31, 2022 and December 31, ~~2020,~~2021, the impact of non-performance risk on the fair value of the Company’s net derivative ~~asset~~liability position was a ~~decrease~~reduction of the net liability of $7$8 million and $1$3 million, respectively.

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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 and December 31, ~~2020~~2021 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’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:


		September 30, 2021									March 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
Purchased fixed price swaps		$	—	$	2	$	—	$	2

Two-way costless collars	Two-way costless collars	—		28		—		28		Two-way costless collars	$	—	$	54	$	—	$	54
Three-way costless collars	Three-way costless collars	—		59		—		59		Three-way costless collars	—		23		—		23
Basis swaps	Basis swaps	—		110		—		110		Basis swaps	—		152		—		152
Call options		—		35		—		35

Purchased fixed price swaps – storage	Purchased fixed price swaps – storage	—		2		—		2		Purchased fixed price swaps – storage	—		1		—		1
Interest rate swaps		—		1		—		1

Liabilities	Liabilities									Liabilities

Fixed price swaps	Fixed price swaps	—		(1,784)		—		(1,784)		Fixed price swaps	—		(2,906)		—		(2,906)
Two-way costless collars	Two-way costless collars	—		(580)		—		(580)		Two-way costless collars	—		(506)		—		(506)
Three-way costless collars	Three-way costless collars	—		(1,020)		—		(1,020)		Three-way costless collars	—		(1,254)		—		(1,254)
Basis swaps	Basis swaps	—		(68)		—		(68)		Basis swaps	—		(48)		—		(48)
Call options	Call options	—		(252)		—		(252)		Call options	—		(258)		—		(258)

Swaptions		—		(26)		—		(26)
Fixed price swaps – storage		—		(5)		—		(5)

Total (1)	Total (1)	$	—	$	(3,498)	$	—	$	(3,498)	Total (1)	$	—	$	(4,742)	$	—	$	(4,742)

(1)Excludes a net reduction to the liability fair value of $7$8 million related to estimated non-performance risk.

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		December 31, 2020									December 31, 2021
		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
Purchased fixed price swaps		$	—	$	1	$	—	$	1

Fixed price swaps	Fixed price swaps	—		59		—		59		Fixed price swaps	$	—	$	148	$	—	$	148
Two-way costless collars	Two-way costless collars	—		74		—		74		Two-way costless collars	—		109		—		109
Three-way costless collars	Three-way costless collars	—		174		—		174		Three-way costless collars	—		53		—		53
Basis swaps	Basis swaps	—		75		—		75		Basis swaps	—		99		—		99
Call options		—		4		—		4
Interest rate swaps										Interest rate swaps	—		2		—		2

Liabilities	Liabilities									Liabilities

Fixed price swaps	Fixed price swaps	—		(96)		—		(96)		Fixed price swaps	—		(1,031)		—		(1,031)
Two-way costless collars	Two-way costless collars	—		(65)		—		(65)		Two-way costless collars	—		(220)		—		(220)
Three-way costless collars	Three-way costless collars	—		(214)		—		(214)		Three-way costless collars	—		(525)		—		(525)
Basis swaps	Basis swaps	—		(10)		—		(10)		Basis swaps	—		(31)		—		(31)
Call options	Call options	—		(40)		—		(40)		Call options	—		(109)		—		(109)
Put options		—		(1)		—		(1)
Swaptions		—		(2)		—		(2)

Total (1)	Total (1)	$	—	$	(41)	$	—	$	(41)	Total (1)	$	—	$	(1,505)	$	—	$	(1,505)

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

See Note 14 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

In the third quarter of 2021, the Company determined that the carrying value of certain non-core assets exceeded their respective fair value less costs to sell and recognized a $6 million non-cash impairment. The Company ~~used Level 3 measurements to determine~~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 ~~these assets.~~assets acquired and liabilities assumed.

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(11) DEBT

The components of debt as of ~~September 30, 2021~~March 31, 2022 and December 31, ~~2020~~2021 consisted of the following:


		September 30, 2021										March 31, 2022
(in millions)	(in millions)	Debt Instrument		Unamortized Issuance Expense			Unamortized Debt Premium		Total		(in millions)	Debt Instrument			Unamortized Issuance Expense			Unamortized Debt Premium/Discount		Total
Current portion of long-term debt:	Current portion of long-term debt:										Current portion of long-term debt:
4.10% Senior Notes due March 2022		$	201	$	—		$	—	$	201
Variable rate (3.3% at March 31, 2022) Term Loan B due June 2027											Variable rate (3.3% at March 31, 2022) Term Loan B due June 2027	$	5	(1)	$	—		$	—	$	5
Total current portion of long-term debt	Total current portion of long-term debt	$	201	$	—		$	—	$	201	Total current portion of long-term debt	$	5		$	—		$	—	$	5

Long-term debt:	Long-term debt:										Long-term debt:
Variable rate (2.08% at September 30, 2021) 2018 revolving credit facility due April 2024		$	665	$	—	(1)	$	—	$	665
Variable rate (2.10% at March 31, 2022) 2018 revolving credit facility due April 2024											Variable rate (2.10% at March 31, 2022) 2018 revolving credit facility due April 2024	$	174		$	—	(2)	$	—	$	174
4.95% Senior Notes due January 2025 ~~(2)~~(3)	4.95% Senior Notes due January 2025 ~~(2)~~(3)	689		(3)			—		686		4.95% Senior Notes due January 2025 ~~(2)~~(3)	389			(1)			—		388
Variable rate (3.3% at March 31, 2022) Term Loan B due June 2027											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	7.75% Senior Notes due October 2027	440		(4)			—		436		7.75% Senior Notes due October 2027	425			(4)			—		421
8.375% Senior Notes due September 2028	8.375% Senior Notes due September 2028	350		(5)			—		345		8.375% Senior Notes due September 2028	345			(5)			—		340
5.375% Senior Notes due February 2029	5.375% Senior Notes due February 2029	700		(5)			26		721		5.375% Senior Notes due February 2029	700			(6)			24		718
5.375% Senior Notes due September 2030	5.375% Senior Notes due September 2030	1,200		(17)			—		1,183		5.375% Senior Notes due September 2030	1,200			(16)			—		1,184
4.75% Senior Notes due February 2032											4.75% Senior Notes due February 2032	1,150			(16)			—		1,134
Total long-term debt	Total long-term debt	$	4,044	$	(34)		$	26	$	4,036	Total long-term debt	$	4,927		$	(55)		$	23	$	4,895

Total debt	Total debt	$	4,245	$	(34)		$	26	$	4,237	Total debt	$	4,932		$	(55)		$	23	$	4,900

		December 31, 2020										December 31, 2021
(in millions)	(in millions)	Debt Instrument		Unamortized Issuance Expense			Unamortized Debt Discount		Total		(in millions)	Debt Instrument			Unamortized Issuance Expense			Unamortized Debt Premium/Discount		Total
Current portion of long-term debt:											Current portion of long-term debt:
4.10% Senior Notes due March 2022											4.10% Senior Notes due March 2022	$	201		$	—		$	—	$	201
Variable rate (3.0% at December 31, 2021) Term Loan B due June 2027											Variable rate (3.0% at December 31, 2021) Term Loan B due June 2027	5		(1)	—			—		5
Total current portion of long-term debt											Total current portion of long-term debt	$	206		$	—		$	—	$	206

Long-term debt:	Long-term debt:										Long-term debt:
Variable rate (2.11% at December 31, 2020) 2018 revolving credit facility due April 2024		$	700	$	—	(1)	$	—	$	700
4.10% Senior Notes due March 2022		207		—			—		207
4.95% Senior Notes due January 2025 (2)		856		(4)			(1)		851
7.50% Senior Notes due April 2026		618		(6)			—		612
Variable rate (2.08% at December 31, 2021) 2018 revolving credit facility, due April 2024											Variable rate (2.08% at December 31, 2021) 2018 revolving credit facility, due April 2024	$	460		$	—	(2)	$	—	$	460
4.95% Senior Notes due January 2025 (3)											4.95% Senior Notes due January 2025 (3)	389			(1)			—		388
Variable rate (3.0% at December 31, 2021) Term Loan B due June 2027											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		(5)			—		435		7.75% Senior Notes due October 2027	440			(4)			—		436
8.375% Senior Notes due September 2028	8.375% Senior Notes due September 2028	350		(5)			—		345		8.375% Senior Notes due September 2028	350			(5)			—		345
5.375% Senior Notes due September 2029											5.375% Senior Notes due September 2029	700			(6)			25		719
5.375% Senior Notes due March 2030											5.375% Senior Notes due March 2030	1,200			(17)			—		1,183
4.75% Senior Notes due February 2032											4.75% Senior Notes due February 2032	1,150			(17)			—		1,133
Total long-term debt	Total long-term debt	$	3,171	$	(20)		$	(1)	$	3,150	Total long-term debt	$	5,234		$	(57)		$	24	$	5,201

Total debt											Total debt	$	5,440		$	(57)		$	24	$	5,407

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

(2)At ~~September 30, 2021~~March 31, 2022 and December 31, ~~2020,~~2021, unamortized issuance expense of ~~$10~~$9 million and ~~$12~~$10 million, respectively, associated with the 2018 credit facility (as defined below) was classified as other long-term assets on the consolidated balance sheets.

~~(2)~~(3)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 ~~will have the effect of decreasing~~decreased the interest rate on the 2025 Notes to ~~6.20%~~5.95% beginning with coupon payments paid after January 2022.

The following is a summary of scheduled debt maturities by year as of ~~September 30, 2021:~~March 31, 2022 and includes the quarterly Term Loan principal repayments of $1.375 million, subject to adjustment for voluntary prepayments, beginning in March 2022:


(in millions)	(in millions)			(in millions)
2021		$	—
2022	2022	201		2022	$	4
2023	2023	—		2023	6
2024 (1)	2024 (1)	665		2024 (1)	179
2025	2025	689		2025	395
2026				2026	5
Thereafter	Thereafter	2,690		Thereafter	4,343
		$	4,245		$	4,932

(1)~~The~~As of March 31, 2022, the Company’s ~~current revolving~~2018 credit facility matures in 2024.

~~Table~~ In April 2022, the 2018 credit facility was amended and restated resulting in the extension of ~~Contents~~the maturity date to 2027.

Credit Facilities

2018 ~~Revolving~~ Credit Facility

In April 2018, the Company ~~replaced its credit facility that was~~ entered into ~~in 2016 with~~ a ~~new~~ 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 ~~September~~October 2021, the banks participating in the 2018 credit facility reaffirmed the elected borrowing base and aggregate commitments to be $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 permitted lien provisions in ~~certain~~the senior ~~note~~notes indentures currently limit liens securing indebtedness to the greater of $2.0 billion orand 25% of adjusted consolidated net tangible ~~assets, which is currently approximately $2.9 billion.~~assets.

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 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 ~~contains~~ 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 ~~ending~~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 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 ~~credit agreement governing the~~ Company’s 2018 credit ~~facility,~~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-based~~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 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 2018 credit facility may become immediately due and payable. As of ~~September 30, 2021,~~March 31, 2022, the Company was in compliance with all of the covenants ~~contained in~~of the credit agreement ~~governing the 2018 credit facility.~~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 ~~September 30, 2021,~~March 31, 2022, the Company had ~~$159~~$147 million in letters of credit and ~~$665~~$174 million in 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

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.

The Company may utilize the 2022 credit facility in the form of loans and letters of credit. Loans under 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 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 2022 credit facility range between 0.375% to 0.50%, depending on the percentage of the commitments utilized.

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

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

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

•restrictions on mergers and asset dispositions;

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

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

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

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,

•The collateral under the facility will be released,

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

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

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

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

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

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

Upon receiving two Investment Grade Ratings from S&P, Moody’s, or Fitch (such period following, an “Investment Grade Period”), certain restrictive covenants fall away or become more permissive. Upon Investment Grade Period, the leverage ratio and current ratio financial covenants and PV-9 Coverage Ratio will no longer be effective, and the Company will be required to maintain compliance with a total indebtedness to capitalization ratio, which is the ratio of the Company’s total indebtedness to the sum of total indebtedness plus stockholders’ equity, not to exceed 65%.

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, the Company had 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) credit facility, (iii) prepaying any other secured indebtedness that is secured by a lien, or some combination thereof. As of March 31, 2022, the Company was in compliance with the quarterly coverage ratio test.

The Company’s ~~debt exposure to~~obligations under the ~~anticipated transition from LIBOR in late 2021 is limited to~~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. The USD-LIBOR settings are expected to be published through June 2023 and Southwestern anticipates using a variation of this rate until the underlying agreements are extended beyond the LIBOR publication date.

Senior Notes

In January 2015, the Company completed a public offering of $1.0 billion aggregate principal amount of its 4.95% ~~senior notes~~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 ~~the initial offering.~~their issuance. On April 7, 2020, S&P downgraded the Company’s bond rating to BB-, which had the effect of increasing the interest rate on the 2025 Notes to 6.45% following the July 23, 2020 interest payment due date. The first coupon payment to the 2025 Notes bondholders at the higher interest rate was paid in January 2021. On September 1, 2021, S&P upgraded the Company’s bond rating to BB, and on January 6, 2022, S&P further upgraded the Company’s bond rating to BB+, which ~~will have the effect of decreasing~~decreased the interest rate on the 2025 Notes to ~~6.20%~~5.95% beginning with coupon payments paid after January 2022.

In the first half of 2020, the Company repurchased $6 million of its 4.10% Senior Notes due 2022, $36 million of its 4.95% Senior Notes due 2025, $21 million of its 7.50% Senior Notes due 2026 and $44 million of its 7.75% Senior Notes due 2027 for $72 million, and recognized a $35 million gain on the extinguishment of debt.

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 ~~revolving~~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 June 1, 2021, Southwestern entered into the Indigo Merger Agreement. Upon the close of the Indigo Merger in September 2021, and pursuant to the terms of the Indigo Merger Agreement, Southwestern assumed $700 million in aggregate principal amount of 5.375% Senior Notes due 2029 of Indigo (“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. Subsequent to the Indigo Merger, the Company exchanged the Indigo Notes for approximately $700 million of newly issued 5.375% Senior Notes due 2029, which are expected to be registered with the SEC in November 2021.

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 of the Company’s 7.50% Senior Notes due 2026, $167 million of the Company’s 4.95% Senior Notes due 2025 and $6 million of the Company’s 4.10% Senior Notes due 2022 for ~~$844~~$845 million, and the Company recognized a ~~$59~~$60 million loss 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 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.

In the first quarter of 2022, the Company repurchased the remaining outstanding principal balance of $201 million of its 4.10% Senior Notes, $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.

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(12) COMMITMENTS AND CONTINGENCIES

Operating Commitments and Contingencies

As of ~~September 30, 2021,~~March 31, 2022, the Company’s contractual obligations for demand and similar charges under firm transportation and gathering agreements to guarantee access capacity on natural gas and liquids pipelines and gathering systems totaled approximately ~~$9.8~~$10.2 billion, ~~$382~~$857 million 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 ~~$884~~$877 million of that total amount. As of ~~September 30, 2021,~~March 31, 2022, 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	$	9,415	$	903	$	1,965	$	1,677	$	2,115	$	2,755	Infrastructure currently in service	$	9,301	$	1,066	$	1,943	$	1,729	$	2,085	$	2,478
Pending regulatory approval and/or construction (1)	Pending regulatory approval and/or construction (1)	382		2		18		27		57		278		Pending regulatory approval and/or construction (1)	857		3		124		161		247		322
Total transportation charges	Total transportation charges	$	9,797	$	905	$	1,983	$	1,704	$	2,172	$	3,033	Total transportation charges	$	10,158	$	1,069	$	2,067	$	1,890	$	2,332	$	2,800

(1)Based on estimated in-service dates as of ~~September 30, 2021.~~March 31, 2022.

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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 ~~will assume~~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 ~~September 30, 2021,~~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 ~~our~~its portion of the estimated future payments.

Excluding the Cotton Valley gathering agreement (discussed above), the Company has recorded additional liabilities totaling ~~$81~~$35 million as of ~~September 30, 2021,~~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 ~~a period ranging from~~the next two ~~to seven~~ 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 ~~September 30, 2021,~~March 31, 2022, the Company does not currently have any material amounts accrued related to litigation matters, including the cases 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.

