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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q

(Mark One)

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

Exchange Act of 1934

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

☐ 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, smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer”, “accelerated filer”, “smaller reporting company” and “emerging growth company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer

☒

Accelerated filer

☐

Non-accelerated filer

☐

Smaller reporting company

☐

Emerging growth company

☐

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

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

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


Class						Outstanding as of ~~April 27,~~November 1, 2021
Common Stock, Par Value $0.01						~~676,850,759~~1,014,978,197

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SOUTHWESTERN ENERGY COMPANY

INDEX TO FORM 10-Q

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


PART I – FINANCIAL INFORMATION			Page

Item 1.	Financial Statements		3
	Consolidated Statements of Operations		3
	Consolidated Statements of Comprehensive Income (Loss)		4
	Consolidated Balance Sheets		5
	Consolidated Statements of Cash Flows		6
	Consolidated Statements of Changes in Equity		7
	Notes to Consolidated Financial Statements		89
		Note 1. Basis of Presentation	89
		Note 2. Acquisition	89
		Note 3. Restructuring Charges	1013
		Note 4. Revenue Recognition	1113
		Note 5. Cash and Cash Equivalents	1215
		Note 6. Natural Gas and Oil Properties	1215
		Note 7. Earnings per Share	1316
		Note 8. Derivatives and Risk Management	1417
		Note 9. Reclassifications From Accumulated Other Comprehensive Income (Loss)	2225
		Note 10. Fair Value Measurements	2226
		Note 11. Debt	2429
		Note 1 2 . Commitments and Contingencies	2731
		Note 1 3 . Income Taxes	2833
		Note 1 4 . Pension Plan and Other Postretirement Benefits	2834
		Note 15. Long-Term Incentive Compensation	2935
		Note 1 6 . Segment Information	3239
		Note 1 7 . New Accounting Pronouncements	3341
		Note 18. Subsequent Events	41
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		3341
	Results of Operations		3644
	Liquidity and Capital Resources		4353
Item 3.	Quantitative and Qualitative Disclosures About Market Risk		4758
Item 4.	Controls and Procedures		4859

PART II – OTHER INFORMATION

Item 1.	Legal Proceedings		4959
Item 1A.	Risk Factors		4959
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds		4962
Item 3.	Defaults Upon Senior Securities		4962
Item 4.	Mine Safety Disclosures		4962
Item 5.	Other Information		4962
Item 6.	Exhibits		4962

CAUTIONARY STATEMENT ABOUT FORWARD-LOOKING STATEMENTS

All statements, other than historical fact or present financial information, 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 that address activities, outcomes and other matters that should or may occur in the future, including, without limitation, statements regarding the financial position, business strategy, production and reserve growth and other plans and objectives for our future operations, are forward-looking statements. Although we believe the expectations expressed in such forward-looking statements are based on reasonable assumptions, such statements

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are not guarantees of future performance. We have no obligation and make no undertaking to publicly update or revise any forward-looking statements, except as may be required by law.

Forward-looking statements include the items identified in the preceding paragraph, information concerning possible or assumed future results of operations and other statements in this Quarterly Report on Form 10-Q (this “Quarterly Report”) identified by words such as “anticipate,” “intend,” “plan,” “project,” “estimate,” “continue,” “potential,” “should,” “could,” “may,” “will,” “objective,” “guidance,” “outlook,” “effort,” “expect,” “believe,” “predict,” “budget,” “projection,” “goal,” “forecast,” “model,” “target” or similar words.

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. In addition to any assumptions and other factors referred to specifically in connection with forward-looking statements, risks, uncertainties and factors that could cause our actual results to differ materially from those indicated in any forward-looking statement include, but are not limited to:

•the timing and extent of changes in market conditions and prices for natural gas, oil and natural gas liquids (“NGLs”), including regional basis differentials and the impact of reduced demand for our production and products in which our production is a component due to governmental and societal actions taken in response to the COVID-19 pandemic;

•our ability to fund our planned capital investments;

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

•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;

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

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

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

•our ability to realize the expected benefits from acquisitions, including the Indigo Merger ~~(as defined~~(discussed below);

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

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

•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, 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;

•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; 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.

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

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PART I – FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

SOUTHWESTERN ENERGY COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)

For the three months ended March 31,
(in millions, except share/per share amounts) 2021 2020
Operating Revenues:
Gas sales $ 464 $ 248
Oil sales 81 52
NGL sales 173 50
Marketing 352 239
Other 2 3
1,072 592
Operating Costs and Expenses:
Marketing purchases 356 248
Operating expenses 250 193
General and administrative expenses 38 26
Montage merger-related expenses 1 0
Restructuring charges 6 10
Depreciation, depletion and amortization 96 113
Impairments 0 1,479
Taxes, other than income taxes 24 13
771 2,082
Operating Income (Loss) 301 (1,490)
Interest Expense:
Interest on debt 50 40
Other interest charges 3 2
Interest capitalized (22) (23)
31 19
Gain (Loss) on Derivatives (191) 339
Gain on Early Extinguishment of Debt 0 28
Other Income, Net 1 1
Income (Loss) Before Income Taxes 80 (1,141)
Provision (Benefit) for Income Taxes:
Current 0 (2)
Deferred 0 408
0 406
Net Income (Loss) $ 80 $ (1,547)
Earnings (Loss) Per Common Share:
Basic $ 0.12 $ (2.86)
Diluted $ 0.12 $ (2.86)
Weighted Average Common Shares Outstanding:
Basic 675,385,145 540,308,491
Diluted 679,867,825 540,308,491


