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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 ~~June 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 ~~July 27, 2021~~April 26, 2022
Common Stock, Par Value $0.01						~~677,020,351~~1,116,176,673

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SOUTHWESTERN ENERGY COMPANY

INDEX TO FORM 10-Q

FOR THE QUARTERLY PERIOD ENDED ~~JUNE 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		89
		Note 1. Basis of Presentation	89
		Note 2. Acquisition	89
		Note 3. Restructuring Charges	1113
		Note 4. Revenue Recognition	1114
		Note 5. Cash and Cash Equivalents	1315
		Note 6. Natural Gas and Oil Properties	1315
		Note 7. Earnings per Share	1416
		Note 8. Derivatives and Risk Management	1517
		Note 9. Reclassifications From Accumulated Other Comprehensive Income (Loss)	2223
		Note 10. Fair Value Measurements	23
		Note 11. Debt	2526
		Note 1 2 . Commitments and Contingencies	2731
		Note 1 3 . Income Taxes	2832
		Note 1 4 . Pension Plan and Other ~~Postretirement~~Post r etirement Benefits	2933
		Note 15. Long-Term Incentive Compensation	2934
		Note 1 6 . Segment Information	3337
		Note 1 7 . New Accounting Pronouncements	3538

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		3539
	Results of Operations		3742
	Liquidity and Capital Resources		4549
Item 3.	Quantitative and Qualitative Disclosures About Market Risk		5055
Item 4.	Controls and Procedures		5156

PART II – OTHER INFORMATION

Item 1.	Legal Proceedings		5157
Item 1A.	Risk Factors		5157
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds		5957
Item 3.	Defaults Upon Senior Securities		5957
Item 4.	Mine Safety Disclosures		5957
Item 5.	Other Information		5957
Item 6.	Exhibits		5958

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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 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.

~~Table of Contents~~

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;

•~~the consummation of or failure to consummate the Indigo Merger and the timing thereof;~~

•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 June 30,				For the six months ended June 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	$	433	$	164	$	897	$	412	Gas sales	$	1,692	$	464
Oil sales	Oil sales	106		19		187		71		Oil sales	111		81
NGL sales	NGL sales	179		40		352		90		NGL sales	272		173
Marketing	Marketing	332		187		684		426		Marketing	866		352
Other	Other	0		0		2		3		Other	2		2
		1,050		410		2,122		1,002			2,943		1,072
Operating Costs and Expenses:	Operating Costs and Expenses:									Operating Costs and Expenses:
Marketing purchases	Marketing purchases	333		201		689		449		Marketing purchases	862		356
Operating expenses	Operating expenses	259		182		509		375		Operating expenses	381		250
General and administrative expenses	General and administrative expenses	34		32		72		58		General and administrative expenses	44		38
Merger-related expenses	Merger-related expenses	3		0		4		0		Merger-related expenses	25		1
Restructuring charges	Restructuring charges	1		2		7		12		Restructuring charges	—		6

Depreciation, depletion and amortization	Depreciation, depletion and amortization	100		84		196		197		Depreciation, depletion and amortization	275		96
Impairments		0		655		0		2,134

Taxes, other than income taxes	Taxes, other than income taxes	27		10		51		23		Taxes, other than income taxes	57		24
		757		1,166		1,528		3,248			1,644		771
Operating Income (Loss)		293		(756)		594		(2,246)
Operating Income										Operating Income	1,299		301
Interest Expense:	Interest Expense:									Interest Expense:
Interest on debt	Interest on debt	48		40		98		80		Interest on debt	68		50
Other interest charges	Other interest charges	3		3		6		5		Other interest charges	3		3
Interest capitalized	Interest capitalized	(21)		(21)		(43)		(44)		Interest capitalized	(30)		(22)
		30		22		61		41			41		31

Gain (Loss) on Derivatives		(871)		(109)		(1,062)		230
Gain on Early Extinguishment of Debt		0		7		0		35
Other Income (Loss), Net		(1)		0		0		1
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		(609)		(880)		(529)		(2,021)
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	0		0		0		(2)		Current	4		—
Deferred	Deferred	0		0		0		408		Deferred	—		—
		0		0		0		406			4		—
Net Loss		$	(609)	$	(880)	$	(529)	$	(2,427)
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	$	(0.90)	$	(1.63)	$	(0.78)	$	(4.49)	Basic	$	(2.40)	$	0.12
Diluted	Diluted	$	(0.90)	$	(1.63)	$	(0.78)	$	(4.49)	Diluted	$	(2.40)	$	0.12

Weighted Average Common Shares Outstanding:	Weighted Average Common Shares Outstanding:									Weighted Average Common Shares Outstanding:
Basic	Basic	676,722,999		541,079,192		676,057,534		540,693,841		Basic	1,114,610,964		675,385,145
Diluted	Diluted	676,722,999		541,079,192		676,057,534		540,693,841		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 June 30, For the six months ended June 30,
(in millions) 2021 2020 2021 2020
Net loss $ (609) $ (880) $ (529) $ (2,427)
Change in value of pension and other postretirement liabilities:
Settlement adjustment (1)
3 0 3 0
Comprehensive loss $ (606) $ (880) $ (526) $ (2,427)


	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)~~Net of~~Settlement adjustment was less than $1 million ~~tax benefits for the three and six months ended June 30, 2021 and for the six months ended June 30, 2020. Tax benefits~~ for the three months ended ~~June 30, 2020 were immaterial.~~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)


		June 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	$	2	$	13	Cash and cash equivalents	$	21	$	28
Accounts receivable, net	Accounts receivable, net	408		368		Accounts receivable, net	1,071		1,160
Derivative assets	Derivative assets	132		241		Derivative assets	103		183
Other current assets	Other current assets	51		49		Other current assets	43		42
Total current assets	Total current assets	593		671		Total current assets	1,238		1,413
Natural gas and oil properties, using the full cost method, including $1,485 million as of June 30, 2021 and $1,472 million as of December 31, 2020 excluded from amortization		27,796		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	496		523		Other	513		509
Less: Accumulated depreciation, depletion and amortization	Less: Accumulated depreciation, depletion and amortization	(23,846)		(23,673)		Less: Accumulated depreciation, depletion and amortization	(24,482)		(24,202)
Total property and equipment, net	Total property and equipment, net	4,446		4,111		Total property and equipment, net	10,215		9,938
Operating lease assets	Operating lease assets	147		163		Operating lease assets	186		187
Long-term derivative assets						Long-term derivative assets	126		226
Deferred tax assets	Deferred tax assets	0		0		Deferred tax assets	—		—
Other long-term assets	Other long-term assets	208		215		Other long-term assets	82		84
Total long-term assets	Total long-term assets	355		378		Total long-term assets	394		497
TOTAL ASSETS	TOTAL ASSETS	$	5,394	$	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	$	207	$	0	Current portion of long-term debt	$	5	$	206
Accounts payable	Accounts payable	653		573		Accounts payable	1,488		1,282
Taxes payable	Taxes payable	62		74		Taxes payable	80		93
Interest payable	Interest payable	57		58		Interest payable	49		75

Derivative liabilities	Derivative liabilities	901		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	23		20		Other current liabilities	64		75
Total current liabilities	Total current liabilities	1,944		1,012		Total current liabilities	5,670		3,052
Long-term debt	Long-term debt	2,814		3,150		Long-term debt	4,895		5,201
Long-term operating lease liabilities	Long-term operating lease liabilities	104		117		Long-term operating lease liabilities	139		142
Long-term derivative liabilities	Long-term derivative liabilities	355		183		Long-term derivative liabilities	1,023		632
Pension and other postretirement liabilities	Pension and other postretirement liabilities	33		45		Pension and other postretirement liabilities	25		23
Other long-term liabilities	Other long-term liabilities	162		156		Other long-term liabilities	214		251
Total long-term liabilities	Total long-term liabilities	3,468		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; 1,250,000,000 shares authorized; issued 721,372,443 shares as of June 30, 2021 and 718,795,700 shares as of December 31, 2020		7		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	5,104		5,093		Additional paid-in capital	7,159		7,150
Accumulated deficit	Accumulated deficit	(4,892)		(4,363)		Accumulated deficit	(7,063)		(4,388)
Accumulated other comprehensive loss	Accumulated other comprehensive loss	(35)		(38)		Accumulated other comprehensive loss	(25)		(25)
Common stock in treasury, 44,353,224 shares as of June 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)	(18)		497		Total equity/(deficit)	(119)		2,547
TOTAL LIABILITIES AND EQUITY	TOTAL LIABILITIES AND EQUITY	$	5,394	$	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 six months ended June 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		$	(529)	$	(2,427)
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	196		197		Depreciation, depletion and amortization	275		96
Amortization of debt issuance costs	Amortization of debt issuance costs	4		4		Amortization of debt issuance costs	2		2
Impairments		0		2,134
Deferred income taxes		0		408
(Gain) loss on derivatives, unsettled		941		(17)

Loss on derivatives, unsettled						Loss on derivatives, unsettled	3,232		169
Stock-based compensation	Stock-based compensation	2		2		Stock-based compensation	1		—
Gain on early extinguishment of debt		0		(35)
Loss on early extinguishment of debt						Loss on early extinguishment of debt	2		—

Other	Other	1		0		Other	(1)		—
Change in assets and liabilities:
Change in assets and liabilities, excluding impact from acquisitions:						Change in assets and liabilities, excluding impact from acquisitions:
Accounts receivable	Accounts receivable	(40)		94		Accounts receivable	89		(33)
Accounts payable	Accounts payable	75		(121)		Accounts payable	126		33
Taxes payable	Taxes payable	(12)		(11)		Taxes payable	(13)		(8)
Interest payable	Interest payable	0		(1)		Interest payable	(16)		(2)
Inventories	Inventories	3		6		Inventories	4		9
Other assets and liabilities	Other assets and liabilities	(24)		21		Other assets and liabilities	(54)		1
Net cash provided by operating activities	Net cash provided by operating activities	617		254		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	(493)		(472)		Capital investments	(500)		(227)
Proceeds from sale of property and equipment	Proceeds from sale of property and equipment	2		2		Proceeds from sale of property and equipment	—		1
Other	Other	(1)		0		Other	—		(1)
Net cash used in investing activities	Net cash used in investing activities	(492)		(470)		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	0		(72)		Payments on long-term debt	(21)		—
Payments on revolving credit facility	Payments on revolving credit facility	(1,782)		(919)		Payments on revolving credit facility	(2,803)		(923)
Borrowings under revolving credit facility	Borrowings under revolving credit facility	1,650		1,221		Borrowings under revolving credit facility	2,517		790
Change in bank drafts outstanding	Change in bank drafts outstanding	0		(8)		Change in bank drafts outstanding	34		7

Debt issuance/amendment costs		(1)		0

Cash paid for tax withholding	Cash paid for tax withholding	(3)		(1)		Cash paid for tax withholding	(4)		(3)

Net cash provided by (used in) financing activities		(136)		221
Net cash used in financing activities						Net cash used in financing activities	(479)		(129)

Increase (decrease) in cash and cash equivalents		(11)		5
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	$	2	$	10	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)


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

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





Performance units vested	2,499,860	—		12		—		—		—	—		12
Tax withholding – stock compensation	(721,070)	—		(4)		—		—		—	—		(4)
Balance at March 31, 2022	1,160,451,456	$	12	$	7,159	$	(7,063)	$	(25)	44,353,224	$	(202)	$	(119)

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


	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 ~~NGL~~NGLs development, exploration ~~development~~ and production (“E&P”). The Company is also focused on creating and capturing additional value through its marketing business (“Marketing”)~~, which was previously referred to as “Midstream” when it included the operation of gathering systems.~~. 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 ~~oil~~as well as associated NGLs and ~~NGLs,~~oil, with ongoing operations focused on ~~the development of~~ unconventional natural gas and oil reservoirs located in Pennsylvania, West Virginia, Ohio and ~~Ohio.~~Louisiana. The Company’s operations in ~~northeast~~ Pennsylvania, West Virginia and Ohio, herein referred to as ~~“Northeast Appalachia,~~“Appalachia,” are primarily ~~focused on the unconventional natural gas reservoir known as the Marcellus Shale. Operations in West Virginia, Ohio and southwest Pennsylvania, herein referred to as “Southwest Appalachia,” are~~ focused on the Marcellus Shale, the Utica and the Upper Devonian unconventional natural gas and ~~oil~~liquids reservoirs. ~~Collectively, Southwestern refers~~The Company’s operations in Louisiana, herein referred to ~~its properties located in Pennsylvania, Ohio~~as “Haynesville,” are primarily focused on the Haynesville and ~~West Virginia as “Appalachia.”~~Bossier natural gas 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 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~~Indigo Merger (as defined below) ~~with Montage Resources Corporation (“Montage”) in November 2020.~~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 ~~will merge~~merged with and into Ikon, a subsidiary of Southwestern, ~~with Indigo surviving the merger~~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 ~~will be~~were cancelled and converted into the right to receive (i) ~~$400~~$373 million in cash consideration, ~~and (ii) 339,270,568 shares of Southwestern common stock, in each case,~~ subject to adjustment as provided in the Indigo Merger ~~Agreement. Additionally,~~Agreement, and (ii) 337,827,171 shares of Southwestern ~~will assume $700 million in aggregate principal amount of 5.375% Senior Notes due 2029 of Indigo (the “Indigo Notes”). The~~common stock. These shares of Southwestern common stock had an aggregate dollar value equal to ~~$1.6 billion,~~approximately $1,588 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 May 28, 2021. Following the~~ closing of the Indigo Merger, Southwestern’s existing shareholders and Indigo’s existing equity holders will own approximately 67% and 33%, respectively, of the outstanding shares of the combined company. The transaction is expected to close in the second half of 2021, subject to customary closing conditions, including the approval of Southwestern’s shareholders.

~~The Company has recorded approximately $2 million in transaction expenses for the three and six months ended June 30, 2021 related to the Indigo Merger.~~

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~~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~~$4.70 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.

~~In anticipation of the Montage Merger,~~September 1, 2021. Additionally, Southwestern assumed $700 million 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~~Indigo’s 5.375% Senior Notes due ~~2023~~2029 (the ~~“Montage~~“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 ~~related accrued interest~~the Indigo revolving line of credit was retired in ~~connection with the closing of the Montage Merger.~~September 2021. See Note 7 and Note 11 for additional information.

The ~~Montage~~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 ~~Montage stockholders~~Indigo equity holders as a result of the ~~Montage~~Indigo Merger:


(in millions, except share, per share amounts)	As of ~~November 13, 2020~~September 1, 2021
Shares of Southwestern common stock issued ~~in respect of outstanding Montage common stock~~	~~67,311,166~~337,827,171
~~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~~September 1, 2021	$	~~3.05~~4.70
	$	1,588
Cash consideration	373
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~~1,961

The ~~assets acquired and liabilities assumed were recorded at their preliminary estimated fair values at the date of the Montage Merger. The~~ following table sets forth the preliminary fair value of the assets acquired and liabilities assumed as of the acquisition date. ~~Although~~Certain data necessary to complete the purchase price allocation is ~~substantially complete as of the date of this filing, there may be further adjustments~~still under evaluation, including, but not limited to, the ~~Company’s~~valuation of natural gas and oil properties asand the ~~studies necessary to determine~~resolution of certain matters that the ~~fair value are finalized. These amounts~~Company is indemnified for under the Indigo Merger Agreement. The Company will ~~be finalized no later than one year from~~finalize the purchase price allocation during the twelve-month period following the acquisition ~~date. For~~date, during which time the ~~six months ended June 30, 2021 there were no changes to~~value of the ~~allocation presented in the 2020 Form 10-K.~~assets and liabilities may be revised as appropriate.

911

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(in millions)	As of ~~November 13, 2020~~September 1, 2021
Consideration:
~~Fair value of Southwestern’s stock issued on November 13, 2020~~Total consideration	$	~~213~~1,961
Fair Value of Assets Acquired:
Cash and cash equivalents	355
Accounts receivable	73192
Other current assets	12
Commodity derivative assets	112
Evaluated oil and gas properties	~~1,012~~2,724
Unevaluated oil and gas properties(1)	90693
Other property, plant and equipment	284
Other long-term assets	2627
Total assets acquired	~~1,244~~3,699
Fair Value of Liabilities Assumed:
Accounts payable (1)	~~145~~283
Other current liabilities	4955
Derivative liabilities	70501
Revolving credit facility	~~200~~95
Senior unsecured notes	~~522~~726
Asset retirement obligations	288
Other noncurrent liabilities	1770
Total liabilities assumed	~~1,031~~1,738
Net Assets Acquired and Liabilities Assumed	$	~~213~~1,961

~~For~~(1)Reflects $9 million purchase price adjustment during the ~~six~~three months ended ~~June 30, 2021, revenues~~March 31, 2022.

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

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

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

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

Prior to the Indigo Merger, in May 2021, Indigo closed on an agreement to divest its Cotton Valley natural gas and oil properties. Indigo retained certain contractual commitments related to volume commitments associated with natural gas gathering, for which Southwestern has assumed the obligation to pay the gathering provider for any unused portion of the volume commitment under the agreement through 2027, depending on the ~~Montage Merger totaled $250~~buyer’s actual use. As of March 31, 2022, up to approximately$34 million of these contractual commitments remain, and ~~$121~~the Company has recorded a $17 million ~~respectively.~~liability for the estimated future payments.