~~St. Lucie County Fire District Firefighters’ Pension Trust~~

On October 17, 2016, the St. Lucie County Fire District Firefighters’ Pension Trust filed a putative class action in the 61st District Court in Harris County, Texas, against the Company, certain of its former officers and current and former directors and the underwriters on behalf of itself and others that purchased certain depositary shares from the Company’s January 2015 equity offering, alleging material misstatements and omissions in the registration statement for that offering. The Company removed the case to federal court, but after a decision by the United States Supreme Court in an unrelated case that these types of cases are not subject to removal, the federal court remanded the case to the Texas state court. The Texas trial court denied the Company’s motion to dismiss, and in February 2020, the court of appeals declined to exercise discretion to reverse the trial court’s decision. The Company filed a petition to review the trial court’s decision with the Texas Supreme Court, and the Court requested a response from the plaintiff. The Court subsequently requested full briefing on the merits of the case. The Company carries insurance for the claims asserted against it and the officer and director defendants, and the carrier accepted coverage. On June 15, 2021, the parties agreed to a settlement of the case without any admission of liability. The Company’s insurance carrier is fully funding the settlement amount. On October 21, 2021, the court orally approved the settlement agreement. It signed a final judgment dismissing the litigation on October 22, 2021. The Company expects the court to enter an amended final judgment that authorizes the disbursement of the settlement amount.

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.

On June 12, 2018, a collection of 51 individuals and entities filed a lawsuit against 15 oil and gas company defendants, including Indigo, in Louisiana state court claiming damages arising out of current and historical ~~exploration~~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 ~~exploration~~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

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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.

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, and litigation, such as the St. Lucie County Fire District Firefighters’ Pension Trust case described above.~~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) INCOME TAXES

The Company’s effective tax rate was approximately 0% for the three ~~and nine~~ months ended ~~September 30, 2021.~~March 31, 2022. The effective tax rate for the three ~~and nine~~ months ~~September 30, 2021~~ended March 31, 2022 related to the effects of a valuation allowance against the Company’s U.S. deferred tax assets. A valuation allowance for deferred tax assets, including net operating losses, is recognized when it is more likely than not that some or all of the benefit from the deferred tax assets will not be realized. To assess that likelihood, the Company uses estimates and judgment regarding future taxable income, and considers the tax consequences in the jurisdiction where such taxable income is generated, to determine whether a valuation allowance is required. Such evidence can include current financial position, results of operations, both actual and forecasted, the reversal of deferred tax liabilities and tax planning strategies as well as current and forecasted business economics of the oil and gas industry.

In 2020, due to significant pricing declines and the material write-down of the carrying value of the Company’s natural gas and oil properties in addition to other negative evidence, the Company concluded that it was more likely than not that these deferred tax assets will not be realized and recorded a valuation allowance. As of the ~~third~~first quarter of ~~2021,~~2022, the Company still maintains a full valuation allowance. The Company also retained a valuation allowance of ~~$87~~$59 million related to net operating losses in jurisdictions in which it no longer operates. Management will continue to assess available positive and negative evidence to estimate whether sufficient future taxable income will be generated to permit the use 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 deferred tax assets until there is sufficient evidence to support the reversal of all or some portion of the allowance. However, if current commodity prices are sustained 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.

The Company’s effective tax rate was approximately 0% ~~and (16)%~~ for the three ~~and nine~~ months ended ~~September 30, 2020, respectively.~~March 31, 2021. The effective tax rate for the ~~nine~~three months ended ~~September 30, 2020 was primarily~~March 31, 2021 related to the ~~effect~~effects of ~~recording~~ the valuation allowance ~~discussed above.~~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”) 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. At ~~September 30, 2021,~~March 31, 2022, the Company had approximately ~~$4.5~~$4 billion of federal

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NOL carryovers, of which approximately $3 billion expire between 2035 and 2037 and ~~$1.5~~$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 NOLs remain subject to a full valuation allowance. If a subsequent ownership

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change were to occur as a result of future transactions in the Company’s common stock, the Company’s use of remaining U.S. tax attributes may be further limited.

~~The~~For three months ended March 31, 2022, the Company ~~adopted Accounting Standards Update No. 2019-12 (“ASU 2019-12”) in the~~recorded current ~~period. ASU 2019-12 addressed simplification to~~ income tax ~~accounting rules, such~~expense of approximately $4 million as ~~removing a few exceptions~~it expects to ~~intraperiod allocation. There was no material impact to~~pay cash income taxes for the ~~financial statements as a result of this adoption.~~year ended December 31, 2022.

(14) PENSION PLAN AND OTHER POSTRETIREMENT BENEFITS

~~The Company maintains defined pension and other postretirement benefit plans, which cover~~Prior to January 1, 2021, substantially all of the Company’s ~~employees.~~employees were covered by the defined benefit pension, a cash balance plan that provided benefits based upon a fixed percentage of an employee’s annual compensation. As part of an ongoing effort to reduce costs, the Company elected to freeze its pension plan effective January 1, 2021. Employees that were participants in the pension plan prior to January 1, 2021 ~~will continue~~continued to receive anthe interest ~~credit to their benefit under~~component of the plan but ~~will~~ no longer ~~receive a benefit accrual for additional years of~~received the service ~~due to the plan freeze.~~

component. On September 13, 2021, the Compensation Committee of the Board of Directors approved terminating the Company’s ~~Pension Plan,~~pension plan, effective December 31, 2021, subject to approval by the Internal Revenue Service. This decision, among other benefits, will provide plan participants quicker access to, and greater flexibility in, the management of participants’ respective benefits due under the plan.

The Company has commenced the ~~Pension Plan~~pension plan termination process, but the specific date for the completion of the process is unknown at this time and will depend on certain legal and regulatory requirements or approvals. As part of the termination process, the Company expects to distribute lump sum payments to or purchase annuities for the benefit of plan participants, which is dependent on the participants’ elections.

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 ~~addition,~~the event a plan is overfunded, the Company ~~expects to make~~recognizes an asset. Conversely, if a ~~payment equal to~~plan is underfunded, the ~~difference between the total benefits due under the plan and the total value of the assets available, which, as of September 30, 2021, was approximately $7 million. The~~ Company ~~is in the process of evaluating the impact of the termination and future settlement accounting on its consolidated financial statements and related disclosures.~~recognizes a liability.

Net periodic pension costs include the following components for the three ~~and nine~~ months ended ~~September 30, 2021~~March 31, 2022 and ~~2020:~~2021:


		Consolidated Statements of Operations Classification of Net Periodic Benefit Cost	For the three months ended September 30,				For the nine months ended September 30,					Consolidated Statements of Operations Classification of Net Periodic Benefit Cost	For the three months ended March 31,
(in millions)	(in millions)		2021		2020		2021		2020		(in millions)		2022		2021
Service cost	Service cost	General and administrative expenses	$	—	$	2	$	—	$	6	Service cost	General and administrative expenses	$	—	$	—
Interest cost	Interest cost	Other Income (Loss), Net	1		1		3		3		Interest cost	Other Income (Loss), Net	1		1
Expected return on plan assets	Expected return on plan assets	Other Income (Loss), Net	—		(2)		(3)		(5)		Expected return on plan assets	Other Income (Loss), Net	—		(1)

Amortization of net loss	Amortization of net loss	Other Income (Loss), Net	—		1		—		1		Amortization of net loss	Other Income (Loss), Net	—		—
Settlement loss	Settlement loss	Other Income (Loss), Net	—		—		1		—		Settlement loss	Other Income (Loss), Net	—		—
Net periodic benefit cost	Net periodic benefit cost		$	1	$	2	$	1	$	5	Net periodic benefit cost		$	1	$	—

The Company recognized ~~a $1 million~~an immaterial non-cash settlement loss ~~related to $6 million of lump sum payments from the pension plan~~ in the first ~~three quarters~~quarter of 2021. As a result of settlement accounting requirements, the Company recorded a $3 million reduction to its net pension liability in the first three quarters of 2021, with a corresponding reduction to accumulated other comprehensive loss.2022.

The Company’s other postretirement benefit plan had a net periodic benefit cost of less than$1 $1 million for each of the three months ended ~~September 30, 2021~~March 31, 2022 and ~~2020, respectively, and $1 million and $2 million for the nine months ended September 30, 2021 and 2020, respectively.~~2021.

~~As of September 30, 2021, the~~The Company ~~has contributed~~ ~~$12 million~~ ~~to the pension and other postretirement benefit plans and~~ does not expect to make any additional contributions to its pension plan during ~~the remainder of 2021~~2022 or thereafter until the plan termination is completed. The Company recognized liabilities of ~~$17~~$12 million and ~~$14~~$13 million related to its pension and other postretirement benefits ~~respectively,~~ as of ~~September 30, 2021, compared to liabilities of $33 million~~both March 31, 2022 and ~~$13 million as of~~ December 31, ~~2020, respectively.~~2021.

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 shares at March 31, 2022 and 2,035 shares ~~and 3,632 shares~~ at ~~September 30, 2021 and~~ December 31, ~~2020, respectively.~~2021.

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(15) 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 years from the date of grant. However, the Company has not granted stock options since February 2017. The Company issues shares of restricted stock, restricted stock units or performance cash awards to employees and directors which generally vest over three years. Restricted stock, restricted stock units ~~performance cash awards~~ and stock options granted to participants under the 2013 Incentive Plan, as amended and restated, immediately vest upon death, disability or retirement (subject to a minimum of three years of service). The Company issues performance unit awards to employees which historically have vested at or over three years. The performance units granted in 2019, 2020 and 2021 cliff-vest at the end of three years.

In February of 2021, ~~and 2020,~~ the Company notified employees of a workforce reduction ~~plans~~plan as a result of strategic realignments of the Company’s organizational structure. ~~These reductions were~~The reduction was substantially complete by the end of the first quarter of ~~each respective year.~~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.

The Company recognized the following amounts in total ~~employee stock-based~~related to long-term incentive compensation costs for the three ~~and nine~~ months ended ~~September 30, 2021~~March 31, 2022 and ~~2020:~~2021:

For the three months ended September 30, For the nine months ended September 30,
(in millions) 2021 2020 2021 2020
Stock-based compensation cost – expensed $ 5 $ 2 $ 27 $ 8
Stock-based compensation cost – capitalized 2 2 12 3


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

Equity-Classified Awards

The Company recognized the following amounts in employee equity-classified stock-based compensation costs for the three ~~and nine~~ months ended ~~September 30, 2021~~March 31, 2022 and ~~2020:~~2021:


		For the three months ended September 30,				For the nine months ended September 30,					For the three months ended March 31,
(in millions)	(in millions)	2021		2020		2021		2020		(in millions)	2022		2021
Equity-classified awards – expensed	Equity-classified awards – expensed	$	—	$	—	$	2	$	2	Equity-classified awards – expensed	$	1	$	—
Equity-classified awards – capitalized	Equity-classified awards – capitalized	—		1		—		1		Equity-classified awards – capitalized	$	—	$	—

As of September 30, 2021, there was less than $1 million of total unrecognized compensation cost related to the Company’s unvested equity-classified stock option grants, equity-classified restricted stock grants and equity-classified performance units. This cost is expected to be recognized over a weighted-average period of 1.8 years.

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Equity-Classified Stock Options

The following table summarizes equity-classified stock option activity for the ~~nine~~three months ended ~~September 30, 2021~~March 31, 2022 and provides information for options outstanding and options exercisable as of ~~September 30, 2021:~~March 31, 2022:


		Number of Options	Weighted Average Exercise Price			Number of Options	Weighted Average Exercise Price
		(in thousands)				(in thousands)
Outstanding at December 31, 2020		3,850	$	13.39
Outstanding at December 31, 2021					Outstanding at December 31, 2021	3,006	$	8.98
Granted	Granted	—	$	—	Granted	—	$	—
Exercised	Exercised	—	$	—	Exercised	—	$	—
Forfeited or expired	Forfeited or expired	(151)	$	32.21	Forfeited or expired	(152)	$	26.35
Outstanding at September 30, 2021		3,699	$	12.63
Exercisable at September 30, 2021		3,699	$	12.63
Outstanding at March 31, 2022					Outstanding at March 31, 2022	2,854	$	8.06
Exercisable at March 31, 2022					Exercisable at March 31, 2022	2,854	$	8.06

Equity-Classified Restricted Stock

The following table summarizes equity-classified restricted stock activity for the ~~nine~~three months ended ~~September 30, 2021~~March 31, 2022 and provides information for unvested shares as of ~~September 30, 2021:~~March 31, 2022:


		Number of Shares	Weighted Average Fair Value			Number of Shares	Weighted Average Fair Value
		(in thousands)				(in thousands)
Unvested shares at December 31, 2020		697	$	5.97
Unvested shares at December 31, 2021					Unvested shares at December 31, 2021	242	$	5.12
Granted	Granted	438	$	5.18	Granted	—	$	—
Vested	Vested	(893)	$	5.81	Vested	(43)	$	4.90
Forfeited	Forfeited	—	$	8.59	Forfeited	—	$	—
Unvested shares at September 30, 2021		242	$	5.12
Unvested shares at March 31, 2022					Unvested shares at March 31, 2022	199	$	5.17

As of March 31, 2022, 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 years.

Equity-Classified Restricted Stock Units

As of March 31, 2022, there was $7 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 ~~result~~weighted-average period of ~~the Montage Merger, certain employees became employees of Southwestern and retained their original equity awards.~~2.6 years. The following table summarizes equity-classified ~~performance unit activity~~restricted stock units for the ~~nine~~three months ended ~~September 30, 2021~~March 31, 2022 and provides information for unvested units as of ~~September 30, 2021.~~March 31, 2022.


		Number of Shares	Weighted Average Fair Value			Number of Shares	Weighted Average Fair Value
		(in thousands)				(in thousands)
Unvested units at December 31, 2020		134	$	3.05
Unvested units at December 31, 2021					Unvested units at December 31, 2021	37	$	3.05
Granted	Granted	—	$	—	Granted	1,699	$	4.45
Vested	Vested	(87)	$	3.05	Vested	—	$	—
Forfeited	Forfeited	—	$	—	Forfeited	(2)	$	3.05
Unvested units at September 30, 2021		47	$	3.05
Unvested units at March 31, 2022					Unvested units at March 31, 2022	1,734	$	4.42

Equity-Classified Performance Units

In each year beginning with 2018, the Company granted performance units that vest at the end of, or over, a three-year period and are payable in either cash or shares at the option of the Compensation Committee of the Company’s Board of Directors. The awards granted from 2018 through 2021 were accounted for as liability-classified awards as the intention of the awards was to settle in cash. In 2022, two types of awards were granted, one of which was accounted for as liability classified awards given the intention to settle in cash. The other awards granted during 2022 have been accounted for as equity-classified awards given the intention to settle in stock and accordingly are recognized at their fair value as of the grant date and amortized throughout the vesting period. The 2022 performance unit awards include a market condition based on relative TSR. The fair values of the market conditions were calculated by Monte Carlo models as of the grant date. As of March 31, 2022, there was

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$5 million of total unrecognized compensation costs related to the Company’s unvested equity-classified performance units. This cost is expected to be recognized over a weighted-average period of 2.9 years.


	Number of Shares	Weighted Average Fair Value
	(in thousands)
Unvested units at December 31, 2021	—	$	—
Granted	850	$	6.04
Vested	—	$	—
Forfeited	—	$	—
Unvested units at March 31, 2022	850	$	6.04

Liability-Classified Awards

The Company recognized the following amounts in employee liability-classified stock-based compensation costs for the three ~~and nine~~ months ended ~~September 30, 2021:~~March 31, 2022:

For the three months ended September 30, For the nine months ended September 30,
(in millions) 2021 2020 2021 2020
Liability-classified stock-based compensation cost – expensed $ 5 $ 2 $ 25 $ 6
Liability-classified stock-based compensation cost – capitalized 2 1 12 2

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

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. The liability classified awards granted in 2021 vest over a period of three years. The Company has accounted for these as liability-classified awards, and accordingly changes in the market value of the instruments will be recorded to general and administrative expense and capitalized expense over the vesting period of the award. As of ~~September 30, 2021,~~March 31, 2022, there was ~~$27~~$23 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 ~~1.1~~1.6 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, 2020		11,613	$	2.67
Unvested units at December 31, 2021					Unvested units at December 31, 2021	7,937	$	4.08
Granted	Granted	1,486	$	4.23	Granted	—	$	—
Vested	Vested	(4,522)	$	3.40	Vested	(3,806)	$	4.47
Forfeited	Forfeited	(592)	$	4.55	Forfeited	(12)	$	7.01
Unvested units at September 30, 2021		7,985	$	4.80
Unvested units at March 31, 2022					Unvested units at March 31, 2022	4,119	$	5.83

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 at the option of the Compensation Committee of the Company’s Board of Directors. The Company has accounted for these as liability-classified awards, and accordingly changes in the fair market value of the instruments will be recorded to general and administrative expense and capitalized expense over the vesting period of the awards. The performance unit awards granted in 2018 include a performance condition based on cash flow per debt-adjusted share and two market conditions, one based on absolute TSR and the other on relative TSR as compared to a group of the Company’s peers. 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. In ~~the first half of~~ 2021, 2 types of performance unit awards were granted. One 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. In 2022, two types of performance unit awards were granted. One type of award includes a 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 market conditions are calculated by Monte Carlo models on a quarterly basis. As of ~~September 30, 2021,~~March 31, 2022, there was ~~$20~~$18 million of total unrecognized compensation cost related to liability-classified performance units. This cost is expected to be recognized over a weighted-average period of 1.8 years. The amount of unrecognized compensation cost for liability-classified

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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
(in thousands)
Unvested units at December 31, 2020 8,699 $ 2.57
Granted 3,580 $ 4.14
Vested (2,020) $ 4.05
Forfeited (744) $ 3.40
Unvested units at September 30, 2021 9,515 $ 3.32


	Number of Units	Weighted Average Fair Value
	(in thousands)
Unvested units at December 31, 2021	9,515	$	2.88
Granted	3,798	$	1.00
Vested (1)	(1,910)	$	6.45
Forfeited	—	$	—
Unvested units at March 31, 2022	11,403	$	3.51

(1)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 and 2021:


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

Performance Cash Awards

In 2021 and 2020, the Company granted performance cash awards that vest over a ~~four-year~~4-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 2020 include a performance condition determined annually by the Company. For both years, the performance measure is a targeted discretionary cash flow amount. If the Company, in its sole discretion, determines that the threshold was not met, the amount for that vesting period will not vest and will be cancelled. As of ~~September 30, 2021,~~March 31, 2022, there was ~~$24~~$42 million of total unrecognized compensation cost related to performance cash awards. This cost is expected to be

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recognized over a ~~weighted average 3.0~~weighted-average period of 3.2 years. The final value of the performance cash awards is contingent upon the Company’s actual performance against these performance measures.