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

Depreciation, depletion and amortization	138		70		334		267
Impairments	6		361		6		2,495
Taxes, other than income taxes	35		15		86		38
	962		908		2,490		4,156
Operating Income (Loss)	636		(381)		1,230		(2,627)
Interest Expense:
Interest on debt	56		43		154		123
Other interest charges	3		2		9		7
Interest capitalized	(25)		(23)		(68)		(67)
	34		22		95		63

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

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


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

Weighted Average Common Shares Outstanding:
Basic	787,032,414		571,872,413		713,455,662		551,162,559
Diluted	787,032,414		571,872,413		713,455,662		551,162,559

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

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SOUTHWESTERN ENERGY COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(Unaudited)

For the three months ended March 31,
(in millions) 2021 2020
Net income (loss) $ 80 $ (1,547)
Change in value of pension and other postretirement liabilities:
Amortization of prior service cost and net loss included in net periodic pension cost (1)
0 0
Comprehensive income (loss) $ 80 $ (1,547)


	For the three months ended September 30,				For the nine months ended September 30,
(in millions)	2021		2020		2021		2020
Net loss	$	(1,857)	$	(593)	$	(2,386)	$	(3,020)

Change in value of pension and other postretirement liabilities:
Settlement adjustment (1)	1		1		4		1

Comprehensive loss	$	(1,856)	$	(592)	$	(2,382)	$	(3,019)

(1)~~The amortization of prior service costs and net loss along with corresponding tax~~Tax benefits for the three months ended ~~March 31,~~September 30, 2021 and ~~March 31,~~ 2020 were immaterial.

Net of $1 million in taxes for the nine months ended September 30, 2021 and 2020, respectively.

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

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SOUTHWESTERN ENERGY COMPANY AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(Unaudited)

March 31, 2021 December 31, 2020
ASSETS (in millions)
Current assets:
Cash and cash equivalents $ 4 $ 13
Accounts receivable, net 400 368
Derivative assets 157 241
Other current assets 41 49
Total current assets 602 671
Natural gas and oil properties, using the full cost method, including $1,488 million as of March 31, 2021 and $1,472 million as of December 31, 2020 excluded from amortization 27,532 27,261
Other 493 523
Less: Accumulated depreciation, depletion and amortization (23,741) (23,673)
Total property and equipment, net 4,284 4,111
Operating lease assets 155 163
Deferred tax assets 0 0
Other long-term assets 206 215
Total long-term assets 361 378
TOTAL ASSETS $ 5,247 $ 5,160
LIABILITIES AND EQUITY
Current liabilities:
Current portion of long-term debt $ 207 $ 0
Accounts payable 639 573
Taxes payable 67 74
Interest payable 55 58
Derivative liabilities 338 245
Current operating lease liabilities 41 42
Other current liabilities 23 20
Total current liabilities 1,370 1,012
Long-term debt 2,812 3,150
Long-term operating lease liabilities 111 117
Long-term derivative liabilities 168 183
Pension and other postretirement liabilities 40 45
Other long-term liabilities 160 156
Total long-term liabilities 3,291 3,651
Commitments and contingencies (Note 12)
0 0
Equity:
Common stock, $0.01 par value; 1,250,000,000 shares authorized; issued 721,195,122 shares as of March 31, 2021 and 718,795,700 shares as of December 31, 2020 7 7
Additional paid-in capital 5,102 5,093
Accumulated deficit (4,283) (4,363)
Accumulated other comprehensive loss (38) (38)
Common stock in treasury, 44,353,224 shares as of March 31, 2021 and December 31, 2020 (202) (202)
Total equity 586 497
TOTAL LIABILITIES AND EQUITY $ 5,247 $ 5,160


	September 30, 2021		December 31, 2020

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

Other	503		523
Less: Accumulated depreciation, depletion and amortization	(23,987)		(23,673)
Total property and equipment, net	8,002		4,111
Operating lease assets	144		163
Deferred tax assets	—		—
Other long-term assets	193		215
Total long-term assets	337		378
TOTAL ASSETS	$	9,241	$	5,160
LIABILITIES AND EQUITY
Current liabilities:
Current portion of long-term debt	$	201	$	—
Accounts payable	955		573
Taxes payable	78		74
Interest payable	42		58

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

Additional paid-in capital	6,688		5,093
Accumulated deficit	(6,749)		(4,363)
Accumulated other comprehensive loss	(34)		(38)
Common stock in treasury, 44,353,224 shares as of September 30, 2021 and December 31, 2020	(202)		(202)
Total equity/(deficit)	(286)		497
TOTAL LIABILITIES AND EQUITY	$	9,241	$	5,160

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

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SOUTHWESTERN ENERGY COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

For the three months ended March 31,
(in millions) 2021 2020
Cash Flows From Operating Activities:
Net income (loss) $ 80 $ (1,547)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization 96 113
Amortization of debt issuance costs 2 1
Impairments 0 1,479
Deferred income taxes 0 408
(Gain) loss on derivatives, unsettled 169 (246)
Stock-based compensation 0 1
Gain on early extinguishment of debt 0 (28)
Change in assets and liabilities:
Accounts receivable (33) 53
Accounts payable 33 (86)
Taxes payable (8) (6)
Interest payable (2) 1
Inventories 9 8
Other assets and liabilities 1 9
Net cash provided by operating activities 347 160
Cash Flows From Investing Activities:
Capital investments (227) (228)
Proceeds from sale of property and equipment 1 0
Other (1) 0
Net cash used in investing activities (227) (228)
Cash Flows From Financing Activities:
Payments on long-term debt 0 (52)
Payments on revolving credit facility (923) (500)
Borrowings under revolving credit facility 790 615
Change in bank drafts outstanding 7 5
Cash paid for tax withholding (3) 0
Net cash provided by (used in) financing activities (129) 68
Decrease in cash and cash equivalents (9) 0
Cash and cash equivalents at beginning of year 13 5
Cash and cash equivalents at end of period $ 4 $ 5