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

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Merger-Related Expenses

The following table ~~presents selected~~summarizes the merger-related expenses incurred:


	For the three months ended March 31,
	2022						2021
(in millions)	Indigo Merger		GEPH Merger		Total		Montage Merger
Transition services	$	—	$	18	$	18	$	—
Professional fees (bank, legal, consulting)	—		1		1		—

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

Pro Forma Information

The following table summarizes the unaudited pro forma condensed financial information for the three ~~and six~~ months ended ~~June 30, 2020~~March 31, 2021 as if the ~~Montage~~Indigo Merger and the GEPH Merger each had occurred on January 1, ~~2019:~~2020:

Pro forma results
(in millions, except per share amounts) For the three months ended
June 30, 2020 For the six months ended
June 30, 2020
Revenues $ 501 $ 1,226
Loss from continuing operations $ (925) $ (2,415)



(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 the operating results that would have occurred had the ~~Montage~~Indigo Merger and the GEPH Merger each been completed at January 1, ~~2019,~~2020, nor is it necessarily indicative of future operating results of the combined ~~entity.~~entities. The unaudited pro forma information gives effect to the ~~Montage~~Indigo Merger and the GEPH Merger and any related equity and debt issuances, along with the use of proceeds therefrom, as if they had occurred on January 1, ~~2019. The unaudited pro forma information for~~ 2020 and is a result of combining the statements of operations of Southwestern with the ~~pre-Montage Merger~~pre-merger results of ~~Montage from January 1, 2020~~Indigo and ~~included~~GEPH, including adjustments for revenues and direct expenses. The pro forma results exclude any cost savings anticipated as a result of the ~~Montage~~Indigo Merger and the ~~impact of any Montage Merger-related costs. The pro forma results~~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 ~~the~~any retirement of ~~the Montage~~assumed senior notes, ~~the Montage~~ credit ~~facility,~~facilities, all related accrued interest and the associated decrease in amortization of issuance costs related to ~~the Montage~~ notes retired and revolving ~~line~~lines of credit. ~~This decrease~~Interest expense was ~~partially offset by increases in interest on debt associated with~~also adjusted to include the ~~issuance~~impact of ~~$350~~the assumption and exchange of Indigo’s $700 million ~~in new 8.375%~~of 5.375% Senior Notes due ~~2028~~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 ~~Southwestern debt offering and borrowings under Southwestern’s credit facility used to pay off the Montage notes, Montage credit facility and related accrued interest.~~respective revolving lines of credit. Management believes the estimates and assumptions are reasonable, and the relative effects of the ~~Montage~~Indigo Merger and the GEPH Merger are properly reflected.

~~Montage Merger-Related Expenses~~

For the three and six months ended June 30, 2021, the Company incurred $1 million and $2 million, respectively, in Montage Merger-related expenses primarily related to one-time severance costs and the accelerated vesting of certain Montage share-based awards, based on the terms of the Montage Agreement and Plan of Merger, for former Montage employees that continued to assist with the transition into 2021.

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(3) RESTRUCTURING CHARGES

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


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

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

On February 24, 2021, the Company notified employees of a workforce reduction plan as part of an ongoing strategic effort to reposition its portfolio, optimize operational performance and improve margins. Affected employees were offered a severance package, which included a one-time payment depending on length of service and, if applicable, the current value of unvested long-term incentive awards that were forfeited. These costs were recognized as restructuring charges for the three ~~and six~~ months ended ~~June 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 three months ended June 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 six months ended June 30, 2021 and 2020:~~

For the three months ended June 30, For the six months ended June 30,
(in millions) 2021 2020 2021 2020
Severance (including payroll taxes) (1)
$ 1 $ 2 $ 7 $ 12

~~(1)~~Total restructuring charges were $1 million and $2 million for the Company’s E&P segment for the three months ended June 30, 2021 and 2020, respectively, and $7 million and $12 million for the Company’s E&P segment for the six months ended June 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 ~~June 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 June 30, 2021~~	$	0

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 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. Production imbalances are generally recorded as receivables and payables and not contract assets or contract liabilities as the imbalances are between the Company and other working interest owners, not the end customer.

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

~~Table of Contents~~

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 June 30, 2021
Gas sales $ 421 $ 0 $ 12 $ 433
Oil sales 105 0 1 106
NGL sales 178 0 1 179
Marketing 0 983 (651) 332
Total $ 704 $ 983 $ (637) $ 1,050
Three months ended June 30, 2020
Gas sales $ 155 $ 0 $ 9 $ 164
Oil sales 16 0 3 19
NGL sales 40 0 0 40
Marketing 0 389 (202) 187
Total $ 211 $ 389 $ (190) $ 410


(in millions)	(in millions)	E&P		Marketing		Intersegment Revenues		Total		(in millions)	E&P		Marketing		Intersegment Revenues		Total
Six months ended June 30, 2021
Three months ended March 31, 2022										Three months ended March 31, 2022
Gas sales	Gas sales	$	872	$	0	$	25	$	897	Gas sales	$	1,690	$	—	$	2	$	1,692
Oil sales	Oil sales	185		0		2		187		Oil sales	110		—		1		111
NGL sales	NGL sales	351		0		1		352		NGL sales	272		—		—		272
Marketing	Marketing	0		1,979		(1,295)		684		Marketing	—		2,755		(1,889)		866
Other (1)	Other (1)	1		1		0		2		Other (1)	2		—		—		2
Total	Total	$	1,409	$	1,980	$	(1,267)	$	2,122	Total	$	2,074	$	2,755	$	(1,886)	$	2,943

Six months ended June 30, 2020
Three months ended March 31, 2021										Three months ended March 31, 2021
Gas sales	Gas sales	$	394	$	0	$	18	$	412	Gas sales	$	451	$	—	$	13	$	464
Oil sales	Oil sales	68		0		3		71		Oil sales	80		—		1		81
NGL sales	NGL sales	90		0		0		90		NGL sales	173		—		—		173
Marketing	Marketing	0		937		(511)		426		Marketing	—		996		(644)		352
Other (2)	Other (2)	3		0		0		3		Other (2)	1		1		—		2
Total	Total	$	555	$	937	$	(490)	$	1,002	Total	$	705	$	997	$	(630)	$	1,072

(1)For the ~~six~~three months ended ~~June 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 six months ended June 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~~primarily Appalachia and ~~Ohio.~~Haynesville.

For the three months
ended June 30, For the six months
ended June 30,
(in millions) 2021 2020 2021 2020
Northeast Appalachia $ 230 $ 117 $ 493 $ 312
Southwest Appalachia 474 94 915 243
Other 0 0 1 0
Total $ 704 $ 211 $ 1,409 $ 555

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	For the three months ended March 31,
(in millions)	2022		2021
Appalachia	$	1,321	$	704
Haynesville	753		—
Other	—		1
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)	June 30, 2021		December 31, 2020		(in millions)	March 31, 2022		December 31, 2021
Receivables from contracts with customers	Receivables from contracts with customers	$	391	$	350	Receivables from contracts with customers	$	972	$	1,085
Other accounts receivable	Other accounts receivable	17		18		Other accounts receivable	99		75
Total accounts receivable	Total accounts receivable	$	408	$	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 six~~ months ended ~~June 30,~~March 31, 2022 and 2021, ~~and 2020.~~respectively. The Company has 0no 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 ~~June 30, 2021~~March 31, 2022 and December 31, ~~2020:~~2021:


(in millions)	(in millions)	June 30, 2021		December 31, 2020		(in millions)	March 31, 2022		December 31, 2021
Cash	Cash	$	2	$	13	Cash	$	21	$	28
Marketable securities (1)	Marketable securities (1)	0		0		Marketable securities (1)	—		—

Total	Total	$	2	$	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 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 0no hedge positions that were designated for hedge accounting as of ~~June 30, 2021.~~March 31, 2022. Prices used to calculate the ceiling value of reserves were as follows:
June 30, 2021 June 30, 2020
Natural gas (per MMBtu)
$ 2.43 $ 2.07
Oil (per Bbl)
$ 49.78 $ 47.17
NGLs (per Bbl)
$ 17.06 $ 8.87


	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 ~~June 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.~~

~~NaN impairment expense was recorded for the six months ended June 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 of November 13, 2020, in accordance with Accounting Standards Codification (“ASC”) Topic 820 – Fair Value Measurement. In the fourth quarter of 2020, pursuant 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 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

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The Company did not record an impairment expense related to ~~the fair value of these acquired assets since the Montage Merger. The properties acquired in the Montage Merger have an unamortized~~its other non-full cost at June 30, 2021 of $1,130 million. Due to the improvement in commodity prices in the second quarter of 2021, 0 impairment charge would have been recorded for the three and six months ended June 30, 2021 had the recently 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 and $650 million at June 30, 2020, resulting in a non-cash ceiling test impairment for the first and second 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.

~~In August 2020,~~On December 31, 2021, the Company ~~completed an underwritten public offering of 63,250,000~~issued 99,337,748 shares of its common stock in conjunction with the GEPH Merger. These shares of Southwestern common stock had an ~~offering~~aggregate dollar value equal to approximately $463 million, based on the closing price toof $4.66 per share of Southwestern common stock on the ~~public of $2.50 per share. Net proceeds after deducting underwriting discounts and offering expenses were approximately $152 million.~~NYSE on December 31, 2021. See Note 2 for additional details ~~regarding~~on the ~~Company’s use~~GEPH Merger.

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

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


		For the three months ended June 30,				For the six months ended June 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		$	(609)	$	(880)	$	(529)	$	(2,427)
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	676,722,999		541,079,192		676,057,534		540,693,841		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	0		0		0		0		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	0		0		0		0		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	0		0		0		0		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	0		0		0		0		Effect of issuance of non-vested performance units	—		2,807,195
Weighted average and potential dilutive outstanding	Weighted average and potential dilutive outstanding	676,722,999		541,079,192		676,057,534		540,693,841		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	$	(0.90)	$	(1.63)	$	(0.78)	$	(4.49)	Basic	$	(2.40)	$	0.12
Diluted	Diluted	$	(0.90)	$	(1.63)	$	(0.78)	$	(4.49)	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 six~~ months ended ~~June 30,~~March 31, 2022 and 2021, ~~and 2020,~~ as they would have had an antidilutive effect:


		For the three months ended June 30,		For the six months ended June 30,			For the three months ended March 31,
		2021	2020	2021	2020		2022	2021
Unexercised stock options	Unexercised stock options	3,733,971	4,548,735	3,764,362	4,566,648	Unexercised stock options	2,948,488	3,795,091
Unvested share-based payment		721,633	902,615	805,791	1,024,867
Stock-based compensation						Stock-based compensation	1,436,920	—
Restricted stock units	Restricted stock units	2,917,427	2,631,727	4,059,473	2,983,352	Restricted stock units	2,528,005	3,987,291
Performance units	Performance units	2,832,043	2,712,207	2,934,615	2,096,041	Performance units	1,917,579	—
Total	Total	10,205,074	10,795,284	11,564,241	10,670,908	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 ~~June 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.

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.

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 ~~June 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 June 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		103	$	2.80	$	—	$	—	$	—	$	—	$	(87)
Two-way costless collars		140	—		—		2.62		2.97		—		(101)
Three-way costless collars		153	—		2.18		2.51		2.86		—		(127)
Total		396											$	(315)
2022	2022														2022
Fixed price swaps	Fixed price swaps	268	$	2.72	$	—	$	—	$	—	$	—	$	(119)	Fixed price swaps	627	$	3.04	$	—	$	—	$	—	$	—	$	(1,672)
Two-way costless collars	Two-way costless collars	125	—		—		2.65		3.04		—		(46)		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		—		(127)		Three-way costless collars	277	—		2.03		2.48		2.88		—		(784)
Total	Total	726											$	(292)	Total	982											$	(2,672)
2023	2023														2023
Fixed price swaps	Fixed price swaps	23	$	2.70	$	—	$	—	$	—	$	—	$	(3)	Fixed price swaps	504	$	3.08	$	—	$	—	$	—	$	—	$	(675)
Two-way costless collars	Two-way costless collars	34	—		—		2.50		2.72		—		(3)		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		—		(34)		Three-way costless collars	215	—		2.09		2.54		3.00		—		(355)
Total	Total	272											$	(40)	Total	938											$	(1,247)
2024	2024														2024
Fixed price swaps															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	$	—	$	(1)	Three-way costless collars	11	—		2.25		2.80		3.54		—		(12)
Total															Total	279											$	(205)

Basis Swaps	Basis Swaps														Basis Swaps
2021		166	$	—	$	—	$	—	$	—	$	(0.47)	$	62
2022	2022	261	—		—		—		—		(0.40)		40		2022	277	$	—	$	—	$	—	$	—	$	(0.53)	$	72
2023	2023	163	—		—		—		—		(0.53)		7		2023	250	—		—		—		—		(0.47)		20
2024	2024	40	—		—		—		—		(0.70)		2		2024	46	—		—		—		—		(0.71)		9
2025	2025	9	—		—		—		—		(0.64)		1		2025	9	—		—		—		—		(0.64)		3

Total	Total	639											$	112	Total	582											$	104

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		Volume (MBbls)		Weighted Average Strike Price per Bbl											Fair Value at June 30, 2021 (in millions)			Volume (MBbls)		Weighted Average Strike Price per Bbl								Fair Value at March 31, 2022 (in millions)
			Swaps			Sold Puts			Purchased Puts			Sold Calls					Swaps			Sold Puts		Purchased Puts		Sold Calls
Oil	Oil																		Oil
2021
Fixed price swaps		1,739		$	50.10		$	—		$	—		$	—	$	(37)
Two-way costless collars		92		—			—			37.50			45.50		(2)
Three-way costless collars		1,152		—			39.22			49.05			54.35		(20)
Total		2,983													$	(59)
2022	2022																2022
Fixed price swaps	Fixed price swaps	3,203		$	53.54		$	—		$	—		$	—	$	(39)	Fixed price swaps	2,376		$	53.32	$	—	$	—	$	—	$	(94)

Three-way costless collars	Three-way costless collars	1,380		—			39.89			50.23			57.05		(15)		Three-way costless collars	1,037		—		39.83		50.17		57.01		(38)
Total	Total	4,583													$	(54)	Total	3,413										$	(132)
2023	2023																2023
Fixed price swaps	Fixed price swaps	846		$	55.98		$	—		$	—		$	—	$	(4)	Fixed price swaps	846		$	55.98	$	—	$	—	$	—	$	(23)
Three-way costless collars	Three-way costless collars	1,268		—			33.97			45.51			56.12		(12)		Three-way costless collars	1,268		—		33.97		45.51		56.12		(36)
Total	Total	2,114													$	(16)	Total	2,114										$	(59)
2024	2024																2024
Fixed price swaps	Fixed price swaps	54		$	53.15		$	—		$	—		$	—	$	0	Fixed price swaps	603		$	68.68	$	—	$	—	$	—	$	(5)

Ethane	Ethane																Ethane
2021
Fixed price swaps		3,284		$	7.64		$	—		$	—		$	—	$	(17)
Two-way costless collars		294		—			—			7.14			10.40		(1)
Total		3,578													$	(18)
2022	2022																2022
Fixed price swaps	Fixed price swaps	2,362		$	8.97		$	—		$	—		$	—	$	(6)	Fixed price swaps	4,142		$	11.27	$	—	$	—	$	—	$	(26)
Two-way costless collars		135		—			—			7.56			9.66		0
Total		2,497													$	(6)

2023																	2023
Fixed price swaps																	Fixed price swaps	1,308		$	11.91	$	—	$	—	$	—	$	(3)

Propane	Propane																Propane
2021
Fixed price swaps		4,261		$	24.00		$	—		$	—		$	—	$	(84)

2022	2022																2022
Fixed price swaps	Fixed price swaps	4,092		$	25.90		$	—		$	—		$	—	$	(42)	Fixed price swaps	4,643		$	31.09	$	—	$	—	$	—	$	(118)
Three-way costless collars	Three-way costless collars	305		—			16.80			21.00			31.92		(2)		Three-way costless collars	230		—		16.80		21.00		31.92		(6)
Total	Total	4,397													$	(44)	Total	4,873										$	(124)
2023																	2023
Fixed price swaps																	Fixed price swaps	1,066		$	37.15	$	—	$	—	$	—	$	(8)

Normal Butane	Normal Butane																Normal Butane
2021
2022																	2022
Fixed price swaps	Fixed price swaps	1,245		$	29.04		$	—		$	—		$	—	$	(27)	Fixed price swaps	1,388		$	36.22	$	—	$	—	$	—	$	(43)
2022
2023																	2023
Fixed price swaps	Fixed price swaps	1,295		$	29.16		$	—		$	—		$	—	$	(16)	Fixed price swaps	329		$	40.64	$	—	$	—	$	—	$	(3)

Natural Gasoline	Natural Gasoline																Natural Gasoline
2021
Fixed price swaps		1,281		$	43.58		$	—		$	—		$	—	$	(29)
2022	2022																2022
Fixed price swaps	Fixed price swaps	1,201		$	45.76		$	—		$	—		$	—	$	(17)	Fixed price swaps	1,497		$	55.78	$	—	$	—	$	—	$	(57)
2023																	2023
Fixed price swaps																	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)

1719

Table of Contents

Other Derivative Contracts
Volume
(Bcf)
Weighted Average Strike Price per MMBtu
Fair Value at
June 30, 2021
(in millions)
Call Options – Natural Gas (Net)
2021 38 $ 3.19 $ (21)
2022 77 3.00 (34)
2023 46 2.94 (14)
2024 9 3.00 (4)
Total 170 $ (73)
Put Options – Natural Gas
2021 9 $ 2.00 $ 0
2022 5 2.00 0
Total 14 $ 0
Volume
(MBbls)
Weighted Average Strike Price per Bbl
Fair Value at
June 30, 2021
(in millions)
Call Options – Oil
2021 114 $ 60.00 $ (1)
Volume
(Bcf)
Weighted Average Strike Price per MMBtu
Fair Value at
June 30, 2021
(in millions)
Swaptions – Natural Gas
2021 (1)
18 $ 3.00 $ (5)

~~(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
June 30, 2021
(in millions)
Swaps Basis Differential
Storage (1)

2021
Purchased fixed price swaps 1 $ 2.45 $ 0 $ 1
Purchased basis swaps 1 0 (0.88) 0
Fixed price swaps 1 2.59 0 (1)
Basis swaps 0 0 (0.89) 0
Total 3 $ 0
2022
Purchased fixed price swaps 0 $ 2.14 $ 0 $ 0
Fixed price swaps 2 2.82 0 (1)
Basis swaps 1 0 (0.57) 0
Total 3 $ (1)


	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
June 30, 2021
(in millions)
2021 2 $ 2.44 $ 3

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

At ~~June 30, 2021,~~March 31, 2022, the net fair value of the Company’s financial instruments ~~related to commodities~~ was a ~~$983~~$4,734 million liability, ~~and~~which included a net reduction of the liability of $2$8 million related to non-performance risk. See Note 10 for additional details regarding the Company’s fair value measurements of its derivatives position.