		Number of Units	Weighted Average Fair Value			Number of Units	Weighted Average Fair Value
		(in thousands)				(in thousands)
Unvested units at December 31, 2020		18,353	$	1.00
Unvested units at December 31, 2021					Unvested units at December 31, 2021	28,272	$	1.00
Granted	Granted	18,546	$	1.00	Granted	24,416	$	1.00
Vested	Vested	(4,955)	$	1.00	Vested	(8,483)	$	1.00
Forfeited	Forfeited	(3,008)	$	1.00	Forfeited	(675)	$	1.00
Unvested units at September 30, 2021		28,936	$	1.00
Unvested units at March 31, 2022					Unvested units at March 31, 2022	43,530	$	1.00

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(16) 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 ~~2020~~2021 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.

E&P Marketing Other Total
Three months ended September 30, 2021 (in millions)
Revenues from external customers $ 1,179 $ 419 $ — $ 1,598
Intersegment revenues (14) 947 — 933
Depreciation, depletion and amortization expense 136 2 — 138
Impairments 6 — — 6
Operating income 628 (1) 8 — 636
Interest expense (2)
34 — — 34
Loss on derivatives (2,398) — (1) (2,399)
Loss on extinguishment of debt — — (59) (59)
Other loss, net (1) — — (1)
Assets 8,572 (3) 546 123 9,241
Capital investments (4)
291 — — 291
Three months ended September 30, 2020
Revenues from external customers $ 308 $ 219 $ — $ 527
Intersegment revenues (10) 276 — 266
Depreciation, depletion and amortization expense 68 2 — 70
Impairments 361 — — 361
Operating loss (379) (1) (2) — (381)
Interest expense (2)
22 — — 22
Loss on derivatives (192) — — (192)
Other income, net 2 — — 2
Assets 3,705 (3) 240 212 4,157
Capital investments (4)
223 — — 223

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E&P Marketing Other Total
Nine months ended September 30, 2021 (in millions)
Revenues from external customers $ 2,616 $ 1,104 $ — $ 3,720
Intersegment revenues (42) 2,242 — 2,200
Depreciation, depletion and amortization expense 327 7 — 334
Impairments 6 — — 6
Operating income 1,209 (1) 21 — 1,230
Interest expense (2)
95 — — 95
Loss on derivatives (3,461) — — (3,461)
Loss on early extinguishment of debt — — (59) (59)
Other loss, net (1) — — (1)
Assets 8,572 (3) 546 123 9,241
Capital investments (4)
816 — — 816
Nine months ended September 30, 2020
Revenues from external customers $ 884 $ 645 $ — $ 1,529
Intersegment revenues (31) 787 — 756
Depreciation, depletion and amortization expense 260 7 — 267
Impairments 2,495 — — 2,495
Operating loss (2,613) (1) (14) — (2,627)
Interest expense (2)
63 — — 63
Gain on derivatives 38 — — 38
Gain on early extinguishment of debt — — 35 35
Other income, net 2 — 1 3
Benefit from income taxes (2)
406 — — 406
Assets 3,705 (3) 240 212 4,157
Capital investments (4)
705 — — 705


	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

(1)Operating income (loss) for the E&P segment includes ~~$7 million and $12~~$6 million of restructuring charges for the ~~nine~~three months ended ~~September 30, 2021 and 2020, respectively.~~2021. The E&P segment operating income (loss) also includes ~~$35~~$25 million and $3$1 million of merger-related expenses for the three months ended ~~September 30,~~March 31, 2022 and 2021, ~~and 2020, respectively, and $39 million and $3 million for the nine months ended September 30, 2021 and 2020, respectively, for merger-related expenses.~~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)E&P assets includes office, technology, water infrastructure, drilling rigs and other ancillary equipment not directly related to natural gas and oil properties.

(4)Capital investments ~~includes an increase~~include increases of ~~$34~~$43 million and ~~a decrease of $7~~$38 million for the three months ended ~~September 30,~~March 31, 2022 and 2021, ~~and 2020, respectively, and increases of $63 million and $1 million for the nine months ended September 30, 2021 and 2020,~~ respectively, relating to the change in accrued expenditures between periods.

The following table presents the breakout of other assets, which represent corporate assets not allocated to segments and assets for non-reportable segments at ~~September 30, 2021~~March 31, 2022 and ~~2020:~~2021:


		As of September 30,					As of March 31,
(in millions)	(in millions)	2021		2020		(in millions)	2022		2021
Cash and cash equivalents	Cash and cash equivalents	$	12	$	95	Cash and cash equivalents	$	21	$	4
Accounts receivable	Accounts receivable	4		7		Accounts receivable	1		—

Prepayments	Prepayments	13		3		Prepayments	6		6
Property, plant and equipment	Property, plant and equipment	12		18		Property, plant and equipment	10		15
Unamortized debt expense	Unamortized debt expense	10		10		Unamortized debt expense	9		11
Right-of-use lease assets	Right-of-use lease assets	67		74		Right-of-use lease assets	63		70
Non-qualified retirement plan	Non-qualified retirement plan	4		5		Non-qualified retirement plan	2		4
Long-term hedging asset (interest rate swaps)		1		—
		$	123	$	212
							$	112	$	110

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(17) NEW ACCOUNTING PRONOUNCEMENTS

New Accounting Standards Implemented in this Report

In ~~August 2018,~~March 2020, the ~~Financial Accounting Standards Board (the “FASB”)~~FASB issued ASU ~~2018-14, Disclosure Framework – Changes to the Disclosure Requirements for Defined Benefit Plans (“ASU 2018-14”). ASU 2018-14 amends, adds and removes certain disclosure requirements under FASB~~2020-04, Reference Rate Reform, as a new ASC Topic, ~~715 – Compensation – Retirement Benefits.~~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 away

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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 ~~2018-14 is~~are effective for ~~fiscal years~~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 ~~after December 15, 2020 and was adopted on January 1, 2021. Adoption~~in the second quarter of ~~ASU 2018-14~~2022. The change from LIBOR to SOFR rates will ~~result in certain disclosure changes within the Company's footnote disclosures. The adoption of ASU 2018-14 did~~ not have a material impact on the ~~Company's~~Company’s consolidated financial statements.

In December 2019, the FASB issued ASU 2019-12, Income Taxes (Topic 740): Simplifying the Accounting for Income Taxes. ASU 2019-12 eliminates certain exceptions to the guidance in Topic 740 related to the approach for intraperiod tax allocation, the methodology for calculating income taxes in an interim period, and the recognition of deferred tax liabilities for outside basis differences. The new guidance also clarifies certain aspects of the existing guidance, among other things. The standard became effective for interim and annual periods beginning after December 15, 2020 and shall be applied on either a prospective basis, a retrospective basis for all periods presented, or a modified retrospective basis through a cumulative-effect adjustment to retained earnings depending on which aspects of the new standard are applicable to an entity. The Company adopted the new standard on January 1, 2021 on a prospective basis, which did not have a material impact on its consolidated financial statements.

New Accounting Standards Not Yet Adopted 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 away from Interbank Offered Rates, such as LIBOR, which is expected to be phased out at the end of calendar year 2021, to alternative reference rates. ASC 848 applies only to contracts, hedging relationships, debt arrangements and other transactionsNone 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 ASU 2020-04 are ~~effective for all entities as of March 12, 2020 through December 31, 2022.~~

The USD-LIBOR settings are expected to be published through June 2023 and Southwestern anticipates using a variation of this rate until the underlying agreements are extended beyond the LIBOR publication date. The Company continues to assess the impact of the new guidance, but the change in the LIBOR rate variation is not expected to have a material ~~impact on the consolidated financial statements.~~

~~(18)SUBSEQUENT EVENTS~~

On November 3, 2021, Southwestern entered into an Agreement and Plan of Merger with Mustang Acquisition Company, LLC (“Merger Sub”), GEP Haynesville LLC (“GEPH”) and GEPH Unitholder Rep, LLC, the Unitholder representative, (the “GEPH Merger Agreement”). Pursuant to the terms of the GEPH Merger Agreement, GEPH will merge with and into Merger Sub, a subsidiary of Southwestern, with GEPH surviving the merger (the “GEPH Merger”). Under the terms and conditions of the GEPH Merger Agreement, on the closing date, each issued and outstanding Preferred Unit (as defined in the GEPH Merger Agreement) will be redeemed in full for an aggregate amount in cash equal to $1,165 million. The aggregate consideration to be paid to the holders of GEPH units in the transaction will consist of $160 million in cash and 99,337,748 shares of Southwestern common stock, which shares have an aggregate dollar value equal to $525 million based on the volume weighted average sales price as traded on the New York Stock Exchange of such shares calculated for the thirty trading day period ending on November 2, 2021. The cash consideration and stock consideration are subject to adjustment as provided in the GEPH Merger Agreement. The transaction is expected to close on or around December 31, 2021, subject to customary closing conditions.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 ~~2020~~2021 Annual Report and analyzes the changes in the results of operations between the three ~~and nine~~ month periods ended ~~September 30, 2021~~March 31, 2022 and ~~2020.~~2021. 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 ~~2020~~2021 Annual Report.

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Factors” in Part I and elsewhere in our ~~2020~~2021 Annual Report. You should read the following discussion with our consolidated financial statements and the related notes included in this Quarterly Report.

OVERVIEW

Background

~~Southwestern Energy Company (including its subsidiaries, collectively, “we,” “our,” “us,” “the Company” or “Southwestern”) is~~We are an independent energy company engaged in natural gas, oil and ~~natural gas liquids (“NGLs”)~~NGLs development, exploration ~~development~~ 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.”~~“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 ~~exploration for~~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 ~~focuses~~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.

~~On June 1, 2021,~~ In just over one year, we 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”) and on September 1, 2021, we closed this deal. Pursuanthave completed three strategic acquisitions which have added scale to the terms of the Indigo Merger Agreement, Indigo merged with and into Ikon, a subsidiary of Southwestern, and became a subsidiary of Southwestern (the “Indigo Merger”). The outstanding equity interests in Indigo were cancelled and converted into the right to receive (i) $373 million in cash consideration, and (ii) 337,827,171 shares of Southwestern common stock, in each case, subject to adjustment as provided in the Indigo Merger Agreement. Additionally, we assumed $700 million in aggregate principal amount of 5.375% Senior Notes due 2029 of Indigo (the “Indigo Notes”). The shares of Southwestern common stock had an aggregate dollar value equal to $1,588 million, based on the closing price of $4.70 per share of Southwestern common stock on the NYSE on September 1, 2021.

Following the closing of the Indigo Merger, Southwestern’s existing shareholders and Indigo’s existing equity holders owned approximately 67% and 33%, respectively, of the outstanding shares of the combined company. The Indigo Merger is expected to diversify our operations ~~by expanding~~and have laid the foundation for our ~~portfolio into the Haynesville formation and give us additional exposure to the markets on the Gulf Coast.~~future:

•On November 13, 2020, we closed on ~~our Agreement and Plan of~~the Montage Merger, ~~with Montage Resources Corporation (“Montage”) pursuant to~~ which ~~Montage merged with and into Southwestern, with Southwestern continuing as the surviving company (the “Montage Merger”). The Montage Merger~~ 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 our strategy to diversify our operations by expanding our 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 our enterprise business risk, expanded our economic inventory, opportunity set and business optionality and enabled immediate cost structure savings. See Note 2 to the consolidated financial statements ~~of this Quarterly Report~~ for more information on the ~~Montage Merger.~~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.

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Recent Financial and Operating Results

Significant ~~third~~first quarter ~~2021~~2022 operating and financial results include:

Total Company

•Net loss of ~~$1,857~~$2,675 million, or ($~~2.36)~~2.40) per diluted share, ~~increased~~decreased compared to net ~~loss~~income of ~~$593~~$80 million, or ~~($1.04)~~$0.12 per diluted share, for the same period in ~~2020.~~2021. Net loss ~~increased~~decreased primarily as a ~~$1,017~~$998 million increase in operating income was more than offset by a ~~$2,207~~$3,736 million reduction resulting from the impact of improved forward pricing on our derivatives position, ~~$1,722~~$3,063 million of which was unrealized. Excluding the change in derivatives position, ~~and $361 million non-cash full cost ceiling test impairment recorded in the third quarters of 2021 and 2020, respectively,~~ net income increased ~~$582~~$981 million in the ~~third~~first quarter of ~~2021,~~2022, compared to the same period in ~~2020,~~2021, primarily as a ~~$656~~$998 million improvement in operating income was partially offset by a ~~$59~~$2 million loss on the early extinguishment of debt recorded in the ~~third~~first quarter of ~~2021~~2022 and a ~~$12~~$10 million increase in interest ~~expense.~~

~~Table~~expense from the first quarter of ~~Contents~~2022 as compared to the same period in 2021.

•Operating income of ~~$636~~$1,299 million increased compared to operating ~~loss~~income of ~~$381~~$301 million for the same period in ~~2020~~2021 on a consolidated basis. Operating ~~loss in the third quarter of 2020 included a $361~~income increased $1,871 million, ~~non-cash full cost ceiling test impairment. Excluding the non-cash impairment, operating income improved $656 million, compared to the same period in 2020,~~ as ~~a $1,071 million increase in operating revenues more than~~increased commodity pricing and natural gas production were only partially offset ~~a $415 million increase in~~by increased operating costs ~~primarily associated with increased production, and expenses.~~of $873 million.

•Net cash provided by operating activities of ~~$213~~$972 million increased ~~39%~~180% from ~~$153~~$347 million for the same period in ~~2020 as the effects of~~2021 which was mostly attributable to higher production due to our recently acquired Haynesville assets coupled with improved commodity ~~pricing and higher production were only~~pricing. This increase was partially offset by ~~a decrease in~~an increased loss on settled derivatives combined with an increase in operating expenses associated with ~~higher liquids production.~~our recently acquired Haynesville assets.

•Total capital investment of ~~$291~~$544 million in the ~~third~~first quarter of ~~2021~~2022 increased ~~30%~~105% from ~~$223~~$266 million for the same period in ~~2020.~~

•~~Closed an offering~~2021 due to the addition of $1,200 million aggregate principal amount of 5.375% Senior Notes due 2030 with net proceeds of $1,183 million, after underwriting discounts and offering expenses, and repurchased $791 million of our outstanding senior notes.the acquired Haynesville assets.

E&P

•E&P ~~segment operating loss of $379 million for the third quarter of 2020 included a non-cash full cost ceiling test impairment of $361 million. Excluding the non-cash impairment, E&P~~ operating income of ~~$628~~$1,278 million in the ~~third~~first quarter of ~~2021~~2022 increased ~~$646~~$983 million, compared to the same period in ~~2020,~~2021, primarily as an ~~$867~~$1,369 million increase in E&P operating revenues resulting from a ~~$2.40~~$2.26 per Mcfe increase in our realized weighted average price per Mcfe (excluding derivatives) and an 89156 Bcfe increase in production volumes was only partially offset by a ~~$221~~$386 million increase in E&P operating costs and expenses.

•Total net production of ~~310~~425 Bcfe, which was comprised of ~~81%~~88% natural gas and ~~19%~~12% oil and NGLs, increased ~~40%~~58% from ~~221~~269 Bcfe in the same period in ~~2020,~~2021, primarily due to a ~~45%~~76% increase in our natural gas production ~~46% and 39% of~~ which was ~~associated with natural gas production~~driven by the Haynesville assets acquired from ~~our Montage Merger-~~Indigo and ~~Indigo Merger-related properties acquired~~GEPH in ~~November 2020~~September 2021 and ~~September~~December 2021, respectively.