	For the nine months ended September 30,
(in millions)	2021		2020
Cash Flows From Operating Activities:
Net loss	$	(2,386)	$	(3,020)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation, depletion and amortization	334		267
Amortization of debt issuance costs	6		6
Impairments	6		2,495
Deferred income taxes	—		408
Loss on derivatives, unsettled	2,952		272
Stock-based compensation	2		2
Loss (gain) on early extinguishment of debt	59		(35)

Other	3		3
Change in assets and liabilities, excluding impact from acquisitions:
Accounts receivable	(147)		106
Accounts payable	58		(129)
Taxes payable	(10)		(12)
Interest payable	(13)		3
Inventories	(2)		3
Other assets and liabilities	(32)		38
Net cash provided by operating activities	830		407

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

Cash Flows From Financing Activities:

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

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

Net cash provided by financing activities	231		381

Increase (decrease) in cash and cash equivalents	(1)		90
Cash and cash equivalents at beginning of year	13		5
Cash and cash equivalents at end of period	$	12	$	95

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
Stock-based compensation — — — — — — — —
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


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

		(in millions, except share amounts)																					(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
Balance at December 31, 2020																						Balance at December 31, 2020	718,795,700			$	7	$	5,093		$	(4,363)	$	(38)		44,353,224	$	(202)	$	497
Comprehensive income:	Comprehensive income:																					Comprehensive income:
Net income																						Net income	—			—		—			80		—			—	—		80
Other comprehensive income																						Other comprehensive income	—			—		—			—		—			—	—		—
Total comprehensive income																						Total comprehensive income	—			—		—			—		—			—	—		80

Issuance of restricted stock																						Issuance of restricted stock	10,067			—		—			—		—			—	—		—
Cancellation of restricted stock																						Cancellation of restricted stock	(405)			—		—			—		—			—	—		—
Restricted units granted																						Restricted units granted	2,136,882			—		8			—		—			—	—		8

Performance units vested																						Performance units vested	1,001,505			—		4			—		—			—	—		4
Tax withholding – stock compensation																						Tax withholding – stock compensation	(748,627)			—		(3)			—		—			—	—		(3)
Balance at March 31, 2021																						Balance at March 31, 2021	721,195,122			$	7	$	5,102		$	(4,283)	$	(38)		44,353,224	$	(202)	$	586
Comprehensive loss:																						Comprehensive loss:
Net loss	Net loss	—	—		—				(1,547)			—		—		—			(1,547)			Net loss	—			—		—			(609)		—			—	—		(609)
Other comprehensive income	Other comprehensive income	—	—		—				—			—		—		—			—			Other comprehensive income	—			—		—			—		3			—	—		3
Total comprehensive loss	Total comprehensive loss	—	—		—				—			—		—		—			(1,547)			Total comprehensive loss	—			—		—			—		—			—	—		(606)
Stock-based compensation	Stock-based compensation	—	—		1				—			—		—		—			1			Stock-based compensation	—			—		2			—		—			—	—		2
Issuance of restricted stock																						Issuance of restricted stock	148,700			—		—			—		—			—	—		—

Restricted units granted																						Restricted units granted	41,879			—		—			—		—			—	—		—
Tax withholding – stock compensation																						Tax withholding – stock compensation	(13,258)			—		—			—		—			—	—		—
Balance at June 30, 2021																						Balance at June 30, 2021	721,372,443			$	7	$	5,104		$	(4,892)	$	(35)		44,353,224	$	(202)	$	(18)
Comprehensive loss:																						Comprehensive loss:
Net loss																						Net loss	—			—		—			(1,857)		—			—	—		(1,857)
Other comprehensive income																						Other comprehensive income	—			—		—			—		1			—	—		1
Total comprehensive loss																						Total comprehensive loss	—			—		—			—		—			—	—		(1,856)

Issuance of restricted stock	Issuance of restricted stock	12,397	—		—				—			—		—		—			—			Issuance of restricted stock	130,675			—		—			—		—			—	—		—
Cancellation of restricted stock		(167,130)	—		—				—			—		—		—			—
Treasury stock		—	—		—				—			—		—		—			—
Restricted units granted	Restricted units granted	1,005,976	—		1				—			—		—		—			1			Restricted units granted	1,132			—		—			—		—			—	—		—
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
Indigo acquisition																						Indigo acquisition	337,827,171			4		1,584			—		—			—	—		1,588

Balance at September 30, 2021																						Balance at September 30, 2021	1,059,331,421			$	11	$	6,688		$	(6,749)	$	(34)		44,353,224	$	(202)	$	(286)

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

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

	(in millions, except share amounts)
Balance at December 31, 2019	585,555,923	$	6	$	4,726	$	(1,251)	$	(33)	44,353,224	$	(202)	$	3,246
Comprehensive loss:
Net loss	—	—		—		(1,547)		—		—	—		(1,547)
Other comprehensive income	—	—		—		—		—		—	—		—
Total comprehensive loss	—	—		—		—		—		—	—		(1,547)
Stock-based compensation	—	—		1		—		—		—	—		1

Issuance of restricted stock	12,397	—		—		—		—		—	—		—
Cancellation of restricted stock	(167,130)	—		—		—		—		—	—		—