As of ~~June 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

~~Table of Contents~~

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 ~~June 30, 2021~~March 31, 2022 and December 31, ~~2020:~~2021:


Derivative Assets	Derivative Assets						Derivative Assets
			Fair Value						Fair Value
(in millions)	(in millions)	Balance Sheet Classification	June 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	$	3	$	1

Fixed price swaps – natural gas	Fixed price swaps – natural gas	Derivative assets	1		37		Fixed price swaps – natural gas	Derivative assets	$	—	$	79
Fixed price swaps – oil		Derivative assets	0		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	16		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	18		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	83		60		Basis swaps – natural gas	Derivative assets	82		77
Call options – natural gas		Derivative assets	9		4

Purchased fixed price swaps – natural gas storage	Purchased fixed price swaps – natural gas storage	Derivative assets	1		0		Purchased fixed price swaps – natural gas storage	Derivative assets	1		—

Fixed price swaps – natural gas	Fixed price swaps – natural gas	Other long-term assets	0		7		Fixed price swaps – natural gas	Other long-term assets	—		64
Fixed price swaps – oil		Other long-term assets	0		2

Two-way costless collars – natural gas	Two-way costless collars – natural gas	Other long-term assets	12		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	68		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	5		15		Three-way costless collars – oil	Other long-term assets	1		3
Basis swaps – natural gas	Basis swaps – natural gas	Other long-term assets	56		15		Basis swaps – natural gas	Other long-term assets	70		22

Interest rate swaps	Interest rate swaps	Other long-term assets	1		0		Interest rate swaps	Other long-term assets	—		2
Total derivative assets	Total derivative assets		$	274	$	387	Total derivative assets		$	230	$	411

1920

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Derivative Liabilities	Derivative Liabilities						Derivative Liabilities
			Fair Value						Fair Value
(in millions)	(in millions)	Balance Sheet Classification	June 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	$	158	$	7
Fixed price swaps – oil		Derivative liabilities	58		12
Fixed price swaps – ethane		Derivative liabilities	21		10
Fixed price swaps – propane		Derivative liabilities	110		36
Fixed price swaps – normal butane		Derivative liabilities	36		8
Fixed price swaps – natural gasoline		Derivative liabilities	39		13
Two-way costless collars – natural gas		Derivative liabilities	151		43
Two-way costless collars – oil		Derivative liabilities	2		1
Two-way costless collars – ethane		Derivative liabilities	1		0
Three-way costless collars – natural gas		Derivative liabilities	217		82
Three-way costless collars – oil		Derivative liabilities	29		15
Three-way costless collars – propane		Derivative liabilities	1		0
Basis swaps – natural gas		Derivative liabilities	19		3
Call options – natural gas		Derivative liabilities	51		12
Call options – oil		Derivative liabilities	1		0
Put options – natural gas		Derivative liabilities	0		1
Swaptions – natural gas		Derivative liabilities	5		2

Fixed price swaps – natural gas storage	Fixed price swaps – natural gas storage	Derivative liabilities	2		0		Fixed price swaps – natural gas storage	Derivative liabilities	$	—	$	1
Fixed price swaps – natural gas	Fixed price swaps – natural gas	Long-term derivative liabilities	52		3		Fixed price swaps – natural gas	Derivative liabilities	1,999		565
Fixed price swaps – oil	Fixed price swaps – oil	Long-term derivative liabilities	22		2		Fixed price swaps – oil	Derivative liabilities	101		60
Fixed price swaps – ethane	Fixed price swaps – ethane	Long-term derivative liabilities	2		0		Fixed price swaps – ethane	Derivative liabilities	28		10
Fixed price swaps – propane	Fixed price swaps – propane	Long-term derivative liabilities	16		2		Fixed price swaps – propane	Derivative liabilities	122		78
Fixed price swaps – normal butane	Fixed price swaps – normal butane	Long-term derivative liabilities	7		1		Fixed price swaps – normal butane	Derivative liabilities	44		27
Fixed price swaps – natural gasoline	Fixed price swaps – natural gasoline	Long-term derivative liabilities	7		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	27		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	158		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		0		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	8		7		Basis swap – natural gas	Long-term derivative liabilities	5		22
Call options – natural gas	Call options – natural gas	Long-term derivative liabilities	31		28		Call options – natural gas	Long-term derivative liabilities	57		42

Total derivative liabilities	Total derivative liabilities		$	1,256	$	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)

2021

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 six~~ months ended ~~June 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 June 30, For the six months ended June 30,
Derivative Instrument 2021 2020 2021 2020
(in millions)
Purchased fixed price swaps – natural gas Gain (Loss) on Derivatives $ 2 $ 1 $ 2 $ 0
Fixed price swaps – natural gas Gain (Loss) on Derivatives (221) (39) (243) 64
Fixed price swaps – oil Gain (Loss) on Derivatives (41) (39) (81) 74
Fixed price swaps – ethane Gain (Loss) on Derivatives (11) (22) (13) (10)
Fixed price swaps – propane Gain (Loss) on Derivatives (43) (44) (88) (8)
Fixed price swaps – normal butane Gain (Loss) on Derivatives (19) 0 (34) 0
Fixed price swaps – natural gasoline Gain (Loss) on Derivatives (11) 0 (31) 0
Two-way costless collars – natural gas Gain (Loss) on Derivatives (148) (7) (160) (11)
Two-way costless collars – oil Gain (Loss) on Derivatives 0 (10) (1) 9
Two-way costless collars – ethane Gain (Loss) on Derivatives (1) 0 (1) 0
Two-way costless collars – propane Gain (Loss) on Derivatives 0 (3) 0 (1)
Three-way costless collars – natural gas Gain (Loss) on Derivatives (249) (45) (249) (96)
Three-way costless collars – oil Gain (Loss) on Derivatives (29) (6) (47) 19
Three-way costless collars – propane Gain (Loss) on Derivatives (1) 0 (2) 0
Basis swaps – natural gas Gain (Loss) on Derivatives 44 (13) 47 (14)
Call options – natural gas Gain (Loss) on Derivatives (40) (4) (37) (9)
Call options – oil Gain (Loss) on Derivatives 0 0 (1) 1
Put options – natural gas Gain (Loss) on Derivatives 1 0 1 0
Swaptions – natural gas Gain (Loss) on Derivatives (4) 0 (3) 0
Purchased fixed price swap – natural gas storage Gain (Loss) on Derivatives 1 0 1 (1)
Fixed price swap – natural gas storage Gain (Loss) on Derivatives (2) 1 (2) 0
Interest rate swaps Gain (Loss) on Derivatives 0 1 1 0
Total gain (loss) on unsettled derivatives $ (772) $ (229) $ (941) $ 17

~~Table of Contents~~


Settled Gain (Loss) on Derivatives Recognized in Earnings (1)
Unsettled Gain (Loss) on Derivatives Recognized in Earnings																				Unsettled Gain (Loss) on Derivatives Recognized in Earnings
		Consolidated Statement of Operations Classification of Gain (Loss) on Derivatives, Settled		For the three months ended June 30,								For the six months ended June 30,									Consolidated Statement of Operations Classification of Gain (Loss) on Derivatives, Unsettled		For the three months ended March 31,
Derivative Instrument	Derivative Instrument		2021			2020				2021				2020				Derivative Instrument				2022			2021

				(in millions)																			(in millions)
Purchased fixed price swaps – natural gas			Gain (Loss) on Derivatives			$	1			$	(1)			$	1			$	(2)

Fixed price swaps – natural gas	Fixed price swaps – natural gas	Gain (Loss) on Derivatives		(6)				84		(2)		(1)				89		(2)		Fixed price swaps – natural gas	Gain (Loss) on Derivatives		$	(1,853)			$	(22)
Fixed price swaps – oil	Fixed price swaps – oil	Gain (Loss) on Derivatives		(28)				18				(45)				27				Fixed price swaps – oil	Gain (Loss) on Derivatives		(53)				(40)
Fixed price swaps – ethane	Fixed price swaps – ethane	Gain (Loss) on Derivatives		(6)				2				(10)				8				Fixed price swaps – ethane	Gain (Loss) on Derivatives		(21)				(2)
Fixed price swaps – propane	Fixed price swaps – propane	Gain (Loss) on Derivatives		(30)				7				(60)				17				Fixed price swaps – propane	Gain (Loss) on Derivatives		(49)				(45)
Fixed price swaps – normal butane	Fixed price swaps – normal butane	Gain (Loss) on Derivatives		(9)				0				(16)				0				Fixed price swaps – normal butane	Gain (Loss) on Derivatives		(20)				(15)
Fixed price swaps – natural gasoline	Fixed price swaps – natural gasoline	Gain (Loss) on Derivatives		(13)				0				(22)				0				Fixed price swaps – natural gasoline	Gain (Loss) on Derivatives		(28)				(20)
Two-way costless collars – natural gas	Two-way costless collars – natural gas	Gain (Loss) on Derivatives		(2)				0				0				6				Two-way costless collars – natural gas	Gain (Loss) on Derivatives		(342)				(12)
Two-way costless collars – oil	Two-way costless collars – oil	Gain (Loss) on Derivatives		(1)				6				(2)				9				Two-way costless collars – oil	Gain (Loss) on Derivatives		—				(1)
Two-way costless collars – propane		Gain (Loss) on Derivatives		0				1				0				2
Two-way costless collars – ethane																				Two-way costless collars – ethane	Gain (Loss) on Derivatives		1				—

Three-way costless collars – natural gas	Three-way costless collars – natural gas	Gain (Loss) on Derivatives		(8)				7				(7)				43				Three-way costless collars – natural gas	Gain (Loss) on Derivatives		(724)				—
Three-way costless collars – oil	Three-way costless collars – oil	Gain (Loss) on Derivatives		(5)				3				(6)				4				Three-way costless collars – oil	Gain (Loss) on Derivatives		(33)				(18)
Three-way costless collars – propane																				Three-way costless collars – propane	Gain (Loss) on Derivatives		(2)				(1)
Basis swaps – natural gas	Basis swaps – natural gas	Gain (Loss) on Derivatives		8				(7)				49				9				Basis swaps – natural gas	Gain (Loss) on Derivatives		36				3
Call options – natural gas																				Call options – natural gas	Gain (Loss) on Derivatives		(149)				3
Call options – oil																				Call options – oil	Gain (Loss) on Derivatives		—				(1)

Swaptions – natural gas																				Swaptions – natural gas	Gain (Loss) on Derivatives		—				1
Purchased fixed price swap – natural gas storage																				Purchased fixed price swap – natural gas storage	Gain (Loss) on Derivatives		1				—
Fixed price swap – natural gas storage																				Fixed price swap – natural gas storage	Gain (Loss) on Derivatives		1				—
Interest rate swaps																				Interest rate swaps	Gain (Loss) on Derivatives		(2)				1
Total loss on unsettled derivatives																				Total loss on unsettled derivatives			$	(3,237)			$	(169)

Settled Gain (Loss) on Derivatives Recognized in Earnings (1)																				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																				Derivative Instrument		2022			2021

																							(in millions)

Fixed price swaps – natural gas																				Fixed price swaps – natural gas		Gain (Loss) on Derivatives			$	(297)			$	5
Fixed price swaps – oil																				Fixed price swaps – oil	Gain (Loss) on Derivatives		(33)				(17)
Fixed price swaps – ethane																				Fixed price swaps – ethane	Gain (Loss) on Derivatives		(8)				(4)
Fixed price swaps – propane																				Fixed price swaps – propane	Gain (Loss) on Derivatives		(41)				(30)
Fixed price swaps – normal butane																				Fixed price swaps – normal butane	Gain (Loss) on Derivatives		(14)				(7)
Fixed price swaps – natural gasoline																				Fixed price swaps – natural gasoline	Gain (Loss) on Derivatives		(19)				(9)
Two-way costless collars – natural gas																				Two-way costless collars – natural gas	Gain (Loss) on Derivatives		(104)				2
Two-way costless collars – oil																				Two-way costless collars – oil	Gain (Loss) on Derivatives		—				(1)
Two-way costless collars – ethane																				Two-way costless collars – ethane	Gain (Loss) on Derivatives		(1)				—

Three-way costless collars – natural gas																				Three-way costless collars – natural gas	Gain (Loss) on Derivatives		(121)				1
Three-way costless collars – oil																				Three-way costless collars – oil	Gain (Loss) on Derivatives		(13)				(1)
Three-way costless collars – propane																				Three-way costless collars – propane	Gain (Loss) on Derivatives		(2)				—
Basis swaps – natural gas																				Basis swaps – natural gas	Gain (Loss) on Derivatives		1				41
Index swaps – natural gas																				Index swaps – natural gas	Gain (Loss) on Derivatives		(1)				—
Call options – natural gas																				Call options – natural gas	Gain (Loss) on Derivatives		(39)				—

Put options – natural gas	Put options – natural gas	Gain (Loss) on Derivatives		0				0				(2)		(3)		0				Put options – natural gas	Gain (Loss) on Derivatives		—				(2)		(2)

Fixed price swaps – natural gas storage	Fixed price swaps – natural gas storage	Gain (Loss) on Derivatives		0				0				0				1				Fixed price swaps – natural gas storage	Gain (Loss) on Derivatives		(3)				—

Total gain (loss) on settled derivatives				$	(99)			$	120			$	(121)			$	213
Total loss on settled derivatives																				Total loss on settled derivatives			$	(695)			$	(22)

Total gain (loss) on derivatives				$	(871)			$	(109)			$	(1,062)			$	230

(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 ~~amortization of premiums paid related to certain natural gas fixed price options for the three and six months ended June 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 ~~six~~three months ended ~~June 30,~~March 31, 2021, which is included in gain (loss) on derivatives on the consolidated statements of operations.

Table of Contents


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 six 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 ~~six~~three months ended ~~June 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 0 0 0
Amounts reclassified from other comprehensive income (1)
3 0 3
Net current-period other comprehensive income 3 0 3
Ending balance June 30, 2021 $ (21) $ (14) $ (35)

~~Details about Accumulated Other Comprehensive Income~~

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

~~Amount Reclassified from Accumulated Other Comprehensive Income~~

For the six months ended
June 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.

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(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 ~~June 30, 2021~~March 31, 2022 and December 31, ~~2020~~2021 were as follows:


		June 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	$	2	$	2	$	13	$	13	Cash and cash equivalents	$	21	$	21	$	28	$	28
2018 revolving credit facility due April 2024	2018 revolving credit facility due April 2024	568		568		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)	2,471		2,684		2,471		2,609		Senior notes (1)	4,209		4,318		4,430		4,745
Derivative instruments, net	Derivative instruments, net	(982)		(982)		(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. The fair ~~value~~values of the Company’s ~~4.10% Senior Notes due March 2022 is~~senior notes are considered to be a Level 21 measurement onas these are actively traded in the ~~fair value hierarchy. The fair values of the Company’s remaining senior notes are considered the be a Level 1 measurement.~~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 ~~June 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 $2$8 million and $1$3 million, respectively.

The Company has classified its derivative instruments into levels depending upon the data utilized to determine their fair values. The Company’s fixed price swaps (Level 2) are estimated using third-party discounted cash flow calculations using the New York Mercantile Exchange (“NYMEX”) futures index for natural gas and oil derivatives and Oil Price Information Service (“OPIS”) for ethane and propane derivatives. The Company utilizes discounted cash flow models for valuing its interest rate derivatives (Level 2). The net derivative values attributable to the Company’s interest rate derivative contracts as of March 31, 2022 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.

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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:


		June 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		$	0	$	3	$	0	$	3
Fixed price swaps		0		1		0		1

Two-way costless collars	Two-way costless collars	0		28		0		28		Two-way costless collars	$	—	$	54	$	—	$	54
Three-way costless collars	Three-way costless collars	0		92		0		92		Three-way costless collars	—		23		—		23
Basis swaps	Basis swaps	0		139		0		139		Basis swaps	—		152		—		152
Call options		0		9		0		9

Purchased fixed price swaps – storage	Purchased fixed price swaps – storage	0		1		0		1		Purchased fixed price swaps – storage	—		1		—		1
Interest rate swaps		0		1		0		1

Liabilities	Liabilities									Liabilities

Fixed price swaps	Fixed price swaps	0		(528)		0		(528)		Fixed price swaps	—		(2,906)		—		(2,906)
Two-way costless collars	Two-way costless collars	0		(181)		0		(181)		Two-way costless collars	—		(506)		—		(506)
Three-way costless collars	Three-way costless collars	0		(430)		0		(430)		Three-way costless collars	—		(1,254)		—		(1,254)
Basis swaps	Basis swaps	0		(27)		0		(27)		Basis swaps	—		(48)		—		(48)
Call options	Call options	0		(83)		0		(83)		Call options	—		(258)		—		(258)

Swaptions		0		(5)		0		(5)
Fixed price swaps – storage		0		(2)		0		(2)

Total (1)	Total (1)	$	0	$	(982)	$	0	$	(982)	Total (1)	$	—	$	(4,742)	$	—	$	(4,742)

(1)~~Includes~~Excludes a net reduction to the liability fair value of $2$8 million related to estimated ~~nonperformance~~non-performance risk.