•Excluding the effect of derivatives, our realized natural gas price of ~~$3.18~~$4.50 per ~~Mcf~~Mcfe increased ~~192%~~113%, our realized oil price of ~~$62.32~~$86.30 per barrel increased ~~112%~~79% and our realized NGL price of ~~$31.76~~$39.33 per barrel increased ~~207%~~72%, as compared to the same period in ~~2020.~~2021. Excluding the effect of derivatives, our total weighted average realized price of ~~$3.74~~$4.88 per Mcfe increased ~~179%~~86% from the same period in ~~2020.~~2021.

•E&P segment invested ~~$291~~$544 million in capital; drilling 1733 wells, completing 2337 wells and placing 2432 wells to sales.

Outlook

Our primary focus in ~~2021~~2022 is to ~~strengthen~~maintain our production profile and improve the ~~balance sheet~~safety and ~~maximize value with disciplined investment across our portfolio. We expect to accomplish this by:~~

•~~Maximizing Our Margins~~. We will continue to concentrate our efforts on our highest return investment opportunities and look for ways to further reduce our cost structure and build on the synergies from our Montage and Indigo mergers while further developing our knowledgeefficiency of our ~~asset base.~~

•~~Generating Free Cash Flow. We expect~~operations to ~~generate cash flow from operations, net of changes in working capital, in excess of~~optimize our ~~expected capital investments, which are designed~~ability to ~~keep our daily production at levels consistent with the end of last year. Additionally, we expect to maintain a hedging program that ensures a certain level of cash flow.~~

•~~Reducing Our Debt. We intend to utilize~~generate free cash flow ~~generated in 2021 to pay down our debt,~~(defined below) and further strengthen our balance ~~sheet~~sheet.

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

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

•~~Building~~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.

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•Focus on Execution. We are focused on operating effectively and efficiently with HSE and ESG as core values; building on 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; 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 strategic transactions that we believe will ~~continue to seek opportunities to leverage~~enhance enterprise returns and deliver financial synergies and operational economies. We believe these transactions lower the risk of our ~~operational expertise of integrating and developing large-scale assets to~~business, expand our ~~portfolio, create economies~~opportunity set, increase business optionality and build upon our demonstrated record of ~~scale and increase optionality in~~asset integration. We strive to deliver those benefits of strategic transactions to our ~~operations and~~business.

We remain committed to achieving these objectives while maintaining our ~~capital investment program.~~

commitment to being environmentally conscious. 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 ~~Item 1A, “Risk Factors” in Part I~~the 2021 Annual Report. As such, we aim to monitor and ~~elsewhere in~~seek ways to minimize the environmental impact of our ~~2020 Annual Report.~~

~~Table~~operations. Additionally, we intend to protect our financial strength by reducing our debt while continuing to extend the weighted average years to maturity of ~~Contents~~

our debt, and by maintaining a derivative program designed to reduce our exposure to commodity price volatility.

COVID-19

During the first ~~three quarters~~quarter of ~~2021,~~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. We~~pandemic, and we continue to monitor ~~the~~its impact ~~of COVID-19~~ 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 ~~exploration for~~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 ~~travel and in-person meeting restrictions and other~~ physical distancing measures. The degree to which the COVID-19 pandemic or any other public health crisis adversely impacts our ~~results~~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 expense, gain (loss) on derivatives, gain (loss) on early extinguishment of debt and income taxes are discussed on a consolidated basis.

E&P


		For the three months ended September 30,						For the nine months ended September 30,							For the three months ended March 31,
(in millions)	(in millions)	2021			2020			2021			2020			(in millions)	2022			2021
Revenues	Revenues	$	1,165		$	298		$	2,574		$	853		Revenues	$	2,074		$	705
Operating costs and expenses	Operating costs and expenses	537		(1)	677		(2)	1,365		(1)	3,466		(2)	Operating costs and expenses	796		(1)	410		(2)
Operating income (loss)		$	628		$	(379)		$	1,209		$	(2,613)
Operating income														Operating income	$	1,278		$	295

Gain (loss) on derivatives, settled	Gain (loss) on derivatives, settled	$	(388)		$	97		$	(509)		$	310		Gain (loss) on derivatives, settled	$	(695)		$	(22)

(1)Includes ~~$7 million in restructuring charges for the nine months ended September 30, 2021, $35 million and $39~~$25 million in merger-related expenses for the three ~~and nine~~ months ended ~~September 30, 2021, respectively, and $6 million related to the non-cash impairment of other non-core assets for the three and nine months ended September 30, 2021.~~March 31, 2022.

(2)Includes ~~$361 million and $2,490 million related to non-cash full cost ceiling test impairments for the three and nine months ended September 30, 2020, respectively, $12~~$6 million in restructuring charges and $1 million in merger-related expenses for the ~~nine~~three months ended ~~September 30, 2020 and $5 million related to the non-cash impairment of other non-core assets for the nine months ended September 30, 2020.~~March 31, 2021.

Operating Income (Loss)

•E&P segment operating income increased ~~$1,007~~$983 million for the three months ended ~~September 30, 2021,~~March 31, 2022, compared to the same period in 2020. The operating loss for the third quarter of 2020 included a $361 million non-cash full cost ceiling test impairment. Excluding the effect of the impairment, operating income improved $646 million, compared to the same period in 2020, as an $8672021. A $1,369 million increase in E&P operating revenues resulting from ~~a 179%~~an 86% increase in our realized weighted average price per Mcfe (excluding derivatives) and a ~~40%~~58% increase in production volumes was only partially offset by a ~~$221~~$386 million increase in E&P operating costs and expenses.

•Operating income for the E&P segment increased $3,822 million for the nine months ended September 30, 2021 compared to the same period in 2020. The operating loss for the nine months ended September 30, 2020 included a $2,490 million non-cash full cost ceiling test impairment. Excluding the effect of the impairment, operating income improved $1,332 million, compared to the same period in 2020, as a $1,721 million increase in E&P operating revenues resulting from a 121% increase in our realized weighted average price per Mcfe (excluding derivatives) and a 37% increase in production volumes was only partially offset by a $389 million increase in E&P operating costs and expenses.

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Revenues

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


		Three months ended September 30,													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
2020 sales revenues (1)		$	190		$	39		$	68		$	297
2021 sales revenues (1)														2021 sales revenues (1)	$	451		$	80		$	173		$	704
Changes associated with prices	Changes associated with prices	524			56			173			753			Changes associated with prices	897			49			114			1,060
Changes associated with production volumes	Changes associated with production volumes	85			13			14			112			Changes associated with production volumes	342			(19)			(15)			308
2021 sales revenues (2)		$	799		$	108		$	255		$	1,162
Increase from 2020		321		%	177		%	275		%	291		%
2022 sales revenues (2)														2022 sales revenues (2)	$	1,690		$	110		$	272		$	2,072
Increase from 2021														Increase from 2021	275		%	38		%	57		%	194		%

(1)Excludes $1 million in other operating revenues for the three months ended ~~September 30, 2020~~March 31, 2021 primarily related to gas ~~balancing gains.~~balancing.

(2)Excludes $3$2 million in other operating revenues for the three months ended ~~September 30, 2021~~March 31, 2022 primarily related to gas ~~balancing gains.~~

Nine months ended September 30,
(in millions except percentages) Natural
Gas Oil NGLs Total
2020 sales revenues (1)
$ 584 $ 107 $ 158 $ 849
Changes associated with prices 851 145 412 1,408
Changes associated with production volumes 236 41 36 313
2021 sales revenues (2)
$ 1,671 $ 293 $ 606 $ 2,570
Increase from 2020 186 % 174 % 284 % 203 %

~~(1)Excludes $4 million in other operating revenues for the nine months ended September 30, 2020 primarily related to gains on purchaser imbalances associated with certain NGLs.~~

~~(2)Excludes $4 million in other operating revenues for the nine months ended September 30, 2021 primarily related to gains on purchaser imbalances associated with certain NGLs.~~balancing.

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Production Volumes


		For the three months ended September 30,				Increase/(Decrease)		For the nine months ended September 30,					Increase/(Decrease)			For the three months ended March 31,							Increase/(Decrease)
Production volumes:	Production volumes:	2021		2020			2021			2020				Production volumes:	2022		2021		Increase/(Decrease)
Natural Gas (Bcf)	Natural Gas (Bcf)																					Natural Gas (Bcf)
Appalachia	Appalachia	221		173		28%		654			487		34%					Appalachia			210				214		(2)%
Haynesville		30		—		100%		30			—		100%
Haynesville (1)																		Haynesville (1)	166				—			100%

Total	Total	251		173		45%		684			487		40%					Total	376				214			76%

Oil (MBbls)	Oil (MBbls)																	Oil (MBbls)
Appalachia	Appalachia	1,722		1,290		33%		5,206			3,764		38%					Appalachia	1,263				1,658			(24)%
Haynesville		2		—		100%		2			—		100%
Haynesville (1)																		Haynesville (1)	4				—			100%
Other	Other	5		4		25%		14			12		17%					Other	3				4			(25)%
Total	Total	1,729		1,294		34%		5,222			3,776		38%					Total	1,270				1,662			(24)%

NGL (MBbls)	NGL (MBbls)																	NGL (MBbls)
Appalachia	Appalachia	8,011		6,687		20%		23,253			18,924		23%					Appalachia	6,919				7,577			(9)%
Other	Other	—		—		—%		2			2		—%					Other	—				1			(100)%
Total	Total	8,011		6,687		20%		23,255			18,926		23%					Total	6,919				7,578			(9)%

Production volumes by area: (Bcfe)	Production volumes by area: (Bcfe)																	Production volumes by area: (Bcfe)
Appalachia	Appalachia	280		221		27%		825			623		32%					Appalachia	259				269			(4)%
Haynesville		30		—		100%		30			—		100%
Haynesville (1)																		Haynesville (1)	166				—			100%

Total	Total	310		221		40%		855			623		37%					Total	425				269			58%

Production volumes by formation: (Bcfe)	Production volumes by formation: (Bcfe)																	Production volumes by formation: (Bcfe)
Marcellus Shale	Marcellus Shale	245		221		11%		700			622		13%					Marcellus Shale	217				213			2%
Utica Shale ~~(1)~~	Utica Shale ~~(1)~~	34		—		100%		124			1		12,300%					Utica Shale ~~(1)~~	42				56			(25)%
Haynesville Shale(1)	Haynesville Shale(1)	16		—		100%		16			—		100%					Haynesville Shale(1)	105				—			100%
Bossier Shale(1)	Bossier Shale(1)	14		—		100%		14			—		100%					Bossier Shale(1)	61				—			100%
Other		1		—		100%		1			—		100%

Total	Total	310		221		40%		855			623		37%					Total	425				269			58%

Production percentage:	Production percentage:																	Production percentage:
Natural gas	Natural gas	81	%	78	%			80	%		78	%						Natural gas	88	%			79	%
Oil	Oil	3	%	4	%			4	%		4	%						Oil	2	%			4	%
NGL	NGL	16	%	18	%			16	%		18	%						NGL	10	%			17	%

(1)~~Prior to~~The Haynesville E&P assets were acquired through the ~~Montage~~Indigo Merger and the GEPH Merger in ~~November 2020, our production from the Utica Shale was immaterial.~~September 2021 and December 2021, respectively.

•E&P production volumes increased by 89156 Bcfe for the three months ended ~~September 30, 2021,~~March 31, 2022, compared to the same period in ~~2020, primarily~~2021, due to ~~incremental~~the recent acquisitions of producing natural gas and oil properties in Haynesville from Indigo in September 2021 and GEPH in December 2021. Production of 166 Bcfe from these properties more than offset a 10 Bcfe decrease in Appalachia production, ~~volumes of 42 Bcfe associated with the properties acquired from Montage in November 2020 and 30 Bcfe associated with the recently acquired Indigo properties.~~

•~~E&P production volumes increased by 232 Bcfe for the nine months ended September 30, 2021,~~as compared to the same period in ~~2020, primarily~~2021, due to ~~incremental production volumes of 134 Bcfe associated with the properties acquired from Montage in November 2020 and 30 Bcfe associated with the~~a higher capital allocation to our recently acquired ~~Indigo properties.~~Haynesville assets.

•Oil and NGL production ~~increased 34% and 20%, respectively,~~decreased 11% for the three months ended ~~September 30, 2021,~~March 31, 2022, compared to the same period in ~~2020. Production volumes associated with the properties~~2021, primarily due to a higher capital allocation to our recently acquired ~~from Montage in November 2020 were 260 MBbls and 800 MBbls for oil and NGLs, respectively, for the three months ended September 30, 2021.~~Haynesville assets.

•Oil and NGL production increased 38% and 23%, respectively, for the nine months ended September 30, 2021, compared to the same period in 2020. Production volumes associated with the properties acquired from Montage in November 2020 were 900 MBbls and 2,604 MBbls for oil and NGLs, respectively, for the nine months ended September 30, 2021.

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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 ~~exploration and~~ 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 ~~hedging~~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 ~~as well as our hedging strategy~~ in order to maintain appropriate liquidity and financial flexibility.

For the three months ended September 30, Increase/(Decrease) For the nine months ended September 30, Increase/(Decrease)
2021 2020 2021 2020
Natural Gas Price:
NYMEX Henry Hub Price ($/MMBtu) (1)
$ 4.01 $ 1.98 103% $ 3.18 $ 1.88 69%
Discount to NYMEX (2)
(0.83) (0.89) (7)% (0.74) (0.68) 9%
Average realized gas price, excluding derivatives ($/Mcf)
$ 3.18 $ 1.09 192% $ 2.44 $ 1.20 103%
Gain on settled financial basis derivatives ($/Mcf)
0.11 0.12 0.11 0.06
Gain (loss) on settled commodity derivatives ($/Mcf)
(1.14) 0.31 (0.43) 0.39
Average realized gas price, including derivatives ($/Mcf)
$ 2.15 $ 1.52 41% $ 2.12 $ 1.65 28%
Oil Price:
WTI oil price ($/Bbl) (3)
$ 70.56 $ 40.93 72% $ 64.82 $ 38.32 69%
Discount to WTI (8.24) (11.47) (28)% (8.71) (10.12) (14)%
Average oil price, excluding derivatives ($/Bbl)
$ 62.32 $ 29.46 112% $ 56.11 $ 28.20 99%
Gain (loss) on settled derivatives ($/Bbl)
(17.49) 17.23 (16.05) 16.77
Average oil price, including derivatives ($/Bbl)
$ 44.83 $ 46.69 (4)% $ 40.06 $ 44.97 (11)%
NGL Price:
Average realized NGL price, excluding derivatives ($/Bbl)
$ 31.76 $ 10.34 207% $ 26.05 $ 8.37 211%
Gain (loss) on settled derivatives ($/Bbl)
(12.45) 0.16 (8.92) 1.48
Average realized NGL price, including derivatives ($/Bbl)
$ 19.31 $ 10.50 84% $ 17.13 $ 9.85 74%
Percentage of WTI, excluding derivatives 45% 25% 40% 22%
Total Weighted Average Realized Price:
Excluding derivatives ($/Mcfe)
$ 3.74 $ 1.34 179% $ 3.01 $ 1.36 121%
Including derivatives ($/Mcfe)
$ 2.49 $ 1.78 40% $ 2.41 $ 1.86 30%

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

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

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

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

(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 ~~charges~~ 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 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 ~~ensure~~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 to the consolidated financial statements, included in this Quarterly Report.