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

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

Southwestern Energy Company (including its subsidiaries, collectively “Southwestern” or the “Company”) is an independent energy company engaged in ~~natural gas, oil and NGL~~ exploration, development and production (“E&P”). of primarily natural gas as well as associated NGLs and oil. The Company is also focused on creating and capturing additional value through its marketing business (“Marketing”)~~, 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 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~~hydrocarbon reservoirs in Pennsylvania, West Virginia, Ohio and ~~oil reservoirs located~~Louisiana. The Company’s operations in Pennsylvania, West Virginia and ~~Ohio. The Company’s operations in northeast Pennsylvania,~~Ohio, herein referred to as “Northeast 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,“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,” primarily focuses on the Haynesville and ~~West Virginia as “Appalachia.”~~Bossier natural gas reservoirs. The Company also operates drilling rigs located in Appalachia, and provides certain oilfield products and services, principally serving the Company’s E&P activities through vertical integration.

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

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 amounts to prior periods could be impacted as a result of the Montage Merger (as defined below) with Montage Resources Corporation (“Montage”) in November ~~2020.~~2020 and the Indigo Merger (as defined below) with Indigo Natural Resources in September 2021. The Company believes the disclosures made are adequate to make the information presented not misleading.

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 (“2020 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 Annual Report.

(2) ACQUISITION

Indigo Natural Resources Merger

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

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

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former equity holders owned approximately 67% and 33%, respectively, of the outstanding shares of the combined company. See Note 7 and Note 11 for additional information.

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


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

The following table sets forth the preliminary fair value of the assets acquired and liabilities assumed as of the acquisition date. Certain data and studies necessary to complete the purchase price allocation are still under evaluation, including, but not limited to, the valuation of natural gas and oil properties and the resolution of certain matters that the Company is indemnified for under the Indigo Merger Agreement for which not enough information is available to assess the final fair value of at this time. 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 September 1, 2021
Consideration:
Total consideration	$	1,961
Fair Value of Assets Acquired:
Cash and cash equivalents	55
Accounts receivable	192
Other current assets	2
Commodity derivative assets	2
Evaluated oil and gas properties	2,724
Unevaluated oil and gas properties	676
Other property, plant and equipment	4
Other long-term assets	27
Total assets acquired	3,682
Fair Value of Liabilities Assumed:
Accounts payable	266
Other current liabilities	55
Derivative liabilities	501
Revolving credit facility	95
Senior unsecured notes	726
Asset retirement obligations	8
Other noncurrent liabilities	70
Total liabilities assumed	1,721
Net Assets Acquired and Liabilities Assumed	$	1,961

The assets acquired and liabilities assumed were recorded at their preliminary estimated fair values at the date of the Indigo Merger. The valuation of certain assets, including property, are based on preliminary appraisals. The fair value of acquired equipment is based on both available market data and a cost approach.

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

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With the completion of the Indigo Merger, Southwestern acquired proved and unproved properties of approximately $2.7 billion and $676 million, respectively, primarily associated with the Haynesville and Bossier formations. The remaining $4 million in Other property, plant and equipment consists of land, water facilities and various equipment.

Deferred income taxes represent the tax effects of differences in the tax basis and merger-date fair values of assets acquired and liabilities assumed. The initial net balance of any deferred tax assets or liabilities is zero. A full valuation was placed on all deferred tax assets generated following the Indigo Merger consistent with the Company’s treatment of its deferred tax asset balance as of September 30, 2021. The measurement of senior unsecured notes was based on unadjusted quoted prices in an active market and are Level 1. The Company considered the borrowings under the revolving credit facility to approximate fair value. The value of derivative instruments was based on observable inputs, primarily forward commodity-price and interest-rate curves and is considered Level 2.

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

Prior to the Indigo Merger, in May 2021, Indigo closed on an agreement to divest its Cotton Valley natural gas and oil properties. Indigo retained certain contractual commitments related to volume commitments associated with natural gas gathering, for which Southwestern will assume the obligation to pay the gathering provider for any unused portion of the volume commitment under the agreement through 2027, depending on the buyer’s actual use. As of September 30, 2021, up to approximately $34 million of these contractual commitments remain, and the Company has recorded a $17 million liability for the estimated future payments.

Excluding the Cotton Valley gathering agreement (discussed above), the Company has recorded additional liabilities totaling $81 million as of September 30, 2021, primarily related to purchase or volume commitments associated with gathering, fresh water and sand. These amounts will be recognized as payments are made over a period ranging from two to seven years.

Montage Resources Merger

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

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

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

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


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

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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 fair value of the assets acquired and liabilities assumed as of the acquisition date. ~~Although the~~The purchase price allocation related to the Montage Merger is substantially complete as of the date of this ~~filing, there may be further adjustments to the Company’s~~filing. The Company is currently finalizing its analysis on potential liabilities and natural gas and oil ~~properties as~~property valuation. Any final adjustments in the ~~studies necessary~~fourth quarter of 2021 are expected to ~~determine the fair value are finalized. These amounts will~~ be ~~finalized no later than one year from the acquisition date.~~immaterial. For the ~~three~~nine months ended ~~March 31,~~September 30, 2021 there were no changes to the allocation presented in the 2020 Form 10-K.


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

For the ~~three~~nine months ended ~~March 31,~~September 30, 2021, revenues and operating income associated with the operations acquired through the Montage Merger totaled ~~$130~~$414 million and ~~$61~~$219 million, respectively.