December 31, 2020
Fair Value Measurements Using:
(in millions) Quoted Prices in Active Markets (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) Assets (Liabilities) at Fair Value
Assets
Purchased fixed price swaps $ 0 $ 1 $ 0 $ 1
Fixed price swaps 0 59 0 59
Two-way costless collars 0 74 0 74
Three-way costless collars 0 174 0 174
Basis swaps 0 75 0 75
Call options 0 4 0 4
Liabilities
Fixed price swaps 0 (96) 0 (96)
Two-way costless collars 0 (65) 0 (65)
Three-way costless collars 0 (214) 0 (214)
Basis swaps 0 (10) 0 (10)
Call options 0 (40) 0 (40)
Put options 0 (1) 0 (1)
Swaptions 0 (2) 0 (2)
Total (1)
$ 0 $ (41) $ 0 $ (41)

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	December 31, 2021
	Fair Value Measurements Using:
(in millions)	Quoted Prices in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Assets (Liabilities) at Fair Value
Assets

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

Liabilities

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




Total (1)	$	—	$	(1,505)	$	—	$	(1,505)

(1)~~Includes~~Excludes a net reduction to the liability fair value of $1$3 million related to estimated ~~nonperformance~~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

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

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(11) DEBT

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


		June 30, 2021										March 31, 2022
(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:										Current portion of long-term debt:
4.10% Senior Notes due March 2022		$	207	$	0		$	0	$	207
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	$	207	$	0		$	0	$	207	Total current portion of long-term debt	$	5		$	—		$	—	$	5

Long-term debt:	Long-term debt:										Long-term debt:
Variable rate (2.10% at June 30, 2021) 2018 revolving credit facility due April 2024		$	568	$	0	(1)	$	0	$	568
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)	856		(4)			(1)		851		4.95% Senior Notes due January 2025 ~~(2)~~(3)	389			(1)			—		388
7.50% Senior Notes due April 2026		618		(5)			0		613
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)			0		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)			0		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			(6)			24		718
5.375% Senior Notes due September 2030											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	$	2,832	$	(18)		$	(1)	$	2,813	Total long-term debt	$	4,927		$	(55)		$	23	$	4,895

Total debt	Total debt	$	3,039	$	(18)		$	(1)	$	3,020	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 term loan facility due April 2024		$	700	$	0	(1)	$	0	$	700
4.10% Senior Notes due March 2022		207		0			0		207
4.95% Senior Notes due January 2025 (2)		856		(4)			(1)		851
7.50% Senior Notes due April 2026		618		(6)			0		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)			0		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)			0		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 ~~June 30, 2021~~March 31, 2022 and December 31, ~~2020,~~2021, unamortized issuance expense of ~~$11~~$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 ~~June 2,~~

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September 1, 2021, ~~in conjunction with the announcement of the Indigo Merger,~~ S&P ~~placed~~upgraded the Company’s bond rating to BB, and on ~~credit watch for a potential positive upgrade. Interest savings from any potential upgrade would be realized for~~January 6, 2022, S&P further upgraded the Company’s bond rating to BB+, which decreased the interest rate on the 2025 Notes to 5.95% beginning with coupon payments paid after January 2022.

The following is a summary of scheduled debt maturities by year as of ~~June 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		$	0
2022	2022	207		2022	$	4
2023	2023	0		2023	6
2024 (1)	2024 (1)	568		2024 (1)	179
2025	2025	856		2025	395
2026				2026	5
Thereafter	Thereafter	1,408		Thereafter	4,343
		$	3,039		$	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 ~~March~~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.

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 ~~June 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 ~~June 30, 2021,~~March 31, 2022, the Company had ~~$233~~$147 million in letters of credit and ~~$568~~$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.

~~The Company’s debt exposure to~~2022 Credit Facility

On April 8, 2022, the ~~anticipated transition from LIBOR in late 2021 is limited to~~Company entered into an Amended and Restated Credit Agreement that replaces the 2018 credit ~~facility. Upon announcement~~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 ~~administrator~~Company and its subsidiaries. The 2022 credit facility has a term of ~~LIBOR identifying~~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 ~~specific date~~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 ~~LIBOR cessation,~~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, ~~will be amended to reference an alternative rate as established by JP Morgan, as~~excludes the effects of interest expense, depreciation, depletion and amortization, income tax, any non-cash impacts from

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~~Administrative Agent,~~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 ~~Company. The alternative rate~~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 ~~prevailing market convention~~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 ~~expected~~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 ~~Secured Overnight Financing Rate (“SOFR”).~~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 obligations under the Term Loan are guaranteed by each of the Company’s subsidiaries that guarantee the obligations under the 2018 (2022 as amended) credit facility and are secured by liens on substantially all the assets of the Company and the Company’s subsidiaries on an equal basis with the liens securing the obligations under the 2018 (2022 as amended) credit facility.

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 ~~June 2,~~September 1, 2021, ~~in conjunction with the announcement of the Indigo Merger,~~ S&P ~~placed~~upgraded the Company’s bond rating to BB, and on ~~credit watch for a potential positive upgrade. Interest savings~~January 6, 2022, S&P further upgraded the Company’s bond rating to BB+, which decreased the interest rate on the 2025 Notes ~~from any potential upgrade would be realized for~~to 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,~~August 30, 2021, Southwestern ~~entered into~~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 ~~Indigo Merger Agreement.~~ 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 $845 million, and the Company recognized a $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 ~~will assume~~assumed $700 million in aggregate principal amount of Indigo’s 5.375% Senior Notes due 2029 (“Indigo Notes”). As part of ~~Indigo.~~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 ~~transaction is expected~~net proceeds of this offering, along with the net proceeds from the Term Loan, were used to ~~close~~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 ~~second half~~first quarter of ~~2021, subject to customary closing conditions, including~~2022, the ~~approval~~Company repurchased the remaining outstanding principal balance of ~~Southwestern’s shareholders.~~$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 ~~June 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 ~~$8.3~~$10.2 billion, ~~$369~~$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 ~~$895~~$877 million of that total amount. As of ~~June 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	$	7,965	$	713	$	1,557	$	1,317	$	1,744	$	2,634	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)	369		2		18		25		52		272		Pending regulatory approval and/or construction (1)	857		3		124		161		247		322
Total transportation charges	Total transportation charges	$	8,334	$	715	$	1,575	$	1,342	$	1,796	$	2,906	Total transportation charges	$	10,158	$	1,069	$	2,067	$	1,890	$	2,332	$	2,800

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

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

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

Environmental Risk

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

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Litigation

The Company is subject to various litigation, claims and proceedings, most of which have arisen in the ordinary course of business, such as for alleged breaches of contract, miscalculation of royalties, employment matters, traffic accidents, pollution, contamination, encroachment on others’ property or nuisance. The Company accrues for litigation, claims and proceedings when a liability is both probable and the amount can be reasonably estimated. As of ~~June 30, 2021,~~March 31, 2022, the Company does not currently have any material amounts accrued related to litigation ~~matters.~~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~~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 ~~October 17, 2016, the St. Lucie County Fire District Firefighters’ Pension Trust~~June 12, 2018, a collection of 51 individuals and entities filed a ~~putative class action~~lawsuit against 15 oil and gas company defendants, including Indigo, in Louisiana state court claiming damages arising out of current and historical development and production activity on certain acreage located in DeSoto Parish, Louisiana. The plaintiffs, who claim to own the properties at issue, assert that Indigo’s actions and the actions of other current operators conducting development and production activity, combined with the improper plugging and abandoning of legacy wells by former operators, have caused environmental contamination to their properties. Among other things, the plaintiffs contend that the defendants’ conduct resulted in the ~~61st District Court~~migration of natural gas,

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along with oilfield contaminants, into the Carrizo-Wilcox aquifer system underlying certain portions of DeSoto Parish. The plaintiffs assert claims based in ~~Harris County, Texas, against~~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 ~~certain~~as a party to the litigation.

The presence of ~~its former officers and current and former directors~~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 ~~underwriters on behalf of itself~~Company is cooperating and ~~others~~coordinating with Conservation in 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.~~ investigation. The Conservation matter number is EMER18-003.

The Company ~~removed the case~~does not currently expect this matter to ~~federal court, but after~~have a ~~decision by the United States Supreme Court in an unrelated case that these types~~material impact on its financial position, results 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. The trial court has issued an order preliminarily approving the settlement. A hearing on final approval of the settlement is set for October 21, 2021.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. ~~NaN~~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 six~~ months ended ~~June 30, 2021.~~March 31, 2022. The effective tax rate for the three ~~and six~~ months ~~June 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.

InAs of the first quarter of ~~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,~~2022, the Company ~~concluded that it was more likely than not that these deferred tax assets will not be realized and recorded~~still maintains a ~~discrete tax expense of $408 million for the increase in its~~full valuation allowance. ~~The net change in valuation allowance is reflected as a component of income tax expense.~~ 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% for the three months ended March 31, 2021. The effective tax rate for the three months ended March 31, 2021 related to the effects of the valuation allowance against the Company’s U.S. deferred tax assets.

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

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~~The Company’s effective tax rate was~~NOL carryovers, of which approximately 0%$3 billion expire between 2035 and ~~(20)% for the three~~2037 and ~~six months ended June 30, 2020, respectively. The effective tax rate for the six months ended June 30, 2020 was primarily the effect of recording the valuation allowance discussed above.~~

$1 billion have an indefinite carryforward life. The Company ~~adopted Accounting Standards Update No. 2019-12 (“ASU 2019-12”) in the current period. ASU 2019-12 addressed simplification~~currently estimates that approximately $2 billion of these federal NOLs will expire before they are able to ~~income tax accounting rules, such as removing~~be used. The non-expiring NOLs remain subject to a ~~few exceptions~~full valuation allowance. If a subsequent ownership change were to ~~intraperiod allocation. There was no material impact to the financial statements~~occur as a result of ~~this adoption.~~future transactions in the Company’s common stock, the Company’s use of remaining U.S. tax attributes may be further limited.

For three months ended March 31, 2022, the Company recorded current income tax expense of approximately $4 million as it expects to pay cash income taxes for the 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 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 the Company’s 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 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 the event a plan is overfunded, the Company recognizes an asset. Conversely, if a plan is underfunded, the Company recognizes a liability.

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


		Consolidated Statements of Operations Classification of Net Periodic Benefit Cost	For the three months ended June 30,				For the six months ended June 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	$	0	$	2	$	0	$	4	Service cost	General and administrative expenses	$	—	$	—
Interest cost	Interest cost	Other Income (Loss), Net	1		1		2		2		Interest cost	Other Income (Loss), Net	1		1
Expected return on plan assets	Expected return on plan assets	Other Income (Loss), Net	(2)		(2)		(3)		(3)		Expected return on plan assets	Other Income (Loss), Net	—		(1)

Amortization of net loss	Amortization of net loss	Other Income (Loss), Net	0		0		0		0		Amortization of net loss	Other Income (Loss), Net	—		—
Settlement loss	Settlement loss	Other Income (Loss), Net	1		0		1		0		Settlement loss	Other Income (Loss), Net	—		—
Net periodic benefit cost	Net periodic benefit cost		$	0	$	1	$	0	$	3	Net periodic benefit cost		$	1	$	—

The Company recognized ~~a $1 million~~an immaterial non-cash settlement loss ~~related to $4 million of lump sum payments from the pension plan~~ in the first ~~half of 2021. As a result of settlement accounting requirements, the Company recorded a $3 million reduction to its net pension liability in the second~~ quarter 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 million~~ ~~and less than~~ $1 million for each of the three months ended ~~June 30, 2021~~March 31, 2022 and ~~2020, respectively, and~~ ~~$1 million~~ ~~and $1 million for the six months ended June 30, 2021 and 2020, respectively.~~2021.

~~As of June 30, 2021, the~~The Company ~~has contributed~~ ~~$9 million~~does not expect to ~~the pension and other postretirement benefit plans and expects to contribute an~~make any additional ~~$3 million~~contributions to its pension plan during 2022 or thereafter until the ~~remainder of 2021.~~plan termination is completed. The Company recognized liabilities of ~~$21~~$12 million and ~~$14~~$13 million related to its pension and other postretirement benefits ~~respectively,~~ as of ~~June 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 ~~June 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

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performance cash awards to employees and directors which generally vest over ~~four~~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 six~~ months ended ~~June 30, 2021~~March 31, 2022 and ~~2020:~~2021:

For the three months ended June 30, For the six months ended June 30,
(in millions) 2021 2020 2021 2020
Stock-based compensation cost – expensed $ 9 $ 6 $ 22 $ 6
Stock-based compensation cost – capitalized 5 1 10 1


	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 six~~ months ended ~~June 30, 2021~~March 31, 2022 and ~~2020:~~2021:


		For the three months ended June 30,				For the six months ended June 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	$	1	$	2	$	2	Equity-classified awards – expensed	$	1	$	—
Equity-classified awards – capitalized	Equity-classified awards – capitalized	0		0		0		0		Equity-classified awards – capitalized	$	—	$	—

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Equity-Classified Stock Options

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


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

Equity-Classified Restricted Stock

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


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

As of ~~June 30, 2021,~~March 31, 2022, there was less than $1 million of total unrecognized compensation cost related to the Company’s unvested equity-classified restricted stock ~~option grants,~~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 ~~grants~~units. This cost is expected to be recognized over a weighted-average period of 2.6 years. The following table summarizes equity-classified restricted stock units for the three months ended March 31, 2022 and provides information for unvested units as of March 31, 2022.


	Number of Shares	Weighted Average Fair Value
	(in thousands)
Unvested units at December 31, 2021	37	$	3.05
Granted	1,699	$	4.45
Vested	—	$	—
Forfeited	(2)	$	3.05
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 ~~1.4~~2.9 years.

~~Equity-Classified Stock Options~~

The following table summarizes equity-classified stock option activity for the six months ended June 30, 2021 and provides information for options outstanding and options exercisable as of June 30, 2021:

Number
of Options Weighted Average
Exercise Price
(in thousands)
Outstanding at December 31, 2020 3,850 $ 13.39
Granted 0 $ 0
Exercised 0 $ 0
Forfeited or expired (151) $ 32.21
Outstanding at June 30, 2021 3,699 $ 12.63
Exercisable at June 30, 2021 3,699 $ 12.63

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~~Equity-Classified Restricted Stock~~

~~The following table summarizes equity-classified restricted stock activity for the six months ended June 30, 2021 and provides information for unvested shares as of June 30, 2021:~~

Number
of Shares Weighted Average
Fair Value
(in thousands)
Unvested shares at December 31, 2020 697 $ 5.97
Granted 307 $ 5.30
Vested (855) $ 5.83
Forfeited 0 $ 8.59
Unvested shares at June 30, 2021 149 $ 5.38

~~Equity-Classified Restricted Stock Units~~

As a result of the Montage Merger, certain employees became employees of Southwestern and retained their original equity awards. The following table summarizes equity-classified performance unit activity for the six months ended June 30, 2021 and provides information for unvested units as of June 30, 2021.


		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	—	$	—
Granted	Granted	0	$	0	Granted	850	$	6.04
Vested	Vested	(87)	$	3.05	Vested	—	$	—
Forfeited	Forfeited	0	$	0	Forfeited	—	$	—
Unvested units at June 30, 2021		47	$	3.05
Unvested units at March 31, 2022					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 six~~ months ended ~~June 30, 2021:~~March 31, 2022:


		For the three months ended June 30,				For the six months ended June 30,					For the three months ended March 31,
(in millions)	(in millions)	2021		2020		2021		2020		(in millions)	2022		2021
Liability-classified stock-based compensation cost – expensed	Liability-classified stock-based compensation cost – expensed	$	7	$	5	$	20	$	4	Liability-classified stock-based compensation cost – expensed	$	8	$	13
Liability-classified stock-based compensation cost – capitalized	Liability-classified stock-based compensation cost – capitalized	5		1		10		1		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 ~~June 30, 2021,~~March 31, 2022, there was ~~$25~~$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 ~~1.8~~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
(in thousands)
Unvested units at December 31, 2020 11,613 $ 2.67
Granted 1,486 $ 4.23
Vested (4,522) $ 3.40
Forfeited (489) $ 4.37
Unvested units at June 30, 2021 8,088 $ 4.90

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	Number of Units	Weighted Average Fair Value
	(in thousands)
Unvested units at December 31, 2021	7,937	$	4.08
Granted	—	$	—
Vested	(3,806)	$	4.47
Forfeited	(12)	$	7.01
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 ~~June 30, 2021,~~March 31, 2022, there was ~~$25~~$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 ~~1.9~~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 (622) $ 2.98
Unvested units at June 30, 2021 9,637 $ 3.38


	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 ~~June 30, 2021,~~March 31, 2022, there was ~~$27~~$42 million of total unrecognized compensation cost related to performance cash awards. This cost is expected to be recognized over a ~~weighted average 3.3~~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	(4,373)	$	1.00	Vested	(8,483)	$	1.00
Forfeited	Forfeited	(2,708)	$	1.00	Forfeited	(675)	$	1.00
Unvested units at June 30, 2021		29,818	$	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 June 30, 2021 (in millions)
Revenues from external customers $ 718 $ 332 $ 0 $ 1,050
Intersegment revenues (14) 651 0 637
Depreciation, depletion and amortization expense 97 3 0 100
Operating income 286 (1) 7 0 293
Interest expense (2)
30 0 0 30
Gain (loss) on derivatives (872) 0 1 (871)
Other loss, net (1) 0 0 (1)
Assets 4,870 (3) 408 116 5,394
Capital investments (4)
259 0 0 259
Three months ended June 30, 2020
Revenues from external customers $ 223 $ 187 $ 0 $ 410
Intersegment revenues (12) 202 0 190
Depreciation, depletion and amortization expense 81 3 0 84
Impairments 655 0 0 655
Operating loss (748) (1) (8) 0 (756)
Interest expense (2)
22 0 0 22
Loss on derivatives (109) 0 0 (109)
Gain on early extinguishment of debt 0 0 7 7
Other income (loss), net (1) 0 1 0
Assets 4,185 (3) 208 162 4,555
Capital investments (4)
245 0 0 245

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E&P Marketing Other Total
Six months ended June 30, 2021 (in millions)
Revenues from external customers $ 1,437 $ 685 $ 0 $ 2,122
Intersegment revenues (28) 1,295 0 1,267
Depreciation, depletion and amortization expense 191 5 0 196
Operating income 581 (1) 13 0 594
Interest expense (2)
61 0 0 61
Gain (loss) on derivatives (1,063) 0 1 (1,062)
Assets 4,870 (3) 408 116 5,394
Capital investments (4)
525 0 0 525
Six months ended June 30, 2020
Revenues from external customers $ 576 $ 426 $ 0 $ 1,002
Intersegment revenues (21) 511 0 490
Depreciation, depletion and amortization expense 192 5 0 197
Impairments 2,134 0 0 2,134
Operating loss (2,234) (1) (12) 0 (2,246)
Interest expense (2)
41 0 0 41
Gain on derivatives 230 0 0 230
Gain on early extinguishment of debt 0 0 35 35
Other income, net 0 0 1 1
Benefit from income taxes (2)
406 0 0 406
Assets 4,185 (3) 208 162 4,555
Capital investments (4)
482 0 0 482


	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 ~~$1 million and $2~~$6 million of restructuring charges for the three months ended ~~June 30, 2021 and 2020, respectively, and $7 million and $12 million of restructuring charges for the six months ended June 30, 2021 and 2020, respectively.~~2021. The E&P segment operating income (loss) also includes $3$25 million and $4$1 million of merger-related ~~charges~~expenses for the three ~~and six~~ months ended ~~June 30,~~March 31, 2022 and 2021, respectively.