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The ~~table~~tables below ~~presents~~present the amount of our future natural gas production in which the impact of basis ~~is protected~~volatility has been limited through derivatives and physical sales arrangements as of ~~September 30, 2021:~~March 31, 2022:


		Volume (Bcf)	Basis Differential			Volume (Bcf)	Basis Differential
Basis Swaps – Natural Gas	Basis Swaps – Natural Gas				Basis Swaps – Natural Gas
2021		71	$	(0.36)
2022	2022	284	(0.38)		2022	277	$	(0.53)
2023	2023	197	(0.49)		2023	250	(0.47)
2024	2024	46	(0.71)		2024	46	(0.71)
2025	2025	9	(0.64)		2025	9	(0.64)

Total	Total	607			Total	582

Physical NYMEX Sales Arrangements – Natural Gas(1)	Physical NYMEX Sales Arrangements – Natural Gas(1)				Physical NYMEX Sales Arrangements – Natural Gas(1)
2021		167	$	(0.16)
2022	2022	514	(0.12)		2022	621	$	(0.17)
2023	2023	375	(0.08)		2023	565	(0.10)
2024	2024	292	(0.06)		2024	391	(0.07)
2025	2025	252	(0.04)		2025	303	(0.04)
2026	2026	125	0.01		2026	138	—
2027	2027	125	0.01		2027	126	0.01
2028	2028	125	0.01		2028	125	0.01
2029	2029	125	0.01		2029	125	0.01
2030	2030	47	—		2030	47	—

Total	Total	2,147			Total	2,441

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

In addition to protecting basis, the table below presents the amount of our future production in which price is financially protected as of ~~September 30, 2021:~~March 31, 2022:


		Remaining 2021	Full Year 2022	Full Year 2023	Full Year 2024		Remaining 2022	Full Year 2023	Full Year 2024
Natural gas (Bcf)	Natural gas (Bcf)	274	1,013	572	68	Natural gas (Bcf)	982	938	279
Oil (MBbls)	Oil (MBbls)	1,376	4,583	2,114	54	Oil (MBbls)	3,413	2,114	603
Ethane (MBbls)	Ethane (MBbls)	2,630	3,496	—	—	Ethane (MBbls)	4,142	1,308	—
Propane (MBbls)	Propane (MBbls)	2,107	4,776	—	—	Propane (MBbls)	4,873	1,066	—
Normal Butane (MBbls)	Normal Butane (MBbls)	617	1,295	—	—	Normal Butane (MBbls)	1,388	329	—
Natural Gasoline (MBbls)	Natural Gasoline (MBbls)	635	1,256	—	—	Natural Gasoline (MBbls)	1,497	359	—
Total financial protection on future production (Bcfe)	Total financial protection on future production (Bcfe)	318	1,105	585	68	Total financial protection on future production (Bcfe)	1,074	969	283

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

Operating Costs and Expenses

For the three months ended September 30, Increase/(Decrease) For the nine months ended September 30, Increase/(Decrease)
(in millions except percentages) 2021 2020 2021 2020
Lease operating expenses (1)
$ 297 $ 203 46% $ 807 $ 579 39%
General & administrative expenses 28

27

4% 93 79 18%
Merger-related expenses 35 3 1,067% 39 3 1,200%
Restructuring charges — — —% 7 12 (42)%
Taxes, other than income taxes 35 15 133% 86 38 126%
Full cost pool amortization 132 65 103% 316 248 27%
Non-full cost pool DD&A 4 3 33% 11 12 (8)%
Impairments 6 361 (98)% 6 2,495 (100)%
Total operating costs $ 537 $ 677 (21)% $ 1,365 $ 3,466 (61)%


	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%

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		For the three months ended September 30,						Increase/	For the nine months ended September 30,						Increase/		For the three months ended March 31,						Increase/
Average unit costs per Mcfe:	Average unit costs per Mcfe:	2021			2020			(Decrease)	2021			2020			(Decrease)	Average unit costs per Mcfe:	2022			2021			(Decrease)
Lease operating expenses (1)	Lease operating expenses (1)	$	0.95		$	0.91		4%	$	0.94		$	0.93		1%	Lease operating expenses (1)	$	0.94		$	0.93		1%
General & administrative expenses	General & administrative expenses	$	0.09	(2)	$	0.12	(3)	(25)%	$	0.11	(2)	$	0.13	(3)	(15)%	General & administrative expenses	$	0.09	(2)	$	0.13	(3)	(31)%
Taxes, other than income taxes	Taxes, other than income taxes	$	0.11		$	0.07		57%	$	0.10		$	0.06		67%	Taxes, other than income taxes	$	0.13		$	0.09		44%
Full cost pool amortization	Full cost pool amortization	$	0.43		$	0.29		48%	$	0.37		$	0.40		(8)%	Full cost pool amortization	$	0.63		$	0.33		91%

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

(2)Excludes ~~$35 million and $39~~$25 million in merger-related expenses for the three ~~and nine~~ months ended ~~September 30, 2021, respectively, and $7~~March 31, 2022.

(3)Excludes $6 million in restructuring charges ~~for the nine months ended September 30, 2021.~~

~~(3)Excludes $3~~and $1 million in merger-related expenses ~~for the~~ three ~~and nine~~ months ended ~~September 30, 2020, respectively, and $12 million in restructuring charges for the nine months ended September 30, 2020.~~March 31, 2021.

Lease Operating Expenses

•Lease operating expenses per Mcfe increased $0.04 per Mcfe for the three months ended September 30, 2021, compared to the same period in 2020, primarily due to increased liquids production, which includes processing fees, and an increase in water handling costs.

•Lease operating expenses per Mcfe increased $0.01 per Mcfe for the ~~nine~~three months ended ~~September 30, 2021,~~March 31, 2022, compared to the same period in ~~2020, as a 37% increase in production volumes,~~2021, primarily due to increased costs associated with ~~the Montage Merger, was more than offset by a $228 million increase in lease operating expenses.~~processing fees, and fuel and electricity.

General and Administrative Expenses

•General and administrative expenses increased ~~$1 million and $14~~$4 million for the three ~~and nine~~ months ended ~~September 30, 2021, respectively,~~March 31, 2022 compared to the same ~~periods~~period in 2021, 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.

Merger-Related Expenses

•Beginning with the Montage Merger in 2020, aswe 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. The table below presents the ~~increase~~charges incurred for our merger-related activities for the three months ended March 31, 2022 and 2021:


	For the three months ended March 31,
	2022						2021
(in millions)	Indigo Merger		GEPH Merger		Total		Montage Merger
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		1
Other	—		2		2		—
Total merger-related expenses	$	1	$	24	$	25	$	1

We refer you to Note 2 of the consolidated financial statements included in ~~our share price and related mark-to-market impact on~~this Quarterly Report for additional details about the ~~value of our share-based awards, which are accounted for as liability awards.~~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 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. WeThese costs were recognized as restructuring ~~expense of $7 million~~charges for the ~~nine~~three months ended ~~months ended September 30,~~March 31, 2021 ~~related to cash severance expenses, including payroll taxes.~~

•~~In February 2020, employees~~and were ~~notified~~substantially completed by the end of ~~a workforce reduction plan as a result~~the first quarter of a strategic realignment of our organizational structure. 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. We recognized restructuring expense of $12 million for the nine months ended September 30, 2020 related to cash severance expenses, including payroll taxes.2021.

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

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. Taxes, other than income taxes, per Mcfe increased $0.04 for the three ~~and nine~~ months ended ~~September 30, 2021, respectively,~~March 31, 2022 compared to the same period in ~~2020,~~2021, primarily due to the impact of higher commodity pricing on our severance ~~taxes.~~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.

Full Cost Pool Amortization

•Our full cost pool amortization rate increased ~~$0.14~~$0.30 per Mcfe for the three months ended ~~September 30, 2021,~~March 31, 2022, as compared to the same period in ~~2020, primarily due to our recent Indigo Merger and the impact of the associated reserves acquired on our depletion calculation.~~

•~~The full cost pool amortization rate decreased $0.03 per Mcfe for the nine months ended September 30,~~ 2021, ~~as compared to the same period in 2020,~~ primarily as a result of ~~the impact~~our acquisitions of ~~$2,490 million in non-cash full cost ceiling test impairments recorded in 2020.~~

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•No impairment expense was recorded for the nine months ended September 30, 2021 in relation to the properties acquired from Montage in November 2020. These properties were recorded at fair value as of November 13, 2020, in accordance with ASC 820 Fair Value Measurement. In the fourth quarter of 2020, pursuant to SEC guidance, we determined that the fair value of the properties acquired at the closing of the Montage Merger clearly exceeded the related full-cost ceiling limitation beyond a reasonable doubt and received a waiver from the SEC to exclude the properties acquired in the Montage Merger from the ceiling test calculation. This waiver was granted for all reporting periods through and including the quarter ending September 30, 2021, as long as we can continue to demonstrate that the fair value of properties acquired clearly exceeds the full cost ceiling limitation beyond a reasonable doubt in each reporting period. As part of the waiver received from the SEC, we are required to disclose what the full cost ceiling test impairment amounts for all periods presented in each applicable quarterly and annual filing would have been if the waiver had not been granted. The fair value of the properties acquired in the Montage Merger was based on forward natural gas and oil ~~pricing existing at the date of the Montage Merger, and we affirmed that there has not been a material decline to the fair value of these acquired assets since the Montage Merger. The~~ properties ~~acquired~~ in the Montage Merger have an unamortized cost at September 30, 2021 of $1,183 million. Due to the improvement in commodity prices during 2021, we would not have recorded any impairment charge for the nine months ended September 30, 2021 had we included our Montage natural gas and oil properties.Haynesville.

•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 ~~test~~ 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 ~~$2,175~~$2,228 million and ~~$1,472~~$2,231 million at ~~September 30, 2021~~March 31, 2022 and at December 31, ~~2020,~~2021, respectively. The unevaluated costs excluded from amortization ~~increased primarily~~decreased slightly as ~~a result of the recent addition of our Haynesville natural gas properties which were acquired through the Indigo Merger, $693 million of which were classified as unevaluated. Additionally,~~ the impact of ~~$829~~$224 million of unevaluated capital invested during the period was ~~only partially~~more than offset by the evaluation of previously unevaluated properties totaling ~~$139~~$227 million.

~~Impairments~~

•We recognized $6 million for the three and nine months ended September 30, 2021, respectively, related to the non-cash impairment of certain non-core assets. During the three and nine months ended September 30, 2020, we recognized non-cash full cost ceiling test impairments of $361 million and $2,490 million, respectively, primarily due to decreased commodity pricing over the prior twelve months. Additionally, for the nine months ended September 30, 2020, we recognized a $5 million impairment related to other non-core assets.

Marketing


		For the three months ended September 30,						Increase/ (Decrease)		For the nine months ended September 30,										Increase/ (Decrease)			For the three months ended March 31,					Increase/ (Decrease)
(in millions except volumes and percentages)	(in millions except volumes and percentages)	2021			2020				2021				2020									(in millions except volumes and percentages)	2022		Increase/ (Decrease)
Marketing revenues	Marketing revenues	$	1,365		$	495			176%				$	3,344				$	1,432		134%								Marketing revenues	$	2,755			$	996	177%
Other operating revenues	Other operating revenues	1			—			100%		2					—					100%				Other operating revenues				—					1			(100)%
Marketing purchases	Marketing purchases	1,352			491			175%		3,307					1,429					131%				Marketing purchases	2,728					986				177%
Operating costs and expenses	Operating costs and expenses	6			6			—%		18					17					6%				Operating costs and expenses	6					5				20%

Operating income (loss)		$	8		$	(2)		500%		$	21				$	(14)				250%
Operating income																								Operating income	$	21				$	6			250%

Volumes marketed (Bcfe)	Volumes marketed (Bcfe)	346			294			18%		1,034					822					26%				Volumes marketed (Bcfe)	538					345				56%

Percent natural gas production marketed from affiliated E&P operations	Percent natural gas production marketed from affiliated E&P operations	98		%	88		%			96		%			87		%							Percent natural gas production marketed from affiliated E&P operations	91		%			93		%
Percent oil and NGL production marketed from affiliated E&P operations		82		%	83		%			82		%			81		%
Affiliated E&P oil and NGL production marketed																								Affiliated E&P oil and NGL production marketed	83		%			80		%

Operating Income

•Operating income for our Marketing segment increased ~~$10~~$15 million for the three months ended ~~September 30, 2021,~~March 31, 2022, compared to the same period in ~~2020,~~2021, primarily due to a $9$17 million increase in the marketing margin (discussed below).

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•~~Marketing~~ which was slightly offset by lower other operating ~~income increased $35 million for the nine months ended September 30, 2021, compared to the same period in 2020, primarily due to a $34 million increase in the marketing margin (discussed below).~~revenues and slightly higher operating costs.

•The margin generated from marketing activities was ~~$13~~$27 million and $4$10 million for the three months ended ~~September 30,~~March 31, 2022 and 2021, ~~and 2020, respectively, and $37 million and $3 million for the nine months ended September 30, 2021 and 2020,~~ respectively. The marketing margin increased in ~~2021,~~2022, compared to the same ~~periods~~period in ~~2020,~~2021, primarily due to increased volumes marketed and optimization of a ~~corresponding reduction in third-party purchases and sales used to optimize the~~larger transportation portfolio due to increased ~~affiliated~~ 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 ~~marketing~~ revenues due to changes in commodity prices and volumes marketed are largely offset by corresponding changes in purchase expenses. Efforts to optimize the cost of our transportation can result in greater expenses and therefore lower marketing margins.

Revenues

•Revenues from our marketing activities increased ~~$870~~$1,759 million for the three months ended ~~September 30, 2021~~March 31, 2022 compared to the same period in ~~2020,~~2021, primarily due to a ~~134%~~77% increase in the price received for volumes marketed and a 52193 Bcfe increase in the volumes marketed.

•Table of ContentsFor the nine months ended September 30, 2021, revenues from our marketing activities increased $1,912 million compared to the same period in 2020, primarily due to an 86% increase in the price received for volumes marketed and a 26% increase in volumes marketed.

~~Operating Costs and Expenses~~New Accounting Standards Implemented in this Report

•~~Operating costs and expenses for~~In March 2020, the marketing segment remained approximately the same for the third quarter and increased $1 million for the nine months ended September 30, 2021, respectively, compared to the same periods in 2020, primarilyFASB issued ASU 2020-04, Reference Rate Reform, as a ~~result~~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 ~~increase in our share price and related mark-to-market impact on the value of our share-based awards, which are accounted for as liability awards.~~

~~Consolidated~~

~~Interest Expense~~

For the three months ended September 30, Increase/(Decrease) For the nine months ended September 30, Increase/(Decrease)
(in millions except percentages) 2021 2020 2021 2020
Gross interest expense:
Senior notes $ 48 $ 39 23% $ 135 $ 112 21%
Credit arrangements 8 4 100% 19 11 73%
Amortization of debt costs 3 2 50% 9 7 29%
Total gross interest expense 59 45 31% 163 130 25%
Less: capitalization (25) (23) 9% (68) (67) 1%
Net interest expense $ 34 $ 22 55% $ 95 $ 63 51%

•Interest expense related to our senior notes increased for the three and nine months ended September 30, 2021, compared to the same period in 2020, as the interest savings from the repurchase of $107 million of our outstanding senior notes during the first half of 2020 was more than offset by the interest associated with the August 2020 public offering of $350 million aggregate principal amount of our 8.375% Senior Notes due 2028, the September 2021 assumption of Indigo Notes, which were exchanged for $700 million aggregate principal amount of our 5.375% Senior Notes due 2029, and the September 2021 public offering of $1,200 million aggregate principal amount of our 5.375% Senior Notes due 2030.

•Capitalized interest increased for the three and nine months ended September 30, 2021, both as compared to the same periods in 2020, primarily due to the incremental capitalized interest associated with the recently acquired Haynesville unevaluated properties.

•Capitalized interest decreased as a percentage of gross interest expense for the three and nine months ended September 30, 2021, compared to the same period in 2020, primarily related to a smaller percentage change in our unevaluated natural gas and oil properties balance as compared to the larger percentage increase in our gross interest expense over the same period.market-wide migration away

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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 and analyzes the changes in the results of operations between the three month periods ended March 31, 2022 and 2021. 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 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 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 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, we have completed three strategic acquisitions which have added scale to our operations and have laid the foundation for our future:

•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.

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.

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Recent Financial and Operating Results

Significant first quarter 2022 operating and financial results include:

Total Company

•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. Net loss decreased primarily as a $998 million 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 2022, compared to the same period in 2021, primarily as a $998 million improvement in operating income was partially offset by a $2 million loss on the early extinguishment of debt recorded in the first quarter of 2022 and a $10 million increase in interest expense from the first quarter of 2022 as compared to the same period in 2021.

•Operating income of $1,299 million increased compared to operating income of $301 million for the same period in 2021 on a consolidated basis. Operating income increased $1,871 million, as increased commodity pricing and natural gas production were only partially offset by increased operating costs of $873 million.

•Net cash provided by operating activities of $972 million increased 180% from $347 million for the same period in 2021 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 increase in operating expenses associated with our recently acquired Haynesville assets.

•Total capital investment of $544 million in the first quarter of 2022 increased 105% from $266 million for the same period in 2021 due to the addition of the ~~unevaluated~~acquired Haynesville ~~properties~~assets.

E&P

•E&P operating income of $1,278 million in the first quarter of 2022 increased $983 million, compared to the same period in 2021, primarily as an $1,369 million increase in E&P operating revenues resulting from a $2.26 per Mcfe increase in our realized weighted average price per Mcfe (excluding derivatives) and an 156 Bcfe increase in production volumes was ~~isolated~~only partially offset by a $386 million increase in E&P operating costs and expenses.