Pro Forma Information

The following table presents selected unaudited pro forma condensed financial information for the three and nine months ended ~~March 31,~~September 30, 2020 as if the Montage Merger had occurred on January 1, ~~2019:~~2019 and the Indigo Merger had occurred on January 1, 2020:


~~(in millions, except per share amounts)~~	~~Pro forma results for the three months ended March 31, 2020~~
~~Revenues~~	$	~~725~~
~~Net income (loss) attributable to common stock~~	$	~~(1,498)~~

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

The unaudited pro forma information is not necessarily indicative of the operating results that would have occurred had the Montage Merger and the Indigo Merger (combined, the “Mergers”) been completed at January 1, 2019 and January 1, 2020, respectively, nor is it necessarily indicative of future operating results of the combined ~~entity.~~entities. The unaudited pro forma information gives effect to the Montage Merger and related equity and debt issuances along with the use of proceeds therefrom as if they had occurred on January 1, 2019. The unaudited pro forma information for 2020 is a result of combining the statements of operations of Southwestern with the ~~pre-Merger~~pre-Montage Merger results of Montage and pre-Indigo Merger results of Indigo from January 1, 2020, ~~and 2019~~ and included adjustments for revenues and direct expenses. The pro forma results exclude any cost savings anticipated as a result of the ~~Merger~~Mergers, and ~~the impact of any Merger-related costs. The pro forma results~~ include adjustments to DD&A (depreciation, depletion and amortization) based on the purchase price allocated to property, plant, and equipment and the estimated useful lives as well as adjustments to interest expense. Interest expense was adjusted to reflect the retirement of the Montage senior notes, the Montage credit facility, all related accrued interest and the associated decrease in amortization of issuance costs related to the Montage notes and revolving line of credit. This decrease was partially offset by increases in interest on debt associated with the issuance of ~~$350~~

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$350 million in ~~new~~ 8.375% Senior Notes due 2028 related to the Southwestern debt offering and borrowings under Southwestern’s credit facility used to pay off the Montage notes, Montage credit facility and related accrued interest. Interest expense was also adjusted to include the impact of the assumption and exchange of Indigo’s $700 million of 5.375% Senior Notes due 2029 for equivalent Southwestern senior notes and to reflect the retirement of the Indigo credit facility, all related accrued interest and the associated decrease in amortization of issuance costs related to the revolving line of credit. Management believes the estimates and assumptions are reasonable, and the relative effects of the ~~Merger~~Mergers are properly reflected.

~~Montage~~ Merger-Related Expenses

~~For~~The following table summarizes the ~~three months ended March 31, 2021, the Company incurred $1 million in~~merger-related expenses incurred:


	For the three months ended September 30,				For the nine months ended September 30,
(in millions)	2021		2020		2021		2020
Indigo Merger-related expenses	$	35	$	—	$	37	$	—
Montage Merger-related expenses	—		3		2		3
Total merger-related expenses	$	35	$	3	$	39	$	3

The Indigo Merger-related expenses primarily ~~related to one-time severance costs~~consist of bank, legal and consulting fees along with representation and warranty insurance. The Montage Merger-related expenses primarily consist of employees and contractors that were temporarily assisting in the ~~accelerated vesting of certain Montage share-based awards, based on the terms~~transition and integration of the ~~Agreement and Plan of Merger, for former~~ Montage ~~employees that continued to assist with the transition into 2021.~~Merger.

(3) RESTRUCTURING CHARGES

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~~nine months ended ~~March 31,~~September 30, 2021, and were substantially complete by the end of the first quarter of 2021.

In February 2020, the Company notified employees 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~~nine months ended ~~March 31,~~September 30, 2020, and were substantially complete by the end of the first quarter of 2020.

The following table presents a summary of the restructuring charges included in Operating Income (Loss) for the three and nine months ended ~~March 31,~~September 30, 2021 and 2020:


		For the three months ended March 31,			For the three months ended September 30,						For the nine months ended September 30,
(in millions)	(in millions)		2021			2020		(in millions)	2021		2020		2021		2020
Severance (including payroll taxes) (1)	Severance (including payroll taxes) (1)		$	6		$	10	Severance (including payroll taxes) (1)	$	—	$	—	$	7	$	12

(1)Total restructuring charges were $6$7 million and ~~$10~~$12 million for the Company’s E&P segment for the ~~three~~nine months ended ~~March 31,~~September 30, 2021 and ~~March 31,~~ 2020, respectively.

The following table presents a reconciliation of the liability associated with the Company’s restructuring activities at ~~March 31,~~September 30, 2021, which is reflected in accounts payable on the consolidated balance sheet:


(in millions)
Liability at December 31, 2020	$	3
Additions	67
Distributions	~~(9)~~(10)
Liability at ~~March 31,~~September 30, 2021	$	0—

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(4) REVENUE RECOGNITION

Revenues from Contracts with Customers

Natural gas and liquids. Natural gas, oil and NGL sales are recognized when control of the product is transferred to the customer at a designated delivery point. The pricing provisions of the Company’s contracts are primarily tied to a market index

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

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

Disaggregation of Revenues

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


(in millions)	(in millions)	E&P		Marketing		Intersegment Revenues		Total		(in millions)	E&P		Marketing		Intersegment Revenues		Total
Three months ended March 31, 2021
Three months ended September 30, 2021										Three months ended September 30, 2021
Gas sales	Gas sales	$	451	$	0	$	13	$	464	Gas sales	$	799	$	—	$	12	$	811
Oil sales	Oil sales	80		0		1		81		Oil sales	108		—		2		110
NGL sales	NGL sales	173		0		0		173		NGL sales	255		—		—		255
Marketing	Marketing	0		996		(644)		352		Marketing	—		1,365		(947)		418
Other (1)	Other (1)	1		1		0		2		Other (1)	3		1		—		4
Total	Total	$	705	$	997	$	(630)	$	1,072	Total	$	1,165	$	1,366	$	(933)	$	1,598