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

(3)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 include ~~a decrease~~increases of $9$43 million and $38 million for the three months ended ~~June 30,~~March 31, 2022 and 2021, ~~and increases of $29 million and $8 million for the six months ended June 30, 2021 and 2020,~~ respectively, relating to the change in accrued expenditures between periods. ~~There was no change in the capital accrual for the three months ended June 30, 2020.~~

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


		As of June 30,					As of March 31,
(in millions)	(in millions)	2021		2020		(in millions)	2022		2021
Cash and cash equivalents	Cash and cash equivalents	$	2	$	10	Cash and cash equivalents	$	21	$	4
Accounts receivable	Accounts receivable	3		0		Accounts receivable	1		—
Income taxes receivable		0		31

Prepayments	Prepayments	15		7		Prepayments	6		6
Property, plant and equipment	Property, plant and equipment	14		21		Property, plant and equipment	10		15
Unamortized debt expense	Unamortized debt expense	11		10		Unamortized debt expense	9		11
Right-of-use lease assets	Right-of-use lease assets	67		77		Right-of-use lease assets	63		70
Non-qualified retirement plan	Non-qualified retirement plan	4		5		Non-qualified retirement plan	2		4
Other		0		1
		$	116	$	162
							$	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 isNone that are 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 transactions that reference~~have 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 Company is currently assessing the impact of adopting this new guidance.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 ~~2020~~2021 Annual Report and analyzes the changes in the results of operations between the three ~~and six~~ month periods ended ~~June 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.

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 ~~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 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 ~~oil~~as well as associated NGLs and ~~NGLs,~~oil, with our ongoing operations focused on ~~the development of~~ unconventional natural gas reservoirs located in Pennsylvania, West Virginia, Ohio and ~~West Virginia.~~Louisiana. Our operations in ~~northeast~~ Pennsylvania, West Virginia and Ohio, which we refer to as “Northeast Appalachia,” are primarily focused on the unconventional natural gas reservoir known as the Marcellus Shale. Our operations in West Virginia, Ohio and southwest Pennsylvania, which we refer to as “Southwest Appalachia,“Appalachia,” are focused on the Marcellus Shale, the Utica and the Upper Devonian unconventional natural gas and ~~oil~~liquids reservoirs. ~~Collectively, our properties~~Our operations in ~~Pennsylvania, Ohio and West Virginia~~

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~~are herein referred~~Louisiana, which we refer to as ~~“Appalachia.~~“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 ~~June~~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 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 ofclosed on the Indigo Merger, Agreement, Indigo will merge with and into Ikon, a subsidiary of Southwestern, with Indigo surviving the merger (the “Indigo Merger”). The outstanding equity interests in Indigo will be cancelled and converted into the right to receive (i) $400 million in cash consideration, and (ii) 339,270,568 shares of Southwestern common stock, in each case, subject to adjustment as providedwhich established our natural gas operations in the ~~Indigo Merger Agreement. Additionally,~~Haynesville and Bossier Shales in Louisiana.

•On December 31, 2021, we will assume $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 $1.6 billion, basedclosed 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 May 28, 2021.~~

~~Following the closing of the Indigo~~GEPH Merger, Southwestern’s existing shareholders and Indigo’s existing equity holders will own approximately 67% and 33%, respectively, of the outstanding shares of the combined company. The transaction is expected to closewhich expanded our operations in the ~~second half of 2021, subject to customary closing conditions, including the approval of Southwestern’s shareholders.~~ Haynesville.

The Indigo Merger ~~is expected~~and GEPH Merger are the result of our strategy to diversify our operations by expanding our portfolio beyond Appalachia into the Haynesville ~~basin~~ and ~~give~~Bossier formations, giving us additional exposure to the LNG corridor and other markets on the U.S. Gulf Coast.

~~On November 13, 2020, we closed on~~ This expansion lowered our Agreement and Plan of 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 Mergerenterprise business risk, expanded our ~~footprint in Appalachia by supplementing our Northeast Appalachia~~economic inventory, opportunity set and ~~Southwest Appalachia operations~~business optionality and ~~by expanding our operations into Ohio.~~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 ~~second~~first quarter ~~2021~~2022 operating and financial results include:

Total Company

•Net loss of ~~$609~~$2,675 million, or ($~~0.90)~~2.40) per diluted share, ~~improved~~decreased compared to net ~~loss~~income of ~~$880~~$80 million, or ~~($1.63)~~$0.12 per diluted share, for the same period in ~~2020. The improvement was~~2021. Net loss decreased primarily ~~due to~~as a ~~$1,049~~$998 million increase in operating income ~~partially~~was more than offset by a ~~$762~~$3,736 million reduction resulting from the impact of improved forward pricing on our derivatives position, ~~$543~~$3,063 million of which was unrealized. Excluding the change in derivatives position, ~~and the impact of the $650 million impairment recorded in the second quarter of 2020,~~ net income increased ~~$383~~$981 million in the ~~second~~first quarter of ~~2021,~~2022, compared to the same period in ~~2020,~~2021, primarily as a ~~$399~~$998 million improvement in operating income was partially offset by ~~an $8~~a $2 million ~~increase in interest expense and a $7 million gain~~loss on the early extinguishment of debt recorded in the ~~second~~first quarter of ~~2020.~~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 ~~$293~~$1,299 million increased compared to operating ~~loss~~income of ~~$756~~$301 million for the same period in ~~2020~~2021 on a consolidated basis. Operating ~~loss in the second quarter of 2020 included a $650~~income increased $1,871 million, ~~non-cash full cost ceiling test impairment. Excluding the non-cash impairment, operating income improved $399 million, compared to the same period in 2020,~~ as ~~a $640 million increase in operating revenues more than~~increased commodity pricing and natural gas production were only partially offset ~~a $241 million increase in~~by increased operating costs ~~associated with increased production, and expenses.~~of $873 million.

•Net cash provided by operating activities of ~~$270~~$972 million increased ~~187%~~180% from ~~$94~~$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 ~~$259~~$544 million in the first quarter of 2022 increased 6%105% from ~~$245~~$266 million for the same period in ~~2020.~~2021 due to the addition of the acquired Haynesville assets.

E&P

•E&P ~~segment~~ operating income of ~~$286 million increased from an operating loss of $748 million for the same period in 2020, primarily related to the non-cash full cost ceiling test impairment of $650~~$1,278 million in the ~~second~~first quarter of ~~2020. Excluding the non-cash impairment, E&P operating income~~2022 increased ~~$384~~$983 million, compared to the same period in ~~2020,~~2021, primarily as ~~a $493~~an $1,369 million increase in E&P operating revenues resulting from a ~~$1.50~~$2.26 per Mcfe increase in our realized weighted average price per Mcfe (excluding derivatives) and ~~a 75~~an 156 Bcfe increase in production volumes was only partially offset by a ~~$109~~$386 million increase in E&P operating costs and expenses.

~~Table of Contents~~

•Total net production of ~~276~~425 Bcfe, which was comprised of ~~79%~~88% natural gas and ~~21%~~12% oil and NGLs, increased ~~37%~~58% from ~~201~~269 Bcfe in the same period in ~~2020,~~2021, primarily due to a ~~39%~~76% increase in our natural gas production ~~23% of~~ which was ~~associated with natural gas production~~driven by the Haynesville assets acquired from ~~our Montage Merger-related properties acquired~~Indigo and GEPH in ~~November 2020.~~September 2021 and December 2021, respectively.

•Excluding the effect of derivatives, our realized natural gas price of ~~$1.92~~$4.50 per ~~Mcf~~Mcfe increased ~~96%~~113%, our realized oil price of ~~$57.50~~$86.30 per barrel increased ~~266%~~79% and our realized NGL price of ~~$23.24~~$39.33 per barrel increased ~~261%~~72%, as compared to the same period in ~~2020.~~2021. Excluding the effect of derivatives, our total weighted average realized price of ~~$2.55~~$4.88 per Mcfe increased ~~143%~~86% from the same period in ~~2020.~~2021.

•E&P segment invested ~~$259~~$544 million in capital; drilling 2333 wells, completing 1937 wells and placing 3132 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 Merger and anticipated Indigo Merger 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.~~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 ~~half~~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 ~~2021~~ 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.

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E&P


		For the three months ended June 30,						For the six months ended June 30,							For the three months ended March 31,
(in millions)	(in millions)	2021			2020			2021			2020			(in millions)	2022			2021
Revenues	Revenues	$	704		$	211		$	1,409		$	555		Revenues	$	2,074		$	705
Operating costs and expenses	Operating costs and expenses	418		(1)	959		(2)	828		(1)	2,789		(2)	Operating costs and expenses	796		(1)	410		(2)
Operating income (loss)		$	286		$	(748)		$	581		$	(2,234)
Operating income														Operating income	$	1,278		$	295

Gain (loss) on derivatives, settled	Gain (loss) on derivatives, settled	$	(99)		$	120		$	(121)		$	213		Gain (loss) on derivatives, settled	$	(695)		$	(22)

(1)Includes ~~$1 million and $7~~$25 million in ~~restructuring charges for the three and six months ended June 30, 2021, respectively and $3 million and $4 million in merger related~~merger-related expenses for the three ~~and six~~ months ended ~~June 30, 2021, respectively.~~March 31, 2022.

(2)Includes ~~$650 million and $2,129 million related to non-cash full cost ceiling test impairments for the three and six months ended June 30, 2020, respectively, $2 million and $12~~$6 million in restructuring charges and $1 million in merger-related expenses for the three ~~and six~~ months ended ~~June 30, 2020, respectively, and $5 million related to the non-cash impairment of other non-core assets for the three and six months ended June 30, 2020.~~March 31, 2021.

Operating Income (Loss)

•E&P segment operating income increased ~~$1,034~~$983 million for the three months ended ~~June 30, 2021,~~March 31, 2022, compared to the same period in 2020. The operating loss for the second quarter of 2020 included a $650 million non-cash full cost ceiling test impairment. Excluding the effect of the impairment, operating income improved $384 million, compared to the same period in 2020, as a $4932021. A $1,369 million increase in E&P operating revenues resulting from ~~a 143%~~an 86% increase in our realized weighted average price per Mcfe (excluding derivatives) and a ~~37%~~58% increase in production volumes was only partially offset by a ~~$109 million increase in E&P operating costs and expenses.~~

•Operating income for the E&P segment increased $2,815 million for the six months ended June 30, 2021 compared to the same period in 2020. The operating loss for the six months ended June 30, 2020 included a $2,129 million non-cash full cost ceiling test impairment. Excluding the effect of the impairment, operating income improved $686 million, compared to the same period in 2020, as a $854 million increase in E&P operating revenues resulting from a 88% increase in our realized weighted average price per Mcfe (excluding derivatives) and a 36% increase in production volumes was only partially offset by a $168$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 June 30,
(in millions except percentages) Natural
Gas Oil NGLs Total
2020 sales revenues $ 155 $ 16 $ 40 $ 211
Changes associated with prices 206 77 128 411
Changes associated with production volumes 60 12 10 82
2021 sales revenues $ 421 $ 105 $ 178 $ 704
Increase from 2020 172 % 556 % 345 % 234 %


		Six months ended June 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)		$	394		$	68		$	90		$	552
2021 sales revenues (1)														2021 sales revenues (1)	$	451		$	80		$	173		$	704
Changes associated with prices	Changes associated with prices	328			89			239			656			Changes associated with prices	897			49			114			1,060
Changes associated with production volumes	Changes associated with production volumes	150			28			22			200			Changes associated with production volumes	342			(19)			(15)			308
2021 sales revenues (2)		$	872		$	185		$	351		$	1,408
Increase from 2020		121		%	172		%	290		%	155		%
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 $3 million in other operating revenues for the six months ended June 30, 2020 primarily related to gains on purchaser imbalances associated with certain NGLs.~~

~~(2)~~Excludes $1 million in other operating revenues for the ~~six~~three months ended ~~June 30,~~March 31, 2021 primarily related to ~~gains on purchaser imbalances associated with certain NGLs.~~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 June 30,				Increase/(Decrease)		For the six months ended June 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)
Northeast Appalachia		123		113		9%		241			227		6%
Southwest Appalachia		96		45		113%		192			87		121%
Appalachia																		Appalachia			210				214		(2)%
Haynesville (1)																		Haynesville (1)	166				—			100%

Total	Total	219		158		39%		433			314		38%					Total	376				214			76%

Oil (MBbls)	Oil (MBbls)																	Oil (MBbls)
Southwest Appalachia		1,826		1,079		69%		3,484			2,474		41%
Appalachia																		Appalachia	1,263				1,658			(24)%
Haynesville (1)																		Haynesville (1)	4				—			100%
Other	Other	5		4		25%		9			8		13%					Other	3				4			(25)%
Total	Total	1,831		1,083		69%		3,493			2,482		41%					Total	1,270				1,662			(24)%

NGL (MBbls)	NGL (MBbls)																	NGL (MBbls)
Southwest Appalachia		7,665		6,110		25%		15,242			12,237		25%
Appalachia																		Appalachia	6,919				7,577			(9)%
Other	Other	1		1		—%		2			2		—%					Other	—				1			(100)%
Total	Total	7,666		6,111		25%		15,244			12,239		25%					Total	6,919				7,578			(9)%

Production volumes by area: (Bcfe)	Production volumes by area: (Bcfe)																	Production volumes by area: (Bcfe)
Northeast Appalachia		123		113		9%		241			227		6%
Southwest Appalachia		153		88		74%		304			175		74%
Appalachia																		Appalachia	259				269			(4)%
Haynesville (1)																		Haynesville (1)	166				—			100%

Total (1)		276		201		37%		545			402		36%
Total																		Total	425				269			58%

Production volumes by formation: (Bcfe)																		Production volumes by formation: (Bcfe)
Marcellus Shale																		Marcellus Shale	217				213			2%
Utica Shale																		Utica Shale	42				56			(25)%
Haynesville Shale (1)																		Haynesville Shale (1)	105				—			100%
Bossier Shale (1)																		Bossier Shale (1)	61				—			100%

Total																		Total	425				269			58%

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

(1)~~Approximately 242 Bcfe~~The Haynesville E&P assets were acquired through the Indigo Merger and ~~200 Bcfe for~~ the ~~three months ended June 30,~~GEPH Merger in September 2021 and ~~2020, respectively, and 455 Bcfe and 401 Bcfe for the six months ended June 30,~~December 2021, ~~and 2020, respectively, were produced from the Marcellus Shale formation. Approximately 34 Bcfe and 90 Bcfe for the three and six months ended June 30, 2021 were produced from the Utica formation.~~respectively.

•E&P production volumes increased by 75156 Bcfe for the three months ended ~~June 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 44 Bcfe associated with our recently acquired Montage properties, all of which is reflected in Southwest Appalachia.~~

•~~E&P production volumes increased by 143 Bcfe for the six months ended June 30, 2021,~~as compared to the same period in ~~2020, primarily~~2021, due to ~~incremental production volumes of 92 Bcfe associated with~~a higher capital allocation to our recently acquired ~~Montage properties, of which 91 Bcfe is reflected in Southwest Appalachia and 1 Bcfe is reflected in Northeast Appalachia.~~Haynesville assets.

•Oil and NGL production ~~increased 69% and 25%, respectively,~~decreased 11% for the three months ended ~~June 30, 2021,~~March 31, 2022, compared to the same period in ~~2020. Production volumes associated with the~~2021, primarily due to a higher capital allocation to our recently acquired ~~Montage properties were 299 MBbls and 870 MBbls for oil and NGLs, respectively, for the three months ended June 30, 2021.~~Haynesville assets.