•Total net production of 425 Bcfe, which was comprised of 88% natural gas and 12% oil and NGLs, increased 58% from 269 Bcfe in the same period in 2021, primarily due to a 76% increase in our natural gas production which was driven by the Haynesville assets acquired from Indigo and GEPH in September 2021 and ~~is expected to increase the amount of capitalized interest until such time as it is evaluated.~~

~~Gain (Loss) on Derivatives~~

For the three months ended September 30, For the nine months ended September 30,
(in millions) 2021 2020 2021 2020
Loss on unsettled derivatives $ (2,015) $ (289) $ (2,957) $ (273)
Gain (loss) on settled derivatives (388) 97 (509) 310
Non-performance risk adjustment 4 — 5 1
Gain (loss) on derivatives $ (2,399) $ (192) $ (3,461) $ 38
December 2021, respectively.

•Excluding the effect of derivatives, our realized natural gas price of $4.50 per Mcfe increased 113%, our realized oil price of $86.30 per barrel increased 79% and our realized NGL price of $39.33 per barrel increased 72%, as compared to the same period in 2021. Excluding the effect of derivatives, our total weighted average realized price of $4.88 per Mcfe increased 86% from the same period in 2021.

•E&P segment invested $544 million in capital; drilling 33 wells, completing 37 wells and placing 32 wells to sales.

Outlook

Our primary focus in 2022 is to maintain our production profile and improve the safety and efficiency of our operations to optimize our ability to generate free cash flow (defined below) and further strengthen our balance sheet.

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

•Creating 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 free cash flow; upgrading the quality, depth and capital efficiency of our drilling inventory; and converting resources to proved reserves.

•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.

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•Capturing the Tangible Benefits of Scale. We strive to create a competitive advantage through executing and integrating strategic transactions that we believe will enhance enterprise returns 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.

We remain committed to achieving these objectives while maintaining our commitment to being environmentally conscious. 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 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

E&P


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

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

(1)Includes $25 million in merger-related expenses 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 million for the three months ended March 31, 2022, compared to the same period in 2021. A $1,369 million increase in E&P operating revenues resulting from an 86% increase in our realized weighted average price per Mcfe (excluding derivatives) and a 58% increase in production volumes was only partially offset by a $386 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,
(in millions except percentages)	Natural Gas			Oil			NGLs			Total
2021 sales revenues (1)	$	451		$	80		$	173		$	704
Changes associated with prices	897			49			114			1,060
Changes associated with production volumes	342			(19)			(15)			308
2022 sales revenues (2)	$	1,690		$	110		$	272		$	2,072
Increase from 2021	275		%	38		%	57		%	194		%

(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.

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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.

•E&P production volumes increased by 156 Bcfe for the three months ended March 31, 2022, compared to the same period in 2021, due to the recent acquisitions of producing natural gas and oil properties in Haynesville from Indigo in September 2021 and GEPH in December 2021. Production of 166 Bcfe from these properties more than offset a 10 Bcfe decrease in Appalachia production, as compared to the same period in 2021, due to a higher capital allocation to our recently acquired Haynesville assets.

•Oil and NGL production decreased 11% for the three months ended March 31, 2022, compared to the same period in 2021, primarily due to a higher capital allocation to our recently acquired Haynesville assets.

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)
	2022			2021
Natural Gas Price:
NYMEX Henry Hub Price ($/MMBtu) (1)	$	4.95		$	2.69		84%
Discount to NYMEX (2)	(0.45)			(0.58)			(22)%
Average realized gas price, excluding derivatives ($/Mcf)	$	4.50		$	2.11		113%
Gain on settled financial basis derivatives ($/Mcf)	0.01			0.19
Gain (loss) on settled commodity derivatives ($/Mcf)	(1.51)			0.03
Average realized gas price, including derivatives ($/Mcf)	$	3.00		$	2.33		29%

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

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

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

(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 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 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:


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

Total	582

Physical NYMEX Sales Arrangements – Natural Gas (1)
2022	621	$	(0.17)
2023	565	(0.10)
2024	391	(0.07)
2025	303	(0.04)
2026	138	—
2027	126	0.01
2028	125	0.01
2029	125	0.01
2030	47	—

Total	2,441

(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:


	Remaining 2022	Full Year 2023	Full Year 2024
Natural gas (Bcf)	982	938	279
Oil (MBbls)	3,413	2,114	603
Ethane (MBbls)	4,142	1,308	—
Propane (MBbls)	4,873	1,066	—
Normal Butane (MBbls)	1,388	329	—
Natural Gasoline (MBbls)	1,497	359	—
Total financial protection on future production (Bcfe)	1,074	969	283

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

~~Gain/Loss on Early Extinguishment~~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%

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~~For~~


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

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

(2)Excludes $25 million in merger-related expenses for the three ~~and nine~~ 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 per Mcfe for the three months ended March 31, 2022, compared to the same period in 2021, primarily due to increased costs associated with processing fees, and fuel and electricity.

General and Administrative Expenses

•General and administrative expenses increased $4 million for the three months ended March 31, 2022 compared to the same period in 2021, 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.

Merger-Related Expenses

•Beginning with the Montage Merger in 2020, 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. The table below presents the charges incurred for our merger-related activities for the three months ended March 31, 2022 and 2021:


	For the three months ended March 31,
	2022						2021
(in millions)	Indigo Merger		GEPH Merger		Total		Montage Merger
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		1
Other	—		2		2		—
Total merger-related expenses	$	1	$	24	$	25	$	1

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 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 charges for the three months ended March 31, 2021 ~~we recorded~~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.

Taxes, Other than Income Taxes

•On a ~~loss~~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. Taxes, other than income taxes, per Mcfe increased $0.04 for the three months ended March 31, 2022 compared to the same period in 2021, primarily due to the impact of higher commodity pricing on ~~early extinguishment~~our severance taxes in West Virginia, which are

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calculated as fixed percentage of ~~$59 million~~revenue net of allowable production expenses, and the impact of incremental severance and ad valorem taxes associated with our assets in Louisiana.

Full Cost Pool Amortization

•Our full cost pool amortization rate increased $0.30 per Mcfe for the three months ended March 31, 2022, as compared to the same period in 2021, primarily as a result of our ~~repurchase~~acquisitions of $791 million in aggregate principal amount of our outstanding senior notes for $844 million in the third quarter of 2021 and the write-off of $6 million in related unamortized debt discounts and debt issuance costs.

For the nine months ended September 30, 2020, we recorded a gain on early extinguishment of debt of $35 million as a result of our repurchase of $107 million in aggregate principal amount of our outstanding senior notes for $72 million in the first three quarters of 2020. See ~~Note 11~~ ~~to the consolidated financial statements of this Quarterly Report for more information on our long-term debt.~~

~~Income Taxes~~

For the three months ended September 30, For the nine months ended September 30,
(in millions except percentages) 2021 2020 2021 2020
Income tax expense $ — $ — $ — $ 406
Effective tax rate 0 % 0 % 0 % (16) %

~~In 2020, due to significant pricing declines and the material write-down of the carrying value of our~~ natural gas and oil properties in ~~addition~~Haynesville.

•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 ~~negative evidence, management concluded that it~~factors, including but not limited to the uncertainty of the amount of future reserve changes.

•Unevaluated costs excluded from amortization were $2,228 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 ~~likely~~ than ~~not that~~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 for the three months ended March 31, 2022, compared to the same period in 2021, primarily due to a ~~portion~~$17 million increase in the marketing margin (discussed below) which was slightly offset by lower other operating revenues and slightly higher operating costs.

•The margin generated from marketing activities was $27 million and $10 million for the three months ended March 31, 2022 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 ~~deferred tax assets will not be realized~~transportation can result in greater expenses and ~~recorded a valuation allowance. As of~~therefore lower marketing margins.

Revenues

•Revenues from our marketing activities increased $1,759 million for the third quarter of 2021, we still maintain a full valuation allowance. We also retained a valuation allowance of $87 million related to net operating losses in jurisdictions in which we no longer operate. Management will continue to assess available positive and negative evidence to estimate whether sufficient future taxable income will be generated to permit the use 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.

~~Due~~three months ended March 31, 2022 compared to the ~~issuance of common stock associated with the Indigo Merger, as discussed~~same period in ~~Note 2, we incurred~~2021, primarily due to a cumulative ownership change and as such, our net operating losses (“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 result77% increase in the ~~expiration~~price received for volumes marketed and a 193 Bcfe increase in the volumes marketed.

Table of NOLs or other tax attributes otherwise available, with a corresponding decrease in our valuation allowance. At September 30, 2021, we had approximately $4.5 billion of federal NOL carryovers, of which approximately $3 billion expire between 2035 and 2037 and $1.5 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 NOLs remain subject to a full valuation allowance. 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.Contents

New Accounting Standards Implemented in this Report

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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.

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

OVERVIEW

Background

•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.

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.

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Recent Financial and Operating Results

Significant first quarter 2022 operating and financial results include:

Total Company

•Total capital investment of $544 million in the first quarter of 2022 increased 105% from $266 million for the same period in 2021 due to the addition of the acquired Haynesville assets.

E&P

•E&P operating income of $1,278 million in the first quarter of 2022 increased $983 million, compared to the same period in 2021, primarily as an $1,369 million increase in E&P operating revenues resulting from a $2.26 per Mcfe increase in our realized weighted average price per Mcfe (excluding derivatives) and an 156 Bcfe increase in production volumes was only partially offset by a $386 million increase in E&P operating costs and expenses.

•E&P segment invested $544 million in capital; drilling 33 wells, completing 37 wells and placing 32 wells to sales.

Outlook

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

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COVID-19

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

E&P


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

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

(1)Includes $25 million in merger-related expenses 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)

Revenues

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


	Three months ended March 31,
(in millions except percentages)	Natural Gas			Oil			NGLs			Total
2021 sales revenues (1)	$	451		$	80		$	173		$	704
Changes associated with prices	897			49			114			1,060
Changes associated with production volumes	342			(19)			(15)			308
2022 sales revenues (2)	$	1,690		$	110		$	272		$	2,072
Increase from 2021	275		%	38		%	57		%	194		%

(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.

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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.

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)
	2022			2021
Natural Gas Price:
NYMEX Henry Hub Price ($/MMBtu) (1)	$	4.95		$	2.69		84%
Discount to NYMEX (2)	(0.45)			(0.58)			(22)%
Average realized gas price, excluding derivatives ($/Mcf)	$	4.50		$	2.11		113%
Gain on settled financial basis derivatives ($/Mcf)	0.01			0.19
Gain (loss) on settled commodity derivatives ($/Mcf)	(1.51)			0.03
Average realized gas price, including derivatives ($/Mcf)	$	3.00		$	2.33		29%

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

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

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

(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.

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

Total	582

Physical NYMEX Sales Arrangements – Natural Gas (1)
2022	621	$	(0.17)
2023	565	(0.10)
2024	391	(0.07)
2025	303	(0.04)
2026	138	—
2027	126	0.01
2028	125	0.01
2029	125	0.01
2030	47	—

Total	2,441

(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:


	Remaining 2022	Full Year 2023	Full Year 2024
Natural gas (Bcf)	982	938	279
Oil (MBbls)	3,413	2,114	603
Ethane (MBbls)	4,142	1,308	—
Propane (MBbls)	4,873	1,066	—
Normal Butane (MBbls)	1,388	329	—
Natural Gasoline (MBbls)	1,497	359	—
Total financial protection on future production (Bcfe)	1,074	969	283

We refer you to Note 8 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%

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

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

(2)Excludes $25 million in merger-related expenses 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

General and Administrative Expenses

Merger-Related Expenses


	For the three months ended March 31,
	2022						2021
(in millions)	Indigo Merger		GEPH Merger		Total		Montage Merger
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		1
Other	—		2		2		—
Total merger-related expenses	$	1	$	24	$	25	$	1

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 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 charges 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.

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. Taxes, other than income taxes, per Mcfe increased $0.04 for the three months ended March 31, 2022 compared to the same period in 2021, 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.

Full Cost Pool Amortization

•Our full cost pool amortization rate increased $0.30 per Mcfe for the three months ended March 31, 2022, as compared to the same period in 2021, primarily as a result of our acquisitions of natural gas and oil properties in Haynesville.

•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 $2,228 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 for the three months ended March 31, 2022, compared to the same period in 2021, 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.

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

Revenues

•Revenues from our marketing activities increased $1,759 million for the three months ended March 31, 2022 compared to the same period in 2021, primarily due to a 77% increase in the price received for volumes marketed and a 193 Bcfe increase in the volumes marketed.

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Operating Costs and Expenses

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

Consolidated

Interest Expense


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

•Interest expense related to our senior notes increased for the three months ended March 31, 2022, compared to the same period in 2021, as a result of the assumption of Indigo Notes, which were exchanged for $700 million aggregate principal amount of our 5.375% Senior Notes due 2029, the September 2021 public offering 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.

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

•Capitalized interest as a percentage of gross interest expense remained flat for the three months ended March 31, 2022, compared to the same period in 2021.

•We refer you to Note 11 to the consolidated financial statements included in this Quarterly Report for additional details about our debt and our financing activities.

Gain (Loss) on Derivatives


	For the three months ended March 31,

(in millions)	2022		2021
Loss on unsettled derivatives	$	(3,237)	$	(169)
Loss on settled derivatives	(695)		(22)
Non-performance risk adjustment	5		—
Loss on derivatives	$	(3,927)	$	(191)

We refer you to Note 8 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

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

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Income Taxes


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

In 2020, due to significant pricing declines 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 more likely than not that a portion of our deferred tax assets would not be realized and recorded a valuation allowance. As of the first quarter of 2022, we still maintain a full valuation allowance. We also retained a valuation allowance of $59 million related to net operating losses in jurisdictions in which we no longer operate. Management will continue to assess available positive and negative evidence to estimate whether sufficient future taxable income will be generated to permit the use 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 deferred tax assets until there is sufficient evidence to support the reversal of all or some portion of the allowance. However, if current commodity prices are sustained 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.

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”) 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. At March 31, 2022, 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 NOLs remain subject to a full valuation allowance. 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.

New Accounting Standards Implemented in this Report

Refer to Note 17 to the consolidated financial statements of this Quarterly Report for a discussion of new accounting standards that have been implemented.

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New Accounting Standards Not Yet Implemented in this Report

Refer to Note 17 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

On April 8, 2022 we entered into the 2022 credit facility which extends the maturity of our existing credit facility through April 2027. The 2022 credit facility has an aggregate maximum revolving credit amount and borrowing base of $3.5 billion, elected commitments of $2.0 billion and has provisions 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 rating agencies. We refer to the 2018 credit facility throughout this Quarterly Report as it was in effect as of the quarter ended March 31, 2022.

We depend primarily on funds generated from our operations, our 2018 credit facility, our cash and cash equivalents balance and capital markets as our primary sources of liquidity. In ~~September~~October 2021, the banks participating in our 2018 credit facility reaffirmed our elected borrowing base and aggregate commitments to be $2.0 billion. At ~~September 30, 2021,~~March 31, 2022, we had approximately ~~$1.2~~$1.7 billion of total available liquidity, which exceeds our currently modeled needs ~~and~~as we remain committed to our strategy of capital discipline. We

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 $3.5 billion maximum revolving credit amount and borrowing base of our 2022 credit facility and the elected $2.0 billion of aggregate 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 billion as of March 31, 2022, 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, 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 ~~this~~ free cash flow to pay down our debt.

~~On June 1, 2021, we entered into the Indigo Merger Agreement. Upon the close of the Indigo Merger, and pursuant~~ We refer you to the terms of the Indigo Merger Agreement, the outstanding equity interests in Indigo were cancelled and converted into (i) $373 million in cash consideration, and (ii) approximately $1,588 million in Southwestern common stock. Additionally, we assumed $700 million in aggregate principal amount of 5.375% Senior Notes due 2029 of Indigo (the “Indigo Notes”). We funded the $373 million cash portion of the September 2021 Indigo Merger consideration with the remaining proceeds from our recently issued 2030 Senior Notes (defined below) and borrowings on our credit facility. See Note 2 ~~and~~ ~~Note~~ 11 to the consolidated financial statements ofincluded in this Quarterly Report and the section below under “Credit Arrangements and Financing Activities” for ~~more information on the Indigo Merger~~additional discussion of our 2022 credit facility and ~~2030 Senior Notes, respectively.~~related covenant requirements.

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 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 ~~ensure~~support a certain level of cash flow to fund our operations. Although we are continually adding additional derivative positions for portions of our expected ~~2021,~~ 2022, 2023 and ~~2023~~2024 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. ~~See~~ ~~“Quantitative and Qualitative Disclosures about Market Risk”~~We again refer you to “Risk Factors” in Item ~~3 in Part I and~~ ~~Note 8~~ ~~in the consolidated financial statements included in this Quarterly Report for further details.~~1A of our 2021 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.

Our short-term cash flows are also dependent on the timely collection of receivables from our customers 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 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 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 September 2021, we completed a public offering of $1,200 million aggregate principal amount of our 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 $791 million principal amount of certain of our outstanding senior notes. The remaining proceeds were used to pay borrowings under our revolving credit facility and for general corporate purposes, including consideration for the Indigo Merger.