Three months ended March 31, 2020
Three months ended September 30, 2020										Three months ended September 30, 2020
Gas sales	Gas sales	$	239	$	0	$	9	$	248	Gas sales	$	190	$	—	$	9	$	199
Oil sales	Oil sales	52		0		0		52		Oil sales	39		—		1		40
NGL sales	NGL sales	50		0		0		50		NGL sales	68		—		—		68
Marketing	Marketing	0		548		(309)		239		Marketing	—		495		(276)		219
Other ~~(2)~~	Other ~~(2)~~	3		0		0		3		Other ~~(2)~~	1		—		—		1
Total	Total	$	344	$	548	$	(300)	$	592	Total	$	298	$	495	$	(266)	$	527

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(in millions)	E&P		Marketing		Intersegment Revenues		Total
Nine months ended September 30, 2021
Gas sales	$	1,671	$	—	$	37	$	1,708
Oil sales	293		—		4		297
NGL sales	606		—		1		607
Marketing	—		3,344		(2,242)		1,102
Other (1)	4		2		—		6
Total	$	2,574	$	3,346	$	(2,200)	$	3,720

Nine months ended September 30, 2020
Gas sales	$	584	$	—	$	27	$	611
Oil sales	107		—		4		111
NGL sales	158		—		—		158
Marketing	—		1,432		(787)		645
Other (2)	4		—		—		4
Total	$	853	$	1,432	$	(756)	$	1,529

(1)For the ~~three~~nine months ended ~~March 31,~~September 30, 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)For the ~~three~~nine months ended ~~March 31,~~September 30, 2020, other E&P revenues consists primarily of gains on purchaser imbalances associated with certain NGLs.

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


		For the three months ended March 31,			For the three months ended September 30,						For the nine months ended September 30,
(in millions)	(in millions)		2021			2020		(in millions)	2021		2020		2021		2020
Northeast Appalachia			$	263		$	195
Southwest Appalachia			441			149
Appalachia								Appalachia	$	1,033	$	297	$	2,441	$	852
Haynesville								Haynesville	132		—		132		—
Other	Other		1			0		Other	—		1		1		1
Total	Total		$	705		$	344	Total	$	1,165	$	298	$	2,574	$	853

Receivables from Contracts with Customers

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


(in millions)	(in millions)	March 31, 2021		December 31, 2020		(in millions)	September 30, 2021		December 31, 2020
Receivables from contracts with customers	Receivables from contracts with customers	$	381	$	350	Receivables from contracts with customers	$	678	$	350
Other accounts receivable	Other accounts receivable	19		18		Other accounts receivable	30		18
Total accounts receivable	Total accounts receivable	$	400	$	368	Total accounts receivable	$	708	$	368

Amounts recognized against the Company’s allowance for doubtful accounts related to receivables arising from contracts with customers were immaterial for the three and nine months ended ~~March 31,~~September 30, 2021 and 2020. 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 ~~March 31,~~September 30, 2021 and December 31, 2020:


(in millions)	(in millions)	March 31, 2021		December 31, 2020		(in millions)	September 30, 2021		December 31, 2020
Cash	Cash	$	4	$	13	Cash	$	12	$	13
Marketable securities (1)	Marketable securities (1)	0		0		Marketable securities (1)	—		—

Total	Total	$	4	$	13	Total	$	12	$	13

(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 exploration, development and acquisition of natural gas and oil properties. Under this method, all such costs (productive and nonproductive), including salaries, benefits

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and other internal costs directly attributable to these activities, are capitalized on a country-by-country basis and amortized over the estimated lives of the properties using the units-of-production method. These capitalized costs are subject to a ceiling test that limits such pooled costs, net of applicable deferred taxes, to the aggregate of the present value of future net revenues attributable to proved natural gas, oil and NGL reserves discounted at 10% (standardized measure). Any costs in excess of the ceiling are written off as a non-cash expense. The expense may not be reversed in future periods, even though higher natural gas, oil and NGL prices may subsequently increase the ceiling. Companies using the full cost method are required to use the average quoted price from the first day of each month from the previous 12 months, including the impact of derivatives designated for hedge accounting, to calculate the ceiling value of their reserves. The Company had 0no hedge positions that were designated for hedge accounting as of ~~March 31,~~September 30, 2021. Prices used to calculate the ceiling value of reserves were as follows:

March 31, 2021 March 31, 2020
Natural gas (per MMBtu)
$ 2.16 $ 2.30
Oil (per Bbl)
$ 40.01 $ 55.77
NGLs (per Bbl)
$ 13.57 $ 9.96


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

Using the average quoted prices above, adjusted for market differentials, the Company’s net book value of its United States natural gas and oil properties did not exceed the ceiling amount at ~~March 31, 2021, and the Company had 0 derivative positions that were designated for hedge accounting as of March 31,~~September 30, 2021. 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 ceiling test impairments.

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~~NaN~~No impairment expense was recorded for the ~~three~~nine months ended ~~March 31,~~September 30, 2021 in relation to the recently acquired Montage 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 ~~strip~~ natural gas and oil pricing existing at the date of the Montage Merger, and the Company affirmed that there has not been a material decline to the fair value of these acquired assets since the Montage Merger. The properties acquired in the Montage Merger have an unamortized cost at ~~March 31,~~September 30, 2021 of ~~$1,102~~$1,183 million. Due to the improvement in commodity prices in the ~~first quarter~~second and third quarters of 2021, 0no impairment charge would have been recorded for the three and nine months ended ~~March 31,~~September 30, 2021 had the ~~recently~~ acquired Montage natural gas and oil properties been included in 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 March 31, 2020, $650 million at June 30, 2020 and $361 million at September 30, 2020, resulting in a non-cash ceiling test impairment for the ~~three months ended March 31,~~first, second and third quarters of 2020.