•Oil and NGL production increased 41% and 25%, respectively, for the six months ended June 30, 2021, compared to the same period in 2020. Production volumes associated with the recently acquired Montage properties were 640 MBbls and 1,804 MBbls for oil and NGLs, respectively, for the six months ended June 30, 2021.

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 in order to maintain appropriate liquidity and financial flexibility.

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		For the three months ended June 30,						Increase/(Decrease)		For the six months ended June 30,							Increase/(Decrease)		For the three months ended March 31,								Increase/(Decrease)
		2021			2020				2021				2020					2022		2021		Increase/(Decrease)
Natural Gas Price:	Natural Gas Price:																									Natural Gas Price:
NYMEX Henry Hub Price ($/MMBtu) (1)	NYMEX Henry Hub Price ($/MMBtu) (1)	$	2.83		$	1.72		65%		$	2.76			$	1.83		51%				NYMEX Henry Hub Price ($/MMBtu) (1)				$	4.95				$	2.69		84%
Discount to NYMEX (2)	Discount to NYMEX (2)	(0.91)			(0.74)			23%		(0.74)				(0.57)			30%				Discount to NYMEX (2)	(0.45)					(0.58)					(22)%
Average realized gas price, excluding derivatives ($/Mcf)	Average realized gas price, excluding derivatives ($/Mcf)	$	1.92		$	0.98		96%		$	2.02			$	1.26		60%				Average realized gas price, excluding derivatives ($/Mcf)	$	4.50				$	2.11				113%
Gain (loss) on settled financial basis derivatives ($/Mcf)		0.03			(0.05)					0.11				0.03
Gain on settled financial basis derivatives ($/Mcf)																					Gain on settled financial basis derivatives ($/Mcf)	0.01					0.19
Gain (loss) on settled commodity derivatives ($/Mcf)	Gain (loss) on settled commodity derivatives ($/Mcf)	(0.06)			0.57					(0.02)				0.43							Gain (loss) on settled commodity derivatives ($/Mcf)	(1.51)					0.03
Average realized gas price, including derivatives ($/Mcf)	Average realized gas price, including derivatives ($/Mcf)	$	1.89		$	1.50		26%		$	2.11			$	1.72		23%				Average realized gas price, including derivatives ($/Mcf)	$	3.00				$	2.33				29%

Oil Price:	Oil Price:																				Oil Price:
WTI oil price ($/Bbl) (3)	WTI oil price ($/Bbl) (3)	$	66.07		$	27.85		137%		$	61.96			$	37.01		67%				WTI oil price ($/Bbl) (3)	$	94.29				$	57.84				63%
Discount to WTI(4)	Discount to WTI(4)	(8.57)			(12.16)			(30)%		(8.92)				(9.46)			(6)%				Discount to WTI(4)	(7.99)					(9.70)					(18)%
Average oil price, excluding derivatives ($/Bbl)	Average oil price, excluding derivatives ($/Bbl)	$	57.50		$	15.69		266%		$	53.04			$	27.55		93%				Average oil price, excluding derivatives ($/Bbl)	$	86.30				$	48.14				79%
Gain (loss) on settled derivatives ($/Bbl)		(19.13)			25.95					(15.34)				16.53
Loss on settled derivatives ($/Bbl)																					Loss on settled derivatives ($/Bbl)	(36.01)					(11.17)
Average oil price, including derivatives ($/Bbl)	Average oil price, including derivatives ($/Bbl)	$	38.37		$	41.64		(8)%		$	37.70			$	44.08		(14)%				Average oil price, including derivatives ($/Bbl)	$	50.29				$	36.97				36%

NGL Price:	NGL Price:																				NGL Price:
Average realized NGL price, excluding derivatives ($/Bbl)	Average realized NGL price, excluding derivatives ($/Bbl)	$	23.24		$	6.43		261%		$	23.05			$	7.29		216%				Average realized NGL price, excluding derivatives ($/Bbl)	$	39.33				$	22.86				72%
Gain (loss) on settled derivatives ($/Bbl)		(7.37)			1.79					(7.06)				2.21
Loss on settled derivatives ($/Bbl)																					Loss on settled derivatives ($/Bbl)	(12.25)					(6.75)
Average realized NGL price, including derivatives ($/Bbl)	Average realized NGL price, including derivatives ($/Bbl)	$	15.87		$	8.22		93%		$	15.99			$	9.50		68%				Average realized NGL price, including derivatives ($/Bbl)	$	27.08				$	16.11				68%
Percentage of WTI, excluding derivatives	Percentage of WTI, excluding derivatives	35		%	23		%			37		%		20		%					Percentage of WTI, excluding derivatives	42		%			40		%

Total Weighted Average Realized Price:	Total Weighted Average Realized Price:																				Total Weighted Average Realized Price:
Excluding derivatives ($/Mcfe)	Excluding derivatives ($/Mcfe)	$	2.55		$	1.05		143%		$	2.58			$	1.37		88%				Excluding derivatives ($/Mcfe)	$	4.88				$	2.62				86%
Including derivatives ($/Mcfe)	Including derivatives ($/Mcfe)	$	2.20		$	1.65		33%		$	2.36			$	1.90		24%				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 ~~June 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		166	$	(0.47)
2022		261	(0.40)
2023		163	(0.53)
2024		40	(0.70)
2025		9	(0.64)
Total		639

Physical NYMEX Sales Arrangements – Natural Gas(1)
2021		132	$	(0.40)
2022	2022	129	(0.36)		2022	277	$	(0.53)
2023	2023	63	(0.36)		2023	250	(0.47)
2024	2024	27	(0.49)		2024	46	(0.71)
2025	2025	12	(0.50)		2025	9	(0.64)

Total	Total	363			Total	582

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

Total					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 ~~June 30, 2021:~~March 31, 2022:


		Remaining 2021	Full Year 2022	Full Year 2023		Remaining 2022	Full Year 2023	Full Year 2024
Natural gas (Bcf)	Natural gas (Bcf)	396	726	272	Natural gas (Bcf)	982	938	279
Oil (MBbls)	Oil (MBbls)	2,983	4,583	2,114	Oil (MBbls)	3,413	2,114	603
Ethane (MBbls)	Ethane (MBbls)	3,578	2,497	—	Ethane (MBbls)	4,142	1,308	—
Propane (MBbls)	Propane (MBbls)	4,261	4,397	—	Propane (MBbls)	4,873	1,066	—
Normal Butane (MBbls)	Normal Butane (MBbls)	1,245	1,295	—	Normal Butane (MBbls)	1,388	329	—
Natural Gasoline (MBbls)	Natural Gasoline (MBbls)	1,281	1,201	—	Natural Gasoline (MBbls)	1,497	359	—
Total financial protection on future production (Bcfe)	Total financial protection on future production (Bcfe)	476	810	285	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%

For the three months ended June 30, Increase/(Decrease) For the six months ended June 30, Increase/(Decrease)
(in millions except percentages) 2021 2020 2021 2020
Lease operating expenses (1)
$ 260 $ 182 43% $ 510 $ 376 36%
General & administrative expenses 30

29

3% 65 52 25%
Merger related expenses 3 — 100% 4 — 100%
Restructuring charges 1 2 (50)% 7 12 (42)%
Taxes, other than income taxes 27 10 170% 51 23 122%
Full cost pool amortization 94 77 22% 184 183 1%
Non-full cost pool DD&A 3 4 (25)% 7 9 (22)%
Impairments — 655 (100)% — 2,134 (100)%
Total operating costs $ 418 $ 959 (56)% $ 828 $ 2,789 (70)%

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		For the three months ended June 30,						Increase/	For the six months ended June 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)	$	0.94		$	0.91		3%	$	0.94		$	0.94		—%	Lease operating expenses (1)	$	0.94		$	0.93		1%
General & administrative expenses	General & administrative expenses	$	0.11	(2)	$	0.14	(3)	(21)%	$	0.12	(2)	$	0.13	(3)	(8)%	General & administrative expenses	$	0.09	(2)	$	0.13	(3)	(31)%
Taxes, other than income taxes	Taxes, other than income taxes	$	0.10		$	0.05		100%	$	0.09		$	0.06		50%	Taxes, other than income taxes	$	0.13		$	0.09		44%
Full cost pool amortization	Full cost pool amortization	$	0.34		$	0.38		(11)%	$	0.34		$	0.46		(26)%	Full cost pool amortization	$	0.63		$	0.33		91%

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

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(2)Excludes ~~$3 million and $4~~$25 million in ~~merger related~~merger-related expenses for the three ~~and six~~ months ended ~~June 30, 2021, respectively, and $1 million and $7~~March 31, 2022.

(3)Excludes $6 million in restructuring charges ~~for the~~and $1 million in merger-related expenses three ~~and six~~ months ended ~~June 30, 2021, respectively.~~March 31, 2021.

~~(3)Excludes $2 million and $12 million in restructuring charges for the three and six months ended June 30, 2020, respectively.~~

Lease Operating Expenses

•Lease operating expenses per Mcfe increased ~~$0.03~~$0.01 per Mcfe for the three months ended ~~June 30, 2021,~~March 31, 2022, compared to the same period in ~~2020,~~2021, primarily due to increased ~~liquids production, which includes~~costs associated with processing fees, and ~~an increase in water costs.~~

•Lease operating expenses per Mcfe remained approximately the same for the six months ended June 30, 2021, compared to the same period in 2020, as a 36% increase in production volumes, primarily associated with the Montage Merger, offset a $134 million increase in lease operating expenses.fuel and electricity.

General and Administrative Expenses

•General and administrative expenses increased ~~$1 million and $13~~$4 million for the three ~~and six~~ months ended ~~June 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 $1 million and $7 million~~charges for the three ~~and six~~ months ended ~~months ended June 30,~~March 31, 2021 ~~respectively, 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 $2 million and $12 million for the three and six months ended June 30, 2020, respectively, 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 ~~$0.05 and $0.03~~$0.04 for the three ~~and six~~ months ended ~~June 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 ~~decreased $0.04 and $0.12~~increased $0.30 per Mcfe for the three ~~and six~~ months ended ~~June 30, 2021, respectively,~~March 31, 2022, as compared to the same period in ~~2020. The average amortization rate decreased~~2021, primarily as a result of ~~the impact~~our acquisitions of ~~$2,825 million in non-cash full cost ceiling test impairments recorded in 2020.~~

•~~No impairment expense was recorded for the six months ended June 30, 2021 in relation to our recently acquired Montage~~ natural gas and oil ~~properties. 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 June 30, 2021 ofHaynesville.

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$1,130 million. Due to the improvement in commodity prices in the first half of 2021, we would not have recorded any impairment charge for the six months ended June 30, 2021 had we included our recently acquired Montage natural gas and oil properties.

•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 ~~$1,485~~$2,228 million and ~~$1,472~~$2,231 million at ~~June 30, 2021~~March 31, 2022 and at December 31, ~~2020,~~2021, respectively. The unevaluated costs excluded from amortization ~~increased~~decreased slightly as the impact of ~~$194~~$224 million of unevaluated capital invested during the period was ~~only partially~~more than offset by the evaluation of previously unevaluated properties totaling ~~$181~~$227 million.

~~Impairments~~

•During the three and six months ended June 30, 2020, we recognized non-cash full cost ceiling test impairments of $650 million and $2,129 million, respectively, primarily due to decreased commodity pricing over the prior twelve months. Additionally, for the three and six months ended June 30, 2020, we recognized a $5 million impairment related to other non-core assets. There were no impairments in the first half of 2021.

Marketing


		For the three months ended June 30,						Increase/ (Decrease)		For the six months ended June 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	$	983		$	389			153%				$	1,979				$	937		111%								Marketing revenues	$	2,755			$	996	177%
Other operating revenues	Other operating revenues	—			—			—%		1					—					100%				Other operating revenues				—					1			(100)%
Marketing purchases	Marketing purchases	969			391			148%		1,955					938					108%				Marketing purchases	2,728					986				177%
Operating costs and expenses	Operating costs and expenses	7			6			17%		12					11					9%				Operating costs and expenses	6					5				20%

Operating income (loss)		$	7		$	(8)		188%		$	13				$	(12)				208%
Operating income																								Operating income	$	21				$	6			250%

Volumes marketed (Bcfe)	Volumes marketed (Bcfe)	343			265			29%		688					528					30%				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	97		%	87		%			95		%			87		%							Percent natural gas production marketed from affiliated E&P operations	91		%			93		%
Percent oil and NGL production marketed from affiliated E&P operations		83		%	83		%			81		%			80		%
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 $15 million for the three months ended ~~June 30, 2021,~~March 31, 2022, compared to the same period in ~~2020,~~2021, primarily due to a ~~$16 million increase in the marketing margin.~~

•~~Marketing operating income increased $25 million for the six months ended June 30, 2021, compared to the same period in 2020, primarily due to a $25~~$17 million increase in the marketing margin (discussed below) which was slightly offset by lower other operating revenues and ~~a $1 million increase in natural gas storage gains recorded in the first half of 2021.~~slightly higher operating costs.

•The margin generated from marketing activities was ~~$14~~$27 million and ~~($2)~~$10 million for the three months ended ~~June 30,~~March 31, 2022 and 2021, ~~and 2020, respectively, and $24 million and ($1) million for the six months ended June 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 $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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~~Revenues~~

•Revenues from our marketing activities increased $594 million for the three months ended June 30, 2021 compared to the same period in 2020, as a 95% increase in the price received for volumes marketed and a 78 Bcfe increase in volumes marketed.

•For the six months ended June 30, 2021, revenues from our marketing activities increased $1,042 million compared to the same period in 2020, primarily due to a 62% increase in the price received for volumes marketed and a 30% increase in volumes marketed.

~~Operating Costs~~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 ~~Expenses~~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:

•~~Operating costs and expenses for the marketing segment increased $1 million and $1 million for the three and six months ended June 30, 2021, respectively, compared to the same periods in~~On November 13, 2020, ~~as a result of the increase in our share price and related mark-to-market impact~~we closed on the ~~value of~~Montage Merger, which increased our ~~share-based awards, which are accounted for as liability awards.~~footprint in West Virginia and Pennsylvania and expanded our operations into Ohio.

~~Consolidated~~

~~Interest Expense~~

For the three months ended June 30, Increase/(Decrease) For the six months ended June 30, Increase/(Decrease)
(in millions except percentages) 2021 2020 2021 2020
Gross interest expense:
Senior notes $ 43 $ 36 19% $ 87 $ 73 19%
Credit arrangements 5 4 25% 11 7 57%
Amortization of debt costs 3 3 —% 6 5 20%
Total gross interest expense 51 43 19% 104 85 22%
Less: capitalization (21) (21) —% (43) (44) (2)%
Net interest expense $ 30 $ 22 36% $ 61 $ 41 49%

•~~Interest expense related~~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 ~~senior notes increased~~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 for more information on the Mergers.

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

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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 ~~three and six months ended June 30, 2021,~~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 ~~2020,~~2021, primarily as a $998 million improvement in operating income was partially offset by a $2 million loss on the ~~interest savings from the repurchase~~early extinguishment of ~~$107 million of our outstanding senior notes during~~debt recorded in the first quarter of ~~2020 was more than offset by the interest associated with the August 2020 public offering of $350~~2022 and a $10 million ~~aggregate principal amount of our 8.375% Senior Notes due 2028.~~

•~~Capitalized interest remained approximately the same for the three months ended June 30, 2021 and decreased for the six months ended June 30, 2021, both as compared to the same periods~~increase in ~~2020, due to the evaluation of natural gas and oil properties over the past twelve months.~~

•~~Capitalized interest decreased as a percentage of gross~~ interest expense ~~for~~from the ~~three and six months ended June 30, 2021,~~first quarter of 2022 as compared to the same period in ~~2020,~~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 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.

•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 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 ~~a smaller percentage change~~gas balancing.

(2)Excludes $2 million in ~~our unevaluated~~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 ~~balance~~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 ~~larger percentage increase~~same period in 2021, due to a higher capital allocation to our ~~gross interest expense~~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 ~~same~~ period.

~~Gain (Loss)~~(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 ~~Derivatives~~

For the three months ended June 30, For the six months ended June 30,
(in millions) 2021 2020 2021 2020
Gain (loss) on unsettled derivatives $ (772) $ (229) $ (941) $ 17
Gain (loss) on settled derivatives (99) 120 (121) 213
Gain (loss) on derivatives $ (871) $ (109) $ (1,062) $ 230
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 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 for additional details about our gain (loss) on derivatives.~~Report.

~~Gain/Loss on Early Extinguishment of Debt~~

For the three and six months ended June 30, 2020, we recorded a gain on early extinguishment of debt of $7 million and $35 million, respectively, as a result of our repurchase of $27 million in aggregate principal amount of our outstanding senior notes for $20 million in the second quarter of 2020 and $107 million in aggregate principal amount of our outstanding senior

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~~notes for $72 million~~The tables below present the amount of our future natural gas production in which the ~~first half~~impact of ~~2020. See~~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 118 toof the consolidated financial statements ofincluded in this Quarterly Report for ~~more information on~~additional details about our ~~long-term debt.~~derivative instruments.

~~Income Taxes~~Operating Costs and Expenses


	For the three months ended March 31,				Increase/(Decrease)
(in millions except percentages)	2022		2021
Lease operating expenses	$	401	$	250	60%
General & administrative expenses	39		35		11%
Merger-related expenses	25		1		2,400%
Restructuring charges	—		6		(100)%
Taxes, other than income taxes	57		24		138%
Full cost pool amortization	269		90		199%
Non-full cost pool DD&A	5		4		25%

Total operating costs	$	796	$	410	94%

For the three months ended June 30, For the six months ended June 30,
(in millions except percentages) 2021 2020 2021 2020
Income tax expense $ — $ — $ — $ 406
Effective tax rate 0 % 0 % 0 % (20) %

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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

•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 and were substantially completed by the end of the first quarter of 2019, we had sustained a three-year cumulative level of profitability. Based on this factor and other positive evidence including forecasted income, we concluded that it was more likely than not that the deferred tax asset would be realized and released substantially all2021.