In April 2018, we entered into a ~~new~~ 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 ~~September~~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

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future ~~derivatives~~derivative position, the level of capital investment and operating costs. The 2018 credit facility is secured by substantially all of our assets ~~including most of~~and our ~~subsidiaries.~~subsidiaries’ assets (taken as a whole). The permitted lien provisions in ~~certain~~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 ~~September 30, 2021,~~March 31, 2022, we had ~~$665~~$174 million of borrowings ~~outstanding~~ on our ~~revolving~~2018 credit facility and ~~$159~~$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 ~~revolving~~2018 credit facility.

As of ~~September 30, 2021,~~March 31, 2022, we were in compliance with all of the applicable covenants contained in the credit agreement governing our ~~revolving~~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 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 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 billion as of March 31, 2022. The 2022 credit facility utilizes the 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 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 11 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 ~~revolving~~2022 credit facility could adversely impact our ability to borrow funds under the ~~revolving~~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 11 to the consolidated financial statements included in this Quarterly Report for additional discussion of our revolving credit facility.

~~Our exposure to~~In contemplation of the ~~anticipated transition from LIBOR in late~~GEPH Merger, on December 22, 2021, ~~is limited to~~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 3 months are as follows:

Debt Repurchases

•In January 2022, we repurchased the remaining outstanding principal balance of $201 million on our 2022 Senior Notes using our 2018 credit facility. ~~Upon announcement by the administrator of LIBOR identifying~~As a specific date for LIBOR cessation, the credit agreement governing the 2018 credit facility will be amended to reference an alternative rate as established by JP Morgan, as Administrative Agent, and Southwestern. The USD-LIBOR settings are expected to be published through June 2023 and we anticipate using a variation of this rate until the underlying agreements are extended beyond the LIBOR publication date.

~~Because~~result of the focused work on refinancing and repayment of our debt in recent years, ~~only $201 million, or 6%,~~coupled with the amendment and restatement of our ~~senior notes outstanding as of September 30, 2021 are~~credit facility on April 8, 2022, the only debt balance scheduled to become due prior to ~~2025.~~2025 is $15 million of our Term Loan principal.

~~At November 1, 2021,~~•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, we had a long-term debt issuer ~~credit rating~~ratings of Ba2 by Moody’s (rating and stable outlook affirmed on ~~April 28,~~November 29, 2021), ~~a long-term debt rating of BB~~BB+ by S&P (rating upgraded to BBBB+ with stable outlook on January 6, 2022) and ~~outlook upgraded to positive on September 1, 2021) and a long-term issuer default rating of~~ BB by Fitch Ratings (rating and stable outlook affirmed ~~and outlook upgraded to positive~~ on ~~September 1,~~November 29, 2021). Effective in July 2018, the interest rate for our 2025 Notes was 6.20%, reflecting a net downgrade in our bond ratings since their issuance. In April 2020, S&P downgraded our bond rating to BB-, which had the effect of increasing the interest rate on the 2025 Notes to 6.45% in July ~~2020. The~~2020, with the first coupon payment ~~to the 2025 Notes bondholders~~ at the higher interest rate ~~was~~in January 2021. On September 1, 2021, S&P upgraded ~~the Company’s~~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 ~~6.20%~~5.95%, beginning with coupon payments ~~paid~~ after January 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.~~respectively, as our 2025 senior notes are subject to ratings driven changes.

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Cash Flows


		For the nine months ended September 30,					For the three months ended March 31,
(in millions)	(in millions)	2021		2020		(in millions)	2022		2021
Net cash provided by operating activities	Net cash provided by operating activities	$	830	$	407	Net cash provided by operating activities	$	972	$	347
Net cash used in investing activities	Net cash used in investing activities	(1,062)		(698)		Net cash used in investing activities	(500)		(227)
Net cash provided by financing activities		231		381
Net cash used in financing activities						Net cash used in financing activities	(479)		(129)

Cash Flow from ~~Operating Activities~~Operations


		For the nine months ended September 30,					For the three months ended March 31,
(in millions)	(in millions)	2021		2020		(in millions)	2022		2021
Net cash provided by operating activities	Net cash provided by operating activities	$	830	$	407	Net cash provided by operating activities	$	972	$	347
Add back (subtract) changes in working capital	Add back (subtract) changes in working capital	146		(9)		Add back (subtract) changes in working capital	(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	$	976	$	398	Net cash provided by operating activities, net of changes in working capital	$	836	$	347

•Net cash provided by operating activities increased ~~104%~~180%, or ~~$423~~$625 million, for the ~~nine~~three months ended ~~September 30, 2021,~~March 31, 2022, compared to the same period in ~~2020,~~2021, primarily due to a ~~$1,408~~$1,060 million increase resulting from higher commodity prices, a ~~$313~~$308 million increase ~~associated with~~related to increased production, a $136 million increased impact of working capital and a ~~$23~~$17 million increase in our marketing ~~margin. These increases were~~margin and partially offset by ~~an $819~~a $673 million decrease in our settled derivatives, a ~~$322~~$188 million increase in operating costs and expenses ~~a $155 million decreased impact of working capital~~ and a ~~$32~~$10 million increase in interest expense.

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•Net cash ~~generated from~~provided by operating activities, net of changes in working capital, ~~provided 120% of~~exceeded our cash requirements for capital investments for the ~~nine~~three months ended ~~September 30, 2021, compared to providing 56% of our cash requirements for capital investments for the same period in 2020. We remain committed to our disciplined capital investment strategy~~March 31, 2022 and ~~to utilizing our excess cash generated from operating activities to reduce our debt.~~2021.

Cash Flow from Investing Activities

•Total E&P capital investments increased ~~$111~~$278 million for the ~~nine~~three months ended ~~September 30, 2021,~~March 31, 2022, compared to the same period in ~~2020,~~2021, due to an increase of $306 million related to our newly acquired Haynesville assets partially offset by a ~~$102~~$28 million ~~increase~~decrease in ~~direct E&P~~our Appalachia investment due to higher capital ~~investments and a $9 million increase in capitalized interest and internal costs, as compared~~allocation to ~~the same period in 2020.~~our recently acquired Haynesville assets.


		For the nine months ended September 30,					For the three months ended March 31,
(in millions)	(in millions)	2021		2020		(in millions)	2022		2021
Additions to properties and equipment	Additions to properties and equipment	$	747	$	700	Additions to properties and equipment	$	500	$	227
Adjustments for capital investments	Adjustments for capital investments					Adjustments for capital investments
Changes in capital accruals	Changes in capital accruals	63		1		Changes in capital accruals	43		38
Other (1)	Other (1)	6		4		Other (1)	1		1
Total capital investment		$	816	$	705
Total capital investing						Total capital investing	$	544	$	266

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

Capital ~~Investment~~Investing
For the three months ended September 30, Increase/(Decrease) For the nine months ended September 30, Increase/(Decrease)
(in millions except percentages) 2021 2020 2021 2020
E&P capital investment $ 291 $ 223 30% $ 816 $ 705 16%
Other capital investment (1)
— — —% — — —%
Total capital investment $ 291 $ 223 30% $ 816 $ 705 16%


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

(1)Other capital ~~investment~~investing was immaterial for the three ~~and nine~~ months ended ~~September 30, 2021~~March 31, 2022 and ~~2020.~~2021.

For the three months ended September 30, For the nine months ended September 30,
(in millions) 2021 2020 2021 2020
E&P Capital Investments by Type:
Exploratory and development drilling, including workovers $ 229 $ 163 $ 648 $ 550
Acquisition of properties 14 15 36 29
Water infrastructure 2 5 4 8
Other 6 3 13 12
Capitalized interest and expenses 40 37 115 106
Total E&P capital investments $ 291 $ 223 $ 816 $ 705

E&P Capital Investments by Area:
Appalachia $ 224 $ 215 $ 741 $ 685
Haynesville 59 — 59 —
Other E&P 8 8 16 20
Total E&P capital investments $ 291 $ 223 $ 816 $ 705

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


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

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

(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 September 30,		For the nine months ended September 30,			For the three months ended March 31,
		2021	2020	2021	2020		2022	2021
Gross Operated Well Count Summary:	Gross Operated Well Count Summary:					Gross Operated Well Count Summary:
Drilled	Drilled	17	16	63	84	Drilled	33	23
Completed	Completed	23	25	71	78	Completed	37	29
Wells to sales	Wells to sales	24	30	72	73	Wells to sales	32	17

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.

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Cash Flow from Financing Activities

•For the ~~nine~~three months ended ~~September 30, 2021,~~March 31, 2022, we ~~completed the previously mentioned $1,200~~fully redeemed our 4.10% Senior Notes for $201 million ~~debt offering which resulted in $1,183 million in net proceeds. We used $844 million to retire $791 million in~~and paid down additional aggregate principal balances on our ~~outstanding~~ senior notes ~~and used $95~~of $20 million ~~to retire the Indigo revolving credit facility as part of the Indigo Merger. In addition, we~~and paid down ~~$35~~$286 million on our ~~revolving~~2018 credit facility.

•In the first three ~~quarters~~months of ~~2020,~~2021, we ~~had net payments of $34~~paid down $133 million on our ~~revolving~~2018 credit facility. ~~In addition, we repurchased $107 million principal amount of our outstanding senior notes for $72 million and recognized a $35 million gain on the extinguishment of debt.~~

We refer you to Note 11 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 ~~$3,260~~$4,432 million at ~~September 30, 2021,~~March 31, 2022, a ~~$2,919~~$2,793 million decrease from December 31, ~~2020, as~~2021, and mostly attributable to a ~~$340 million increase in accounts receivable was more than offset by a $2,635~~$2,741 million reduction in the current mark-to-market value of our derivatives position related to improved forward pricing across all commodities, ~~along with~~a reduction in accounts receivable of $89 million, and an increase in our accounts payable of $206 million which was partially offset by the ~~reclassification~~full repayment of ~~long-term debt to short-term debt~~our 4.10% Senior Notes of $201 million ~~related~~and decreases to ~~our 2022 senior notes and a $386 million increase in~~ various payables of $48 million, as compared to December 31, ~~2020.~~2021. We believe that our existing cash and cash equivalents, our anticipated cash flows from operations ~~the remaining borrowing capacity on our credit facility~~ and our ~~existing cash and cash equivalents~~available credit facility will be sufficient to meet our working capital and operational spending requirements.

Off-Balance Sheet Arrangements

We may enter into off-balance sheet arrangements and transactions that can give rise to material off-balance sheet obligations. As of ~~September 30, 2021,~~March 31, 2022, our material off-balance sheet arrangements and transactions include operating service arrangements and ~~$159~~$147 million in letters of credit outstanding against our 2018 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 ~~a summary~~more information.

Table of ~~our operating leases.~~Contents

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 ~~2020~~2021 Annual Report.

Contingent Liabilities and Commitments

As of ~~September 30, 2021,~~March 31, 2022, we had commitments for demand and similar charges under firm transportation and gathering agreements to guarantee access capacity on natural gas and liquids pipelines and gathering systems totaling approximately ~~$9.8~~$10.2 billion, ~~$382~~$857 million 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 ~~$884~~$877 million. As of ~~September 30, 2021,~~March 31, 2022, 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	$	9,415	$	903	$	1,965	$	1,677	$	2,115	$	2,755	Infrastructure currently in service	$	9,301	$	1,066	$	1,943	$	1,729	$	2,085	$	2,478
Pending regulatory approval and/or construction (1)	Pending regulatory approval and/or construction (1)	382		2		18		27		57		278		Pending regulatory approval and/or construction (1)	857		3		124		161		247		322
Total transportation charges	Total transportation charges	$	9,797	$	905	$	1,983	$	1,704	$	2,172	$	3,033	Total transportation charges	$	10,158	$	1,069	$	2,067	$	1,890	$	2,332	$	2,800

(1)Based on the estimated in-service dates as of ~~September 30, 2021.~~March 31, 2022.

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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 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 ~~September 30, 2021,~~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), ~~we have~~the Company has recorded additional liabilities totaling ~~$81~~$35 million as of ~~September 30, 2021,~~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 ~~a period ranging from~~the next two ~~to seven~~ years.

Substantially all of our employees who were employed prior to January 1, 2021 are covered by defined benefit and postretirement benefit plans. As part of ongoing effort to reduce costs, we elected to freeze the pension plan effective January 1, 2021. Employees ~~that~~who were participants in the pension plan prior to January 1, 2021 ~~will continue~~continued to receive the interest component of the plan but ~~will~~ no longer ~~receive~~received the service component.

On September 13, 2021, the Compensation Committee of the Board of Directors approved terminating our ~~Pension Plan,~~pension plan, effective December 31, 2021. This decision, among other benefits, will provide plan participants quicker access to and greater flexibility in the management of participants’ respective benefits due under the plan. We have commenced the ~~Pension Plan~~pension plan termination process, but the specific date for the completion of the process is unknown at this time and will depend on certain legal and regulatory requirements or approvals. As part of the termination process, we expect to distribute lump sum payments to or purchase annuities for the benefit of plan participants, which is dependent on the participants’ elections. In addition, we expect to make a payment equal to the difference between the total benefits due under the plan and the total value of the assets available, which, as of September 30, 2021, was approximately $7 million.

For the ~~nine~~three months ended ~~September 30, 2021,~~March 31, 2022, we have ~~contributed $12 million~~not made contributions to the pension and postretirement benefit plans, and we do not expect to contribute additional funds to our pension plan during the remainder of ~~2021.~~2022. We recognized liabilities of ~~$31 million and $46~~$25 million as of ~~September 30, 2021~~March 31, 2022 and December 31, ~~2020, respectively,~~2021, as a result ~~of the underfunded status~~ of our pension and other postretirement benefit plans. See Note 14 to the consolidated financial statements included in this Quarterly Report for additional discussion about our pension and other postretirement benefits.

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

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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 12 to the consolidated financial statements included in Item 1 of Part I of this Quarterly Report.

Supplemental Guarantor Financial Information

As discussed in Note 11, in April 2018 the Company entered into the 2018 credit facility. Pursuant to requirements under the indentures governing our senior notes, each 100% owned subsidiary that became a guarantor of the 2018 credit facility also became 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 ~~that~~ 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.

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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 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, options, swaptions, basis swaps and ~~basis~~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.~~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. 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. At ~~September 30, 2021, no~~March 31, 2022, one purchaser accounted for ~~greater than 10%~~18% of our revenues. For the year ended December 31, ~~2020,~~2021, 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% of our revenues. No other individual purchasers accounted for more than 10% of our ~~revenues.~~revenues in either of these respective periods. A default on this account could have a material impact on the Company, but we do not believe that there is a material risk of a default. We believe that the loss of any one customer would not have an adverse effect on our ability to sell our natural gas, oil and NGL production.Company. See “Commodities Risk” below for discussion of credit risk associated with commodities trading.

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Interest Rate Risk

As of ~~September 30, 2021,~~March 31, 2022, we had approximately ~~$3,580~~$4,209 million ~~principal amount~~ of outstanding senior notes with a weighted average interest rate of ~~6.10% and $665~~5.74%, $549 million of borrowings under our ~~revolving~~Term Loan and $174 million of borrowings under our 2018 credit facility. ~~The 1% improvement to the Company’s weighted average fixed rate interest cost since the second quarter~~As of ~~2021 is a result of the refinancing activities previously described. At September 30, 2021,~~March 31, 2022, we had a long-term debt issuer ~~credit rating~~ratings of BB+ by S&P, Ba2 by Moody’s ~~a long-term debt rating of BB by S&P~~ and ~~a long-term issuer default rating of~~ BB by Fitch Ratings. In April 2020, S&P downgraded our bond rating to BB-, which had the effect of increasing the interest rate on our 2025 Notes to 6.45% following the July 23, 2020 interest payment date. The first coupon payment to the bondholders at the higher interest rate was paid in January 2021. On September 1, 2021 S&P upgraded 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~~decreased the interest rate on the 2025 ~~Notes~~notes to ~~6.20%~~5.95%, beginning with coupon payments paid after January 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.~~respectively, as our 2025 senior notes are subject to ratings driven changes.