(7) EARNINGS PER SHARE

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

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

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

For the three months ended March 31,
(in millions, except share/per share amounts) 2021 2020
Net income (loss) $ 80 $ (1,547)
Number of common shares:
Weighted average outstanding 675,385,145 540,308,491
Issued upon assumed exercise of outstanding stock options 0 0
Effect of issuance of non-vested restricted common stock 870,541 0
Effect of issuance of non-vested restricted units 804,944 0
Effect of issuance of non-vested performance units 2,807,195 0
Weighted average and potential dilutive outstanding 679,867,825 540,308,491
Earnings per common share
Basic $ 0.12 $ (2.86)
Diluted $ 0.12 $ (2.86)

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

Number of common shares:
Weighted average outstanding	787,032,414		571,872,413		713,455,662		551,162,559
Issued upon assumed exercise of outstanding stock options	—		—		—		—
Effect of issuance of non-vested restricted common stock	—		—		—		—
Effect of issuance of non-vested restricted units	—		—		—		—
Effect of issuance of non-vested performance units	—		—		—		—
Weighted average and potential dilutive outstanding	787,032,414		571,872,413		713,455,662		551,162,559

Loss per common share
Basic	$	(2.36)	$	(1.04)	$	(3.34)	$	(5.48)
Diluted	$	(2.36)	$	(1.04)	$	(3.34)	$	(5.48)

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


		For the three months ended March 31,		For the three months ended September 30,				For the nine months ended September 30,
			2021		2020		2021	2020	2021	2020
Unexercised stock options	Unexercised stock options		3,795,091		4,584,563	Unexercised stock options	3,699,448	4,425,886	3,742,486	4,519,385
Unvested share-based payment	Unvested share-based payment		0		1,006,860	Unvested share-based payment	762,945	939,941	827,279	946,547
Restricted stock units	Restricted stock units		3,987,291		1,312,293	Restricted stock units	3,434,189	1,935,781	3,509,603	2,001,621
Performance units	Performance units		0		2,275,498	Performance units	2,251,254	2,282,211	2,196,073	2,027,985
Total	Total		7,782,382		9,179,214	Total	10,147,836	9,583,819	10,275,441	9,495,538

(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 ~~March 31,~~September 30, 2021, the Company’s derivative financial instruments consisted of fixed price swaps, two-way costless collars, three-way costless collars, basis swaps, call options, swaptions and interest rate swaps. A description of the Company’s derivative financial instruments is provided below:


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

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

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

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

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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.

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 ~~derivative positions.~~derivatives position. The Company presents its ~~derivative positions~~derivatives position on a gross basis and does not net the asset and liability positions.

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

Financial Protection on Production
Weighted Average Price per MMBtu
Volume (Bcf)
Swaps Sold Puts Purchased Puts Sold Calls Basis Differential
Fair Value at
March 31, 2021
(in millions)
Natural Gas
2021
Fixed price swaps 176 $ 2.79 $ — $ — $ — $ — $ 14
Two-way costless collars 195 — — 2.57 2.93 — 1
Three-way costless collars 218 — 2.17 2.50 2.84 — (23)
Total 589 $ (8)
2022
Fixed price swaps 112 $ 2.68 $ — $ — $ — $ — $ (2)
Two-way costless collars 63 — — 2.52 3.03 — (3)
Three-way costless collars 278 — 2.06 2.50 2.97 — (13)
Total 453 $ (18)
2023
Three-way costless collars 103 $ — $ 2.05 $ 2.46 $ 3.01 $ — $ (4)
Basis Swaps
2021 233 $ — $ — $ — $ — $ (0.49) $ 39
2022 220 — — — — (0.44) 24
2023 119 — — — — (0.56) 4
2024 24 — — — — (0.64) 1
2025 9 — — — — (0.64) 0
Total 605 $ 68


Financial Protection on Production
		Weighted Average Price per MMBtu
	Volume (Bcf)	Swaps		Sold Puts		Purchased Puts		Sold Calls		Basis Differential		Fair Value at September 30, 2021 (in millions)
Natural Gas
2021
Fixed price swaps	102	$	2.83	$	—	$	—	$	—	$	—	$	(314)
Two-way costless collars	88	—		—		2.70		3.04		—		(253)
Three-way costless collars	84	—		2.19		2.54		2.91		—		(251)
Total	274											$	(818)
2022
Fixed price swaps	539	$	2.77	$	—	$	—	$	—	$	—	$	(868)
Two-way costless collars	141	—		—		2.66		3.06		—		(253)
Three-way costless collars	333	—		2.06		2.51		2.94		—		(493)
Total	1,013											$	(1,614)
2023
Fixed price swaps	274	$	2.76	$	—	$	—	$	—	$	—	$	(192)
Two-way costless collars	83	—		—		2.69		2.92		—		(43)
Three-way costless collars	215	—		2.09		2.54		3.00		—		(159)
Total	572											$	(394)
2024
Fixed price swaps	57	$	2.43	$	—	$	—	$	—	$	—	$	(42)
Three-way costless collars	11	—		2.25		2.80		3.54		—		(6)
Total	68											$	(48)