See Note 3 of the ~~valuation allowance. However,~~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 ~~price declines during 2020~~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 ~~write-down~~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 ~~carrying value~~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 ~~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, we 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 these deferred tax assets will not be realized and recorded a discrete tax expense~~offset by the evaluation of ~~$408~~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.

•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 ~~valuation allowance~~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 ~~first quarter~~price received for volumes marketed and a 193 Bcfe increase in the volumes marketed.

Table of 2020. The net change in valuation allowance is reflected as a component of income tax expense. We continue to have a full valuation allowance for the first half of 2021. We also continue to retain a valuation allowance of $87 million related to net operating losses in jurisdictions in which we no longer operate.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

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

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

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

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

The Indigo Merger and GEPH Merger are the result of 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 for more information on the Mergers.

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

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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.

•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 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.

•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.

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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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 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

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

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

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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.

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 ~~March~~October 2021, the banks participating in our 2018 credit facility reaffirmed our elected borrowing base and aggregate commitments to be $2.0 billion. At ~~June 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.

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 free cash flow to pay down our debt. We refer you to Note 11 to the consolidated financial statements included in this Quarterly Report and the section below under “Credit Arrangements and Financing Activities” for additional discussion of our ~~2018~~2022 credit facility and related covenant requirements.

On June 1, 2021, we entered into the Indigo Merger Agreement. Upon the close of the Indigo Merger, and pursuant to the terms of the Indigo Merger Agreement, the outstanding equity interests in Indigo will be cancelled and converted into the right to receive (i) $400 million in cash consideration, and (ii) approximately $1.6 billion in Southwestern common stock. Additionally, we will assume $700 million in aggregate principal amount of 5.375% Senior Notes due 2029 of Indigo (the “Indigo Notes”). We expect to fund the $400 million cash portion of the Indigo Merger consideration with borrowings on our credit facility. The transaction is expected to close in the second half of 2021, subject to customary closing conditions, including the approval of our shareholders. See ~~Note 2~~ ~~to the consolidated financial statements of this Quarterly Report for more information on the Indigo Merger.~~

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

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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 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 ~~March~~October 2021, the banks participating in our 2018 credit facility reaffirmed the elected borrowing base to be $2.0 billion, which also reflected our aggregate commitments. The borrowing base is subject to redetermination at least twice a year, which typically occurs in April and October, and is subject to change based primarily on drilling results, commodity prices, our future ~~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 ~~June 30, 2021,~~March 31, 2022, we had ~~$568~~$174 million of borrowings ~~outstanding~~ on our ~~revolving~~2018 credit facility and ~~$233~~$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 ~~June 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 alternative rate will be based on the prevailing market convention and is expected to be the Secured Overnight Financing Rate (or “SOFR”).

~~Because~~result of the focused work on refinancing and repayment of our debt ~~during~~in recent years, coupled with the ~~last three years, only $207 million, or 8%,~~amendment and restatement of our ~~senior notes outstanding as of June 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 July 27, 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 ~~placed~~upgraded to BB+ with stable outlook on ~~credit watch on June 2, 2021 for potential positive upgrade at the closing of the Indigo Merger)~~January 6, 2022) and ~~a long-term issuer default rating of~~ BB by Fitch Ratings (rating and stable outlook affirmed ~~and outlook upgraded to stable~~ on ~~January~~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. ~~Any reduction~~On September 1, 2021, S&P upgraded our bond rating to BB, and on January 6, 2022 S&P further upgraded our bond rating to BB+, which will have the effect of decreasing the interest rate on the 2025 Notes ~~as a result of a potential upgrade~~ to ~~the bond rating would be effective following the~~5.95%, beginning with coupon payments after January ~~2022 coupon payment.~~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 six months ended June 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	$	617	$	254	Net cash provided by operating activities	$	972	$	347
Net cash used in investing activities	Net cash used in investing activities	(492)		(470)		Net cash used in investing activities	(500)		(227)
Net cash provided by (used in) financing activities		(136)		221
Net cash used in financing activities						Net cash used in financing activities	(479)		(129)

Cash Flow from ~~Operating Activities~~Operations


		For the six months ended June 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	$	617	$	254	Net cash provided by operating activities	$	972	$	347
Add back (subtract) changes in working capital	Add back (subtract) changes in working capital	(2)		12		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	$	615	$	266	Net cash provided by operating activities, net of changes in working capital	$	836	$	347

•Net cash provided by operating activities increased ~~143%~~180%, or ~~$363~~$625 million, for the ~~six~~three months ended ~~June 30, 2021,~~March 31, 2022, compared to the same period in ~~2020,~~2021, primarily due to a ~~$656~~$1,060 million increase resulting from higher commodity prices, a ~~$200~~$308 million increase ~~associated with~~related to increased production, ~~an $18 million increase in marketing margin and~~ a ~~$14~~$136 million increased impact of working ~~capital. These increases were~~capital and a $17 million increase in our marketing margin and partially offset by a ~~$334~~$673 million decrease in our settled derivatives, a ~~$175~~$188 million increase in operating costs and expenses and a ~~$20~~$10 million increase in interest expense.

•Net cash ~~generated from~~provided by operating activities, net of changes in working capital, ~~provided 117% of~~exceeded our cash requirements for capital investments for the ~~six~~three months ended ~~June 30, 2021, compared to providing 55% 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 2021.

Cash Flow from Investing Activities

•Total E&P capital investments increased ~~$43~~$278 million for the ~~six~~three months ended ~~June 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 ~~$37~~$28 million ~~increase~~decrease in ~~direct E&P~~our Appalachia investment due to higher capital ~~investments and a $6 million increase in capitalized interest and internal costs, as compared~~allocation to ~~the same period in 2020.~~our recently acquired Haynesville assets.


		For the six months ended June 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	$	493	$	472	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	29		8		Changes in capital accruals	43		38
Other (1)	Other (1)	3		2		Other (1)	1		1
Total capital investment		$	525	$	482
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 June 30, Increase/(Decrease) For the six months ended June 30, Increase/(Decrease)
(in millions except percentages) 2021 2020 2021 2020
E&P capital investment $ 259 $ 245 6% $ 525 $ 482 9%
Other capital investment (1)
— — —% — — —%
Total capital investment $ 259 $ 245 6% $ 525 $ 482 9%


	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 six~~ months ended ~~June 30, 2021~~March 31, 2022 and ~~2020.~~2021.

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		For the three months ended June 30,				For the six months ended June 30,				For the three months ended March 31,
(in millions)	(in millions)	2021		2020		2021		2020			(in millions)	2022		2021
E&P Capital Investments by Type:	E&P Capital Investments by Type:										E&P Capital Investments by Type:
Exploratory and development drilling, including workovers		$	204	$	197	$	419	$	387
Development and exploration, including workovers											Development and exploration, including workovers	$	460	$	215
Acquisition of properties	Acquisition of properties	12		8		22		14			Acquisition of properties	26		10

Water infrastructure		2		2		2		3

Other	Other	3		5		7		9			Other	4		4
Capitalized interest and expenses	Capitalized interest and expenses	38		33		75		69			Capitalized interest and expenses	54		37
Total E&P capital investments	Total E&P capital investments	$	259	$	245	$	525	$	482		Total E&P capital investments	$	544	$	266

E&P Capital Investments by Area:	E&P Capital Investments by Area:										E&P Capital Investments by Area:
Northeast Appalachia		$	85	$	115	$	165	$	201
Southwest Appalachia		169		123		352		269
Appalachia											Appalachia	$	235	$	263
Haynesville (1)											Haynesville (1)	306		—
Other E&P ~~(1)~~	Other E&P ~~(1)~~	5		7		8		12			Other E&P ~~(1)~~	3		3
Total E&P capital investments	Total E&P capital investments	$	259	$	245	$	525	$	482		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 June 30,		For the six months ended June 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	23	30	46	68	Drilled	33	23
Completed	Completed	19	31	48	53	Completed	37	29
Wells to sales	Wells to sales	31	31	48	43	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.

Cash Flow from Financing Activities

•For the ~~six~~three months ended ~~June 30, 2021,~~March 31, 2022, we fully redeemed our 4.10% Senior Notes for $201 million and paid down ~~$132~~additional aggregate principal balances on our senior notes of $20 million and paid down $286 million on our ~~revolving~~2018 credit facility.

•In the first ~~half~~three months of ~~2020,~~2021, we ~~had net borrowings of $302~~paid down $133 million ~~from~~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 ~~$1,351~~$4,432 million at ~~June 30, 2021,~~March 31, 2022, a ~~$1,010~~$2,793 million decrease from December 31, ~~2020, as~~2021, and mostly attributable to a ~~$40 million increase in accounts receivable was more than offset by a $765~~$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 the reclassification~~a reduction in accounts receivable of ~~long-term debt to short-term debt of $207~~$89 million, ~~related to our 2022 senior notes, a $68 million~~and an increase in our accounts payable of $206 million which was partially offset by the full repayment of our 4.10% Senior Notes of $201 million and decreases to various payables ~~and an $11~~of $48 million, ~~decrease in cash and cash equivalents,~~ 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, as well as our funding requirements associated with the Indigo Merger.~~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 ~~June 30, 2021,~~March 31, 2022, our material off-balance sheet arrangements and transactions include operating service arrangements and ~~$233~~$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 of our operating leases.~~more information.

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Contractual Obligations and Contingent Liabilities and Commitments

We have various contractual obligations in the normal course of our operations and financing activities. Other than the firm transportation and gathering agreements discussed below, there have been no material changes to our contractual obligations from those disclosed in our ~~2020~~2021 Annual Report.

Contingent Liabilities and Commitments

As of ~~June 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 ~~$8.3~~$10.2 billion, ~~$369~~$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 ~~$895~~$877 million. As of ~~June 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	$	7,965	$	713	$	1,557	$	1,317	$	1,744	$	2,634	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)	369		2		18		25		52		272		Pending regulatory approval and/or construction (1)	857		3		124		161		247		322
Total transportation charges	Total transportation charges	$	8,334	$	715	$	1,575	$	1,342	$	1,796	$	2,906	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 ~~June 30, 2021.~~March 31, 2022.

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 March 31, 2022, up to approximately $34 million of these contractual commitments remain (included in the table above), and we have recorded a $17 million liability for the estimated future payments.

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

Substantially 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 ~~its~~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, 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 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.

For the ~~six~~three months ended ~~June 30, 2021,~~March 31, 2022, we have ~~contributed $9 million~~not made contributions to the pension and postretirement benefit plans, and we do not expect to contribute an additional ~~$3 million~~funds to our pension plan during the remainder of ~~2021.~~2022. We recognized liabilities of ~~$35 million and $46~~$25 million as of ~~June 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,

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by acceleration, by call for redemption or otherwise, together with interest on the overdue principal, if any, and interest on any overdue interest, to the extent lawful, and all other obligations of the Company to the holders of the senior notes.

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

Critical Accounting Policies and Estimates

There have been no material changes to our critical accounting policies and estimates as compared to the critical accounting policies and estimates described in our 2021 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 ~~June 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 ~~June 30, 2021,~~March 31, 2022, we had approximately ~~$2,471~~$4,209 million ~~principal amount~~ of outstanding senior notes with a weighted average interest rate of ~~7.02% and $568~~5.74%, $549 million of borrowings under our ~~revolving~~Term Loan and $174 million of borrowings under our 2018 credit facility. ~~At June 30, 2021,~~As of 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,~~On September 1, 2021 S&P ~~downgraded~~upgraded our bond rating to ~~BB-~~BB, and on January 6, 2022, S&P further upgraded our bond rating to BB+, which ~~had the effect of increasing~~decreased 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 June 2, 2021 in conjunction with the announcement of the Indigo Merger, S&P placed our bond rating on credit watch for a potential positive upgrade. Interest savings on the 2025 ~~Notes from any potential upgrade would be realized for~~notes to 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)	$	207		$	—		$	—		$	856		$	618		$	790		$	2,471		Fixed rate payments (1)	$	—		$	—		$	—		$	389		$	—		$	3,820		$	4,209
Weighted average interest rate	Weighted average interest rate	4.10		%	—		%	—		%	6.45		%	7.50		%	8.03		%	7.02		%	Weighted average interest rate	—		%	—		%	—		%	5.95		%	—		%	5.72		%	5.74		%

Variable rate payments (1)	Variable rate payments (1)	$	—		$	—		$	568		$	—		$	—		$	—		$	568		Variable rate payments (1)	$	4		$	6		$	179		$	6		$	5		$	523		$	723
Weighted average interest rate	Weighted average interest rate	—		%	—		%	2.10		%	—		%	—		%	—		%	2.10		%	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

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production that is financially protected. Credit risk relates to the risk of loss as a result of non-performance by our counterparties. The counterparties are primarily major banks and integrated energy companies that management believes present minimal credit risks. The credit quality of each counterparty and the level of financial exposure we have to each counterparty are closely monitored to limit our credit risk exposure. Additionally, we perform both quantitative and qualitative assessments of these counterparties based on their credit ratings and credit default swap rates where applicable. We have not incurred any counterparty losses related to non-performance and do not anticipate any losses given the information we have currently. However, we cannot be certain that we will not experience such losses in the future. The fair value of our derivative assets and liabilities includes a non-performance risk factor. We refer you to Note 8 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, ~~(Interim),~~ 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, ~~(Interim),~~ 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, ~~(Interim),~~ concluded that our disclosure controls and procedures were effective as of ~~June 30, 2021~~March 31, 2022 at a reasonable assurance level.

Changes in Internal Control over Financial Reporting

~~There~~On December 31, 2021, the Company completed its acquisition of GEP Haynesville, LLC. As part of the ongoing integration of the acquired business, we are in the process of incorporating the controls and related procedures of GEPH. Other than incorporating the GEPH controls, 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 ~~June 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.~~

~~Risk Factors Relating to the Indigo Merger~~

~~There can be no assurances when or if the Indigo Merger will be completed.~~

Although SWN expects to complete the Indigo Merger by the end of the fourth quarter of 2021, there can be no assurances as to the exact timing of completion of the Indigo Merger or that the Indigo Merger will be completed at all. The completion of the Indigo Merger is subject to numerous conditions, including, among others:

•~~the absence of any law, order or injunction prohibiting the Indigo Merger;~~

•~~the expiration or earlier termination of the waiting period under the HSR Act;~~

•~~the accuracy of each party’s representations and warranties;~~

•~~each party’s compliance with its covenants and agreements contained in the Indigo Merger Agreement; and~~

•~~approval of the Stock Issuance Proposal.~~

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There can be no assurance that the conditions required to complete the Indigo Merger, some of which are beyond the control of SWN and Indigo, will be satisfied or waived on the anticipated schedule, or at all.

Additionally, the Indigo Merger Agreement also provides for certain termination rights for both SWN and Indigo, including if the Indigo Merger is not consummated on or before November 29, 2021. Upon termination of the Indigo Merger Agreement under certain circumstances, including (a) termination by Indigo in the event of a change of recommendation by the Board, or (b) if an alternative transaction is publicly proposed or publicly disclosed and not withdrawn prior to the Special Meeting and the Indigo Merger Agreement is terminated (i) by SWN or Indigo due to either the failure of SWN shareholders to approve the Stock Issuance Proposal or the failure of the Indigo Merger to close on or before November 29, 2021, or (ii) by Indigo due to a breach by SWN and, in any such case, within 12 months after such termination SWN enters into a definitive agreement with respect to, or otherwise consummates, an alternative transaction, SWN will be obligated to pay Indigo a fee of $81 million.

~~Obtaining required approvals and satisfying closing conditions may prevent or delay completion of the Indigo Merger.~~

The Indigo Merger is subject to a number of conditions to closing as specified in the Indigo Merger Agreement. These closing conditions include, among others, obtaining shareholder approval of the Stock Issuance Proposal, approval for listing on the NYSE of the shares of common stock issuable in accordance with the Indigo Merger Agreement, the absence of governmental restraints or prohibitions preventing the consummation of the Indigo Merger. The obligation of each of SWN and Indigo to consummate the Indigo Merger is also conditioned on, among other things, (i) the accuracy of the representations and warranties as set forth by the other party in the Indigo Merger Agreement, (ii) the performance by the other party, in all material respects, of its obligations under the Indigo Merger Agreement required to be performed at or prior to the effective time of the Indigo Merger and (iii) the delivery by the other party of a certificate of an authorized officer certifying that the required conditions have been satisfied. The required shareholder consents and approvals may not be obtained and the required conditions to closing may not be satisfied, and, if all required consents and approvals are obtained and the conditions are satisfied, no assurance can be given as to the terms, conditions and timing of such consents and approvals. Any delay in completing the Indigo Merger could cause SWN and Indigo not to realize, or to be delayed in realizing, some or all of the benefits that SWN and Indigo expect to achieve if the Indigo Merger is successfully completed within its expected time frame.

The market price for shares of common stock following the completion of the Indigo Merger may be affected by factors different from, or in addition to, those that historically have affected or currently affect the market prices of shares of common stock.

SWN’s businesses differ in some regards from those of Indigo and, accordingly, the results of operations of SWN following completion of the Indigo Merger will be affected by some factors that are different from those currently or historically affecting the results of operations of SWN. The results of operations of SWN following completion of the Indigo Merger may also be affected by factors different from those that currently affect or have historically affected SWN. In addition, following completion of the Indigo Merger, SWN may seek to raise additional equity financing through one or more underwritten offerings, private placements and/or rights offerings, or issue stock in connection with acquisitions, which may result in downward pressure on the share price of the common stock.