		Expected Maturity Date																				Expected Maturity Date
($ in millions)		2022			2023			2024			2025			2026			Thereafter			Total
($ in millions except percentages)																							($ in millions except percentages)	2022			2023			2024			2025			2026			Thereafter			Total
Fixed rate payments (1)	Fixed rate payments (1)	$	201		$	—		$	—		$	689		$	—		$	2,690		$	3,580		Fixed rate payments (1)	$	—		$	—		$	—		$	389		$	—		$	3,820		$	4,209
Weighted average interest rate	Weighted average interest rate	4.10		%	—		%	—		%	6.45		%	—		%	6.15		%	6.10		%	Weighted average interest rate	—		%	—		%	—		%	5.95		%	—		%	5.72		%	5.74		%

Variable rate payments (1)	Variable rate payments (1)	$	—		$	—		$	665		$	—		$	—		$	—		$	665		Variable rate payments (1)	$	4		$	6		$	179		$	6		$	5		$	523		$	723
Weighted average interest rate	Weighted average interest rate	—		%	—		%	2.08		%	—		%	—		%	—		%	2.08		%	Weighted average interest rate	3.30		%	3.30		%	2.42		%	3.30		%	3.30		%	3.30		%	3.08		%

(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

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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 and Note 10 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.~~Act as of the end of the period covered by this Quarterly Report. Our disclosure controls and procedures are the controls and other procedures that we have designed to ensure that we record, process, accumulate and communicate information to our management, including our Chief Executive Officer and Chief Financial Officer, to allow timely decisions regarding required disclosures and submission within the time periods specified in the SEC’s rules and forms. All internal control systems, no matter how well designed, have inherent limitations. Therefore, even those determined to be effective can provide only a level of reasonable assurance with respect to financial statement preparation and presentation. Based on the evaluation, our management, including our Chief Executive Officer and Chief Financial Officer, concluded that our disclosure controls and procedures were effective as of ~~September 30, 2021~~March 31, 2022 at a reasonable assurance level.

Changes in Internal Control over Financial Reporting

~~During the quarter ended September 30,~~On December 31, 2021, the Company completed its acquisition of ~~Indigo Natural Resources.~~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 ~~Indigo.~~GEPH. Other than incorporating the ~~Indigo~~GEPH controls, there were no changes in our internal control over financial reporting (as defined in Rule 13a-15(f) and 15d-15(f) under the Exchange Act) that occurred during the quarter ended ~~September 30, 2021~~March 31, 2022 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 12 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 ~~2020~~2021 Annual ~~Report, except as set forth below.~~

~~Risks Factors Relating to SWN Following the Indigo Merger~~

~~SWN may be unable to successfully integrate Indigo’s business into its business or achieve the anticipated benefits of the Indigo Merger.~~

The success of the Indigo Merger will depend, in part, on SWN’s ability to realize the anticipated benefits and cost savings from combining SWN’s and Indigo’s businesses, and there can be no assurance that SWN will be able to successfully integrate or otherwise realize the anticipated benefits of the Indigo Merger. Difficulties in integrating SWN and Indigo may result in the combined company performing differently than expected, in operational challenges, or in the failure to realize anticipated expense-related efficiencies. Potential difficulties that may be encountered in the integration process include, among others:

•~~the inability to successfully integrate Indigo in a manner that permits the achievement of full revenue, expected cash flows and cost savings anticipated from the Indigo Merger;~~

•~~not realizing anticipated operating synergies;~~

•~~integrating personnel from Indigo and the loss of key employees;~~

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•~~potential unknown liabilities and unforeseen expenses or delays associated with and following the completion of the Indigo Merger;~~

•~~integrating relationships with customers, vendors and business partners;~~

•~~performance shortfalls as a result of the diversion of management’s attention caused by completing the Indigo Merger and integrating Indigo’s operations;~~

•~~the impact of SWN’s recent acquisition of Montage Resources Corporation and continuing integration related to the acquisition; and~~

•~~the disruption of, or the loss of momentum in, SWN’s ongoing business or inconsistencies in standards, controls, procedures and policies.~~

SWN’s ability to achieve the anticipated benefits of the Indigo Merger will depend in part upon whether it can integrate Indigo’s business into SWN’s existing business in an efficient and effective manner. SWN may not be able to accomplish this integration process successfully. The successful acquisition of producing properties, including those owned by Indigo, requires an assessment of several factors, including:

•~~recoverable reserves;~~

•~~future natural gas and oil prices and their appropriate differentials;~~

•~~availability and cost of transportation of production to markets;~~

•~~availability and cost of drilling equipment and of skilled personnel;~~

•~~development and operating costs including access to water and potential environmental and other liabilities; and~~

•~~regulatory, permitting and similar matters.~~

The accuracy of these assessments is inherently uncertain. In connection with these assessments, SWN has performed a review of the subject properties that it believes to be generally consistent with industry practices. The review was based on SWN’s analysis of historical production data, assumptions regarding capital expenditures and anticipated production declines. Data used in such review was furnished by Indigo or obtained from publicly available sources. SWN’s review may not reveal all existing or potential problems or permit SWN to fully assess the deficiencies and potential recoverable reserves for all of the acquired properties, and the reserves and production related to the assets and operations of Indigo may differ materially after such data is reviewed further by SWN. Inspections will not always be performed on every well, and environmental problems are not necessarily observable even when an inspection is undertaken. Even when problems are identified, Indigo may be unwilling or unable to provide effective contractual protection against all or a portion of the underlying deficiencies. SWN is often not entitled to contractual indemnification for environmental liabilities and acquire properties on an “as is” basis, and, as is the case with certain liabilities associated with the assets and operations of Indigo, SWN is entitled to remedies for only certain environmental liabilities. Additionally, SWN will not have the ability to control operations with respect to the portion of the assets and operations of Indigo in which Indigo holds only a non-operating interest. The integration process may be subject to delays or changed circumstances, and SWN can’t give any assurances that the assets and operations of Indigo will perform in accordance with SWN’s expectations or that SWN’s expectations with respect to integration or cost savings as a result of the Indigo Merger will materialize.

~~Sales of substantial amounts of the common stock in the open market by the holders of units of Indigo (“Indigo Holders”) could depress SWN’s stock price.~~

Shares of common stock that were issued to the former Indigo Holders in the Indigo Merger will become freely tradable once registered pursuant to the registration rights agreement entered into by SWN and certain Indigo Holders (the “Registration Rights Agreement”) or sold in compliance with Rule 144 promulgated under the Securities Act. Pursuant to the Registration Rights Agreement, all of the shares of common stock issued as stock consideration to any former Indigo Holder who was a party to the Registration Rights Agreement was registered for resale. Once registered, the common stock held by such former Indigo Holders are unrestricted and do not require further registration under the Securities Act, although such shares may be subject to the lockup restrictions set forth in the Registration Rights Agreement.

The former Indigo Holders may wish to dispose of some or all of their interests in SWN, and as a result may seek to sell their shares of common stock. These sales (or the perception that these sales may occur), coupled with the increase in the

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~~outstanding number of shares of common stock, may affect the market for, and the market price of, the common stock in an adverse manner.~~

If SWN’s shareholders, including the former Indigo Holders, sell substantial amounts of common stock in the public market, the market price of the common stock may decrease. These sales might also make it more difficult for SWN to raise capital by selling equity or equity-related securities at a time and price that it otherwise would deem appropriate.

~~The trading price and volume of the common stock may be volatile following the Indigo Merger.~~

The trading price and volume of the common stock may be volatile following completion of the Indigo Merger. The stock markets in general have experienced extreme volatility that has often been unrelated to the operating performance of particular companies. These broad market fluctuations may adversely affect the trading price of the common stock. As a result, you may suffer a loss on your investment.

~~The market for the common stock will depend on a number of conditions, most of which the combined company cannot control, including:~~

•~~general economic conditions within the U.S. and internationally, including changes in interest rates;~~

•~~general market conditions, including fluctuations in commodity prices;~~

•~~domestic and international economic, legal and regulatory factors unrelated to the combined company’s performance;~~

•~~changes in oil and natural gas prices; volatility in the financial markets or other global economic factors, including the impact of COVID-19;~~

•~~actual or anticipated fluctuations in the combined company’s quarterly and annual results and those of its competitors;~~

•~~quarterly variations in the rate of growth of the combined company’s financial indicators, such as revenue, EBITDA, net income and net income per share;~~

•~~the businesses, operations, results and prospects of the combined company;~~

•~~the operating and financial performance of the combined company;~~

•~~future mergers and strategic alliances;~~

•~~market conditions in the oil industry;~~

•~~changes in government regulation, taxes, legal proceedings or other developments;~~

•~~shortfalls in the combined company’s operating results from levels forecasted by securities analysts;~~

•~~investor sentiment toward the stock of oil and gas companies;~~

•~~changes in revenue or earnings estimates, or changes in recommendations by equity research analysts;~~

•failure of the combined company to achieve the perceived benefits of the Indigo Merger, including financial results and anticipated synergies, as rapidly as or to the extent anticipated by financial or industry analysts;

•~~speculation in the press or investment community;~~

•~~the failure of research analysts to cover the combined company’s common stock;~~

•~~sales of the common stock by the combined company, large shareholders or management, or the perception that such sales may occur;~~

•~~changes in accounting principles, policies, guidance, interpretations or standards;~~

•~~announcements concerning the combined company or its competitors;~~

•~~public reaction to the combined company’s press releases, other public announcements and filings with the SEC;~~

•~~strategic actions taken by competitors;~~

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•~~actions taken by the combined company shareholders;~~

•~~additions or departures of key management personnel;~~

•~~maintenance of acceptable credit ratings or credit quality; and~~

•~~the general state of the securities markets.~~

These and other factors may impair the market for the common stock and the ability of investors to sell shares at an attractive price. These factors also could cause the market price and demand for the common stock to fluctuate substantially, which may negatively affect the price and liquidity of the common stock. Many of these factors and conditions are beyond the control of the combined company or the combined company shareholders.

Securities class action litigation has often been instituted against companies following periods of volatility in the overall market and in the market price of a company’s securities. Such litigation, if instituted against the combined company, could result in very substantial costs, divert management’s attention and resources and harm the combined company’s business, operating results and financial condition.

~~Following the completion of the Indigo Merger, SWN may be exposed to additional commodity price risk as a result of the acquisition of Indigo’s upstream assets.~~

The prices for natural gas have historically been volatile, and SWN expects this volatility to continue in the future. The Indigo Merger may increase SWN’s exposure to these, or other, commodity price risks.

To mitigate its exposure to changes in commodity prices, Indigo hedged natural gas from time to time, primarily through the use of certain derivative commodity instruments. SWN now bears the economic impact of all of Indigo’s hedge portfolio assumed at the close of the Indigo Merger. Actual natural gas prices may differ from the Company’s expectations and, as a result, such hedges could have a negative impact on SWN’s business.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

Our sand mine location, which supported our former Fayetteville Shale business, was subject to regulation by the Federal Mine Safety and Health Administration under the Federal Mine Safety and Health Act of 1977. Information concerning mine safety violations or other regulatory matters required by Section 1503(a) of the Dodd-Frank Wall Street Reform and Consumer Protection Act and Item 104 of Regulation S-K (17 CFR 229.106) is included in Exhibit 95.1 to this Quarterly Report. On February 10, 2021, we sold our sand mine to a third party and, as a result, no longer own or operate any mines.Not applicable.

ITEM 5. OTHER INFORMATION

Not applicable.

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ITEM 6. EXHIBITS


(2.1)			Agreement and Plan of Merger, dated ~~as of~~ August 12, 2020, by and ~~between~~among Southwestern Energy Company and Montage Resources Corporation (Incorporated by reference to Exhibit 2.1 to the ~~Registrant’s~~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)			Amended and Restated Bylaws of Southwestern Energy Company, as amended on April 28, 2020 (Incorporated by reference to Exhibit 3.2 to the Registrant’s Quarterly Report on Form 10-Q filed April 30, 2020).

~~Table of Contents~~


(4.1)			~~Fifth~~Sixth Supplemental Indenture, dated as of ~~September 10, 2021~~January 4, 2022, among Southwestern Energy Company, the guarantors ~~named therein~~party thereto and ~~the~~The Bank of New York Mellon Trust, ~~Company,~~ N.A., as trustee ~~(incorporated~~(Incorporated by reference to Exhibit ~~4.6~~4.1 to ~~our Post-Effective Amendment No.1~~the Registrant’s Current Report on Form ~~S-4~~8-K filed on ~~September 16, 2021)~~January 5, 2022).
(4.2)			~~Seventh~~Eighth Supplemental Indenture, dated as of ~~September 10, 2021~~January 4, 2022, among Southwestern Energy Company, the guarantors ~~named therein~~party thereto and Regions Bank, as trustee ~~(incorporated~~(Incorporated by reference to Exhibit ~~4.14~~4.2 to ~~our Post-Effective Amendment No.1~~the Registrant’s Current Report on Form ~~S-4~~8-K filed on ~~September 16, 2021)~~January 5, 2022).
(4.3)			~~Sixth~~Eighth Supplemental Indenture, dated as of ~~August 30, 2021~~January 4, 2022, among Southwestern Energy Company, the guarantors ~~named therein~~party thereto and U.S. Bank National Association, as trustee ~~(incorporated~~(Incorporated by reference to Exhibit ~~4.4~~4.3 to ~~our~~the Registrant’s Current Report on Form 8-K filed on ~~August 30, 2021)~~January 5, 2022).
(4.4)			~~Seventh~~Fifth Supplemental Indenture, dated as of ~~September 10, 2021~~January 4, 2022, among Southwestern Energy Company, the guarantors ~~named therein and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.23 to our Post-Effective Amendment No.1 on Form S-4 filed on September 16, 2021).~~
~~(4.4)~~			~~Indenture dated August 30, 2021, between Southwestern Energy Company~~party thereto and Regions Bank, as trustee ~~(incorporated~~(Incorporated by reference to Exhibit ~~4.1~~4.4 to ~~our~~the Registrant’s Current Report on Form 8-K filed on ~~August 30, 2021)~~January 5, 2022).
~~(4.5)~~			First Supplemental Indenture, dated as of August 30, 2021 among Indigo Natural Resources LLC, the Security Guarantors party thereto and Wells Fargo Bank, National Association, as trustee (incorporated by reference to Exhibit 4.2 to our Current Report on Form 8-K filed on August 30, 2021).
~~(4.6)~~			Second Supplemental Indenture dated as of September 3, 2021 among Southwestern Energy Company, the Security Guarantors party thereto and Regions Bank, as trustee (incorporated by reference to Exhibit 4.1 to our Current Report on Form 8-K filed on September 3, 2021).
~~(4.7)~~			Third Supplemental Indenture, dated as of September 10, 2021 among Southwestern Energy Company, the guarantors named therein and Regions Bank, as trustee (incorporated by reference to Exhibit 4.31 to our Post-Effective Amendment No.1 on Form S-4 filed on September 16, 2021).
~~(4.8)~~			~~Form of 5.375% Senior Notes due 2029 (incorporated by reference to Exhibit 4.2 to our Current Report on Form 8-K filed with the SEC on September 3, 2021).~~
~~(4.9)~~			Exchange and Registration Rights Agreement, dated 3, 2021, among Southwestern Energy Company, the Guarantors thereto, J.P. Morgan Securities LLC and Credit Agricole Securities (USA) Inc. (incorporated by reference to Exhibit 4.3 to our Current Report on Form 8-K filed on September 3, 2021).
~~(4.10)~~			Indenture, dated as of February 2, 2021 among Indigo Natural Resources LLC, the guarantors named therein and Wells Fargo Bank, National Association, as trustee (incorporated by reference to Exhibit 4.34 to our Post-Effective Amendment No.1 on Form S-4 filed on September 16, 2021).
~~(4.11)~~			First Supplemental Indenture, dated as of August 26, 2021 among Indigo Natural Resources LLC, the guarantors named therein and Wells Fargo Bank, National Association, as trustee (incorporated by reference to Exhibit 4.35 to our Post-Effective Amendment No.1 on Form S-4 filed on September 16, 2021).
~~(4.12)~~			~~Form of 5.375% Notes due 2029 (incorporated by reference to Exhibit 4.36 to our Post-Effective Amendment No.1 on Form S-4 filed on September 16, 2021).~~
(10.1)			~~Amendment No.10 to~~Amended and Restated Credit Agreement, dated ~~June 9, 2021,~~April 8, 2022 among Southwestern Energy ~~Corporation, the lenders party thereto and JP Morgan~~Company, JPMorgan Chase Bank, N.A., as ~~administrative agent for~~Administrative Agent and the lenders from time to time party thereto (Incorporated by reference to Exhibit 10.1 to the ~~Registrant's~~Registrant’s Current Report on Form 8-K filed ~~June 9, 2021)~~on April 12, 2022).
(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.
(95.1)*			~~Mine Safety Disclosure.~~
(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:	~~November 4, 2021~~April 28, 2022	/s/ CARL F. GIESLER, JR.
		Carl F. Giesler, Jr. Executive Vice President and Chief Financial Officer

6459


	September 30, 2021		September 30, 2020
Natural gas (per MMBtu)	$	2.94	$	1.97
Oil (per Bbl)	$	57.69	$	43.40
NGLs (per Bbl)	$	23.26	$	9.26


	Nine months ended September 30,
(in millions except percentages)	Natural Gas			Oil			NGLs			Total
2020 sales revenues (1)	$	584		$	107		$	158		$	849
Changes associated with prices	851			145			412			1,408
Changes associated with production volumes	236			41			36			313
2021 sales revenues (2)	$	1,671		$	293		$	606		$	2,570
Increase from 2020	186		%	174		%	284		%	203		%