~~SWN may be adversely affected by negative publicity related to the proposed Indigo Merger and in connection with other matters.~~

From time to time, political and public sentiment in connection with the proposed Indigo Merger and in connection with other matters could result in a significant amount of adverse press coverage and other adverse public statements affecting SWN. Adverse press coverage and other adverse statements, whether or not driven by political or public sentiment, may also result in investigations by regulators, legislators and law enforcement officials or in legal claims. Responding to these investigations and lawsuits, regardless of the ultimate outcome of the proceeding, can divert the time and effort of senior management from the management of SWN’s and Indigo’s respective businesses. Addressing any adverse publicity, governmental scrutiny or enforcement or other legal proceedings is time consuming and expensive and, regardless of the factual basis for the assertions being made, can have a negative impact on the reputation of SWN and Indigo, on the morale and performance of their employees and on their relationships with their respective regulators. It may also have a negative impact on their ability to take timely advantage of various business and market opportunities. The direct and indirect effects of negative publicity, and the demands of responding to and addressing it, may have a material adverse effect on SWN’s and Indigo’s respective businesses, financial condition, results of operations and cash flows.

The Indigo Merger is subject to conditions, including certain conditions that may not be satisfied or completed on a timely basis or at all. Failure to complete the Indigo Merger could have material and adverse effects on SWN.

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Completion of the Indigo Merger is subject to a number of conditions, including, among other things, obtaining the approval of the Stock Issuance Proposal and the expiration of the applicable waiting period under the HSR Act. Such conditions, some of which are beyond SWN’s control, may not be satisfied or waived in a timely manner or at all and therefore make the completion and timing of the completion of the Indigo Merger uncertain. In addition, the Indigo Merger Agreement contains certain termination rights for both SWN and Indigo, which if exercised, will also result in the Indigo Merger not being consummated. Furthermore, the governmental authorities from which the regulatory approvals are required may impose conditions on the completion of the Indigo Merger or require changes to the terms thereof. Such conditions or changes and the process of obtaining regulatory approvals could have the effect of delaying or impeding consummation of the transactions or of imposing additional costs or limitations on SWN or Indigo following completion of the Indigo Merger, any of which might have an adverse effect on SWN following completion of the Indigo Merger.

If the Indigo Merger is not completed, SWN’s ongoing business may be adversely affected and, without realizing any of the benefits of having completed the Indigo Merger, SWN will be subject to a number of risks, including the following:

• ~~SWN will be required to pay its costs relating to the Indigo Merger, such as legal, accounting and financial advisory, whether or not the Indigo Merger is completed;~~

•~~time and resources committed by SWN’s management to matters relating to the Indigo Merger could otherwise have been devoted to pursuing other beneficial opportunities; and~~

•~~the market price of the common stock could decline to the extent that the current market price reflects a market assumption that the Indigo Merger will be completed.~~

In addition to the above risks, if the Indigo Merger Agreement is terminated and the Board seeks another acquisition, SWN’s shareholders cannot be certain that SWN will be able to find a party willing to enter into a transaction as attractive to SWN as Indigo. Also, if the Indigo Merger Agreement is terminated under certain specified circumstances, SWN may be required to pay Indigo a termination fee of $81 million or reimburse certain of Indigo’s expenses.

~~SWN may waive one or more of the closing conditions without re-soliciting shareholder approval.~~

SWN may determine to waive, in whole or part, one or more of the conditions to closing the Indigo Merger prior to SWN being obligated to consummate the Indigo Merger. SWN currently expects to evaluate the materiality of any waiver and its effect on SWN shareholders in light of the facts and circumstances at the time, to determine whether any amendment of the proxy statement or any re-solicitation of proxies is required in light of such waiver. Any determination whether to waive any condition to the Indigo Merger or to re-solicit shareholder approval or amending or supplementing the proxy statement as a result of a waiver will be made by SWN at the time of such waiver based on the facts and circumstances as they exist at that time.

~~SWN and Indigo will be subject to business uncertainties while the Indigo Merger is pending, which could adversely affect SWN’s business.~~

In connection with the pendency of the Indigo Merger, it is possible that certain persons with whom SWN or Indigo have a business relationship may delay or defer certain business decisions or might decide to seek to terminate, change or renegotiate their relationships with SWN or Indigo, as the case may be, as a result of the Indigo Merger, which could negatively affect SWN’s or Indigo’s revenues, earnings and cash flows as well as the market price of the common stock, regardless of whether the Indigo Merger is completed. Also, SWN’s and Indigo’s ability to attract, retain and motivate employees may be impaired until the Indigo Merger is completed, and SWN’s ability to do so may be impaired for a period of time thereafter, as current and prospective employees may experience uncertainty about their roles within the combined company following the Indigo Merger.

Under the terms of the Indigo Merger Agreement, SWN and Indigo are subject to certain restrictions on the conduct of business prior to the consummation of the Indigo Merger, which may adversely affect SWN’s and Indigo’s ability to execute certain of SWN’s and Indigo’s business strategies, including the ability in certain cases to modify or enter into certain contracts, acquire or dispose of certain assets, incur or prepay certain indebtedness, incur encumbrances, make capital expenditures or settle claims. Such limitations could negatively affect SWN’s and Indigo’s businesses and operations prior to the completion of the Indigo Merger.

~~SWN will incur significant transaction costs in connection with the Indigo Merger.~~

SWN has incurred and is expected to continue to incur a number of non-recurring costs associated with the Indigo Merger, combining the operations of Indigo with SWN’s and achieving desired synergies. These costs have been, and will continue to

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be, substantial and, in many cases, will be borne by SWN whether or not the Indigo Merger is completed. A substantial majority of non-recurring expenses will consist of transaction costs and include, among others, fees paid to financial, legal, accounting and other advisors and employee retention, severance, and benefit costs. SWN will also incur costs related to formulating and implementing integration plans. Although SWN expects that the elimination of duplicative costs, as well as the realization of synergies and efficiencies related to the integration of the assets and operations of Indigo, should allow SWN to offset these transaction costs over time, this net benefit may not be achieved in the near term or at all.

Moreover, if the Indigo Merger is not completed, SWN will have incurred substantial expenses for which no ultimate benefit will have been received. SWN has incurred out-of-pocket expenses in connection with the Indigo Merger for investment banking, legal and accounting fees and financial printing and other costs and expenses, much of which will be incurred even if the Indigo Merger is not completed.

~~Termination of the Indigo Merger Agreement or failure to otherwise complete the Indigo Merger could negatively impact SWN’s business and financial results.~~

~~Termination of the Indigo Merger Agreement or any failure to otherwise complete the Indigo Merger may result in various consequences, including:~~

•SWN’s business may have been adversely impacted by the failure to pursue other beneficial opportunities due to the focus of management on the Indigo Merger, without realizing any of the anticipated benefits of completing the Indigo Merger;

•~~in certain instances, payment by SWN of a termination fee or reimbursement of certain expenses to Indigo;~~

•under certain circumstances, the Indigo Merger Agreement requires that SWN advance, or pay to Indigo the amount of loss in respect of, certain hedge contracts entered into by Indigo subsequent to the execution of the Indigo Merger Agreement; and

•negative reactions from the financial markets and customers may occur if the anticipated benefits of the Indigo Merger are not able to be realized. Such anticipated benefits may include, among others, operational efficiencies, cost savings, and synergies.

If the Indigo Merger is not consummated, SWN cannot assure you that the risks described above will not negatively impact the business, financial results, and ability to repay its outstanding indebtedness.

Until the completion of the Indigo Merger or the termination of the Indigo Merger Agreement in accordance with its terms, SWN and Indigo are each prohibited from entering into certain transactions and taking certain actions that might otherwise be beneficial to SWN or Indigo and their respective shareholders.

From and after the date of the Indigo Merger Agreement and prior to completion of the Indigo Merger, the Indigo Merger Agreement restricts SWN and Indigo from taking specified actions without the consent of the other party and generally requires that the business of each company and its respective subsidiaries be conducted in all material respects in the ordinary course of business consistent with past practice. These restrictions may prevent SWN or Indigo from making appropriate changes to their respective businesses or organizational structures or from pursuing attractive business opportunities that may arise prior to the completion of the Indigo Merger, and could have the effect of delaying or preventing other strategic transactions. Adverse effects arising from the pendency of the Indigo Merger could be exacerbated by any delays in consummation of the Indigo Merger or termination of the Indigo Merger Agreement.

~~The announcement and pendency of the Indigo Merger could have an adverse effect on SWN’s and/or Indigo’s business, financial condition, results of operations or business prospects.~~

~~The announcement and pendency of the Indigo Merger could disrupt SWN’s and/or Indigo’s businesses in the following ways, among others:~~

•SWN’s and/or Indigo’s employees may experience uncertainty regarding their future roles in the combined company, which might adversely affect SWN’s and/or Indigo’s ability to retain, recruit and motivate key personnel;

•the attention of SWN’s and/or Indigo’s management may be directed toward the completion of the Indigo Mergers and other transaction-related considerations and may be diverted from the day-to-day business operations of SWN and/or Indigo, as applicable, and matters related to the Indigo Mergers may require commitments of time and resources that

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~~could otherwise have been devoted to other opportunities that might have been beneficial to SWN and/or Indigo, as applicable; and~~

•customers, suppliers and other third parties with business relationships with SWN and/or Indigo may decide not to renew or may decide to seek to terminate, change and/or renegotiate their relationships with SWN and/or Indigo as a result of the Indigo Merger, whether pursuant to the terms of their existing agreements with SWN and/or Indigo or otherwise.

~~Any of these matters could adversely affect the businesses of, or harm the financial condition, results of operations or business prospects of, SWN and/or Indigo.~~

Securities class action and derivative lawsuits may be brought against SWN in connection with the Indigo Merger, which could result in substantial costs and may delay or prevent the Indigo Merger from being completed.

Securities class action lawsuits and derivative lawsuits are often brought against public companies that have entered into acquisition, merger or other business combination agreements that could prevent or delay the completion of the Indigo Merger and result in significant costs to SWN, including any costs associated with the indemnification of directors and officers. Even if such a lawsuit is without merit, defending against these claims can result in substantial costs and divert management time and resources. An adverse judgment could result in monetary damages, which could have a negative impact on SWN’s liquidity and financial condition.

Lawsuits that may be brought against SWN, Indigo or SWN’s or Indigo’s directors could also seek, among other things, injunctive relief or other equitable relief, including a request to enjoin SWN from consummating the Indigo Merger. One of the conditions to the closing of the Indigo Merger is that no injunction by any court or other tribunal of competent jurisdiction has been entered and continues to be in effect and no law has been adopted or is effective, in either case that prohibits or makes illegal the closing of the Indigo Merger. Consequently, if a plaintiff is successful in obtaining an injunction prohibiting completion of the Indigo Merger, that injunction may delay or prevent the Indigo Merger from being completed within the expected timeframe or at all, which may adversely affect SWN’s business, financial position and results of operation.

The combined company may record goodwill and other intangible assets that could become impaired and result in material non-cash charges to the results of operations of the combined company in the future.

SWN will account for the Indigo Merger as an acquisition of a business in accordance with GAAP. Under the acquisition method of accounting, the assets and liabilities of Indigo and its subsidiaries will be recorded, as of completion, at their respective fair values and added to SWN’s. SWN’s reported financial condition and results of operations for periods after completion of the Indigo Merger will reflect Indigo’s balances and results after completion of the Indigo Merger but will not be restated retroactively to reflect the historical financial position or results of operations of Indigo and its subsidiaries for periods prior to the Indigo Merger.

Under the acquisition method of accounting, the total purchase price will be allocated to Indigo’s tangible assets and liabilities and identifiable intangible assets based on their fair values as of the date of completion of the Indigo Merger. The excess of the purchase price over those fair values, if any, will be recorded as goodwill. To the extent the value of goodwill or intangibles, if any, becomes impaired in the future, the combined company may be required to incur material non-cash charges relating to such impairment. The combined company’s operating results may be significantly impacted from both the impairment and the underlying trends in the business that triggered the impairment.

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

~~If the Indigo Merger is consummated, 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;~~

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

•~~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.

~~SWN’s results may suffer if it does not effectively manage its expanded operations following the Indigo Merger.~~

Following completion of the Indigo Merger, the size of the Company’s business will increase significantly beyond its current size. SWN’s future success will depend, in part, on SWN’s ability to manage this expanded business, which poses numerous risks and uncertainties, including the need to integrate the operations and business of Indigo into SWN’s existing business in an efficient and timely manner, to combine systems and management controls and to integrate relationships with customers, vendors and business partners.

~~SWN’s current shareholders will have a reduced ownership and voting interest after the Indigo Merger compared to their current ownership and will exercise less influence over management.~~

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Based on the number of outstanding shares of common stock as of July 27, 2021, immediately after the Indigo Merger is completed, it is expected that, on a fully diluted basis, SWN’s current shareholders will collectively own approximately 67% and the former Indigo shareholders will own, in the aggregate, approximately 33% of the outstanding shares of common stock (assuming no adjustments are made pursuant to the Indigo Merger Agreement). As a result of the Indigo Merger, SWN’s current shareholders will own a smaller percentage of SWN than they currently own, and as a result will have less influence on SWN’s management and policies.

~~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 are issued to the Indigo Holders in the Indigo Merger will become freely tradable once registered pursuant to the registration rights agreement to be 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 Indigo Holder who is a party to the Registration Rights Agreement will be registered for resale. Once registered, the common stock held by such Indigo Holders will be unrestricted and will 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 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 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 the Indigo Merger is completed and SWN’s shareholders, including the Indigo Holders, sell substantial amounts of common stock in the public market following the closing of the Indigo Merger, 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;~~

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•~~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;~~

•~~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 hedges natural gas from time to time, primarily through the use of certain derivative commodity instruments. SWN will bear the economic impact of all of Indigo’s current hedges following the completion 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.

SWN’s ability to utilize its U.S. net operating loss carryforwards to reduce future taxable income following the consummation of the Indigo Merger will be subject to various limitations under the United States Internal Revenue Code of 1986, as amended (the “Code”).

Section 382 of the Code imposes a limitation on the ability of a corporation to utilize its net operating loss carryforwards (“NOLs”) upon the occurrence of an ownership change resulting from issuances of a corporation’s stock or the sale or exchange of such corporation’s stock by certain shareholders if, as a result, there is an aggregate change of more than 50% in the beneficial ownership of such corporation’s stock by such shareholders during any three-year period. SWN believes that the Indigo Merger, if consummated, will result in an ownership change with respect to SWN, which would trigger a limitation on SWN’s ability to utilize any of its historic loss carryforwards following the consummation of the Indigo Merger, based on information currently available. The limitation with respect to such loss carryforwards generally would be equal to (i) the fair market value of SWN’s equity as of immediately prior to such ownership change multiplied by (ii) a percentage approximately

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equivalent to the yield on long-term tax-exempt bonds during the month in which the ownership change occurs. In addition, the limitation would, under current law, be increased if there are recognized built-in gains during any post-change year, but only to the extent of any net unrealized built-in gains in SWN’s assets at the time of the ownership change. Any such limitation imposed on the ability to use such NOLs to offset future taxable income could cause the Company to pay U.S. federal income taxes earlier than it otherwise would if such limitations were not in effect and could cause certain of such NOLs to expire unused, thereby reducing or eliminating the benefit of such NOLs.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).
(4.1)			Sixth Supplemental Indenture, dated as of January 4, 2022, among Southwestern Energy Company, the guarantors party thereto and The Bank of New York Mellon Trust, N.A., as trustee (Incorporated by reference to Exhibit 4.1 to the Registrant’s Current Report on Form 8-K filed on January 5, 2022).
(4.2)			Eighth Supplemental Indenture, dated as of January 4, 2022, among Southwestern Energy Company, the guarantors party thereto and Regions Bank, as trustee (Incorporated by reference to Exhibit 4.2 to the Registrant’s Current Report on Form 8-K filed on January 5, 2022).
(4.3)			Eighth Supplemental Indenture, dated as of January 4, 2022, among Southwestern Energy Company, the guarantors party thereto and U.S. Bank National Association, as trustee (Incorporated by reference to Exhibit 4.3 to the Registrant’s Current Report on Form 8-K filed on January 5, 2022).
(4.4)			Fifth Supplemental Indenture, dated as of January 4, 2022, among Southwestern Energy Company, the guarantors party thereto and Regions Bank, as trustee (Incorporated by reference to Exhibit 4.4 to the Registrant’s Current Report on Form 8-K filed on January 5, 2022).
(10.1)			~~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:	~~July 29, 2021~~April 28, 2022	/s/ CARL F. GIESLER, JR.
		Carl F. Giesler, Jr. Executive Vice President and Chief Financial Officer

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	Pro forma results
(in millions, except per share amounts)	For the three months ended June 30, 2020		For the six months ended June 30, 2020
Revenues	$	501	$	1,226
Loss from continuing operations	$	(925)	$	(2,415)


	For the three months ended June 30,				For the six months ended June 30,
(in millions)	2021		2020		2021		2020
Northeast Appalachia	$	230	$	117	$	493	$	312
Southwest Appalachia	474		94		915		243
Other	0		0		1		0
Total	$	704	$	211	$	1,409	$	555


	June 30, 2021		June 30, 2020
Natural gas (per MMBtu)	$	2.43	$	2.07
Oil (per Bbl)	$	49.78	$	47.17
NGLs (per Bbl)	$	17.06	$	8.87


	Three months ended June 30,
(in millions except percentages)	Natural Gas			Oil			NGLs			Total
2020 sales revenues	$	155		$	16		$	40		$	211
Changes associated with prices	206			77			128			411
Changes associated with production volumes	60			12			10			82
2021 sales revenues	$	421		$	105		$	178		$	704
Increase from 2020	172		%	556		%	345		%	234		%