Basis Swaps
2021	71	$	—	$	—	$	—	$	—	$	(0.36)	$	19
2022	284	—		—		—		—		(0.38)		17
2023	197	—		—		—		—		(0.49)		2
2024	46	—		—		—		—		(0.71)		3
2025	9	—		—		—		—		(0.64)		1
Total	607											$	42

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Volume
(MBbls)
Weighted Average Strike Price per Bbl
Fair Value at
March 31, 2021
(in millions)
Swaps Sold Puts Purchased Puts Sold Calls
Oil
2021
Fixed price swaps 3,272 $ 49.27 $ — $ — $ — $ (29)
Two-way costless collars 156 — — 37.79 45.73 (2)
Three-way costless collars 1,498 — 37.86 47.70 53.10 (10)
Total 4,926 $ (41)
2022
Fixed price swaps 1,719 $ 48.54 $ — $ — $ — $ (10)
Three-way costless collars 1,380 — 39.89 50.23 57.05 (4)
Total 3,099 $ (14)
2023
Three-way costless collars 1,268 $ — $ 33.97 $ 45.51 $ 56.12 $ (4)
Ethane
2021
Fixed price swaps 4,429 $ 7.17 $ — $ — $ — $ (11)
Two-way costless collars 440 — — 7.14 10.40 0
Total 4,869 $ (11)
2022
Fixed price swaps 1,758 $ 8.68 $ — $ — $ — $ (1)
Two-way costless collars 135 — — 7.56 9.66 0
Total 1,893 $ (1)
Propane
2021
Fixed price swaps 5,443 $ 20.84 $ — $ — $ — $ (69)
2022
Fixed price swaps 2,723 $ 21.83 $ — $ — $ — $ (14)
Three-way costless collars 305 — 16.80 21.00 31.92 (1)
Total 3,028 (15)
Normal Butane
2021
Fixed price swaps 1,568 $ 25.30 $ — $ — $ — $ (19)
2022
Fixed price swaps 888 $ 24.47 $ — $ — $ — $ (5)
Natural Gasoline
2021
Fixed price swaps 1,513 $ 37.91 $ — $ — $ — $ (27)
2022
Fixed price swaps 857 $ 40.48 $ — $ — $ — $ (8)


	Volume (MBbls)	Weighted Average Strike Price per Bbl								Fair Value at September 30, 2021 (in millions)
		Swaps		Sold Puts		Purchased Puts		Sold Calls
Oil
2021
Fixed price swaps	780	$	48.94	$	—	$	—	$	—	$	(20)
Two-way costless collars	46	—		—		37.50		45.50		(1)
Three-way costless collars	550	—		39.18		48.95		54.35		(11)
Total	1,376									$	(32)
2022
Fixed price swaps	3,203	$	53.54	$	—	$	—	$	—	$	(53)
Three-way costless collars	1,380	—		39.89		50.23		57.05		(20)
Total	4,583									$	(73)
2023
Fixed price swaps	846	$	55.98	$	—	$	—	$	—	$	(7)
Three-way costless collars	1,268	—		33.97		45.51		56.12		(16)
Total	2,114									$	(23)
2024
Fixed price swaps	54	$	53.15	$	—	$	—	$	—	$	—

Ethane
2021
Fixed price swaps	2,483	$	9.74	$	—	$	—	$	—	$	(19)
Two-way costless collars	147	—		—		7.14		10.40		(1)
Total	2,630									$	(20)
2022
Fixed price swaps	3,361	$	10.01��	$	—	$	—	$	—	$	(16)
Two-way costless collars	135	—		—		7.56		9.66		(1)
Total	3,496									$	(17)





Propane
2021
Fixed price swaps	2,107	$	23.98	$	—	$	—	$	—	$	(74)


2022
Fixed price swaps	4,471	$	26.96	$	—	$	—	$	—	$	(84)
Three-way costless collars	305	—		16.80		21.00		31.92		(5)
Total	4,776									$	(89)



Normal Butane
2021
Fixed price swaps	617	$	29.08	$	—	$	—	$	—	$	(22)
2022
Fixed price swaps	1,295	$	29.16	$	—	$	—	$	—	$	(28)

Natural Gasoline
2021
Fixed price swaps	635	$	43.62	$	—	$	—	$	—	$	(19)
2022
Fixed price swaps	1,256	$	46.41	$	—	$	—	$	—	$	(26)

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Other Derivative Contracts
Volume
(Bcf)
Weighted Average Strike Price per MMBtu
Fair Value at
March 31, 2021
(in millions)
Call Options – Natural Gas (Net)
2021 57 $ 3.19 $ (4)
2022 77 3.00 (16)
2023 46 2.94 (10)
2024 9 3.00 (3)
Total 189 $ (33)
Put Options – Natural Gas
2021 14 $ 2.00 $ 0
2022 5 2.00 (1)
Total 19 $ (1)

Volume
(MBbls)
Weighted Average Strike Price per Bbl
Fair Value at
March 31, 2021
(in millions)
Call Options – Oil
2021 171 $ 60.00 $ (1)

Volume
(Bcf)
Weighted Average Strike Price per MMBtu
Fair Value at
March 31, 2021
(in millions)
Swaptions – Natural Gas
2021 (1)
18 $ 3.00 $ (1)


Other Derivative Contracts
	Volume (Bcf)	Weighted Average Strike Price per MMBtu		Fair Value at September 30, 2021 (in millions)





Call Options – Natural Gas (Net)
2021	19	$	3.19	$	(52)
2022	77	3.00		(118)
2023	46	2.94		(37)
2024	9	3.00		(9)

Total	151			$	(216)
Put Options – Natural Gas
2021	5	$	2.00	$	—
2022	5	2.00		—
Total	10			$	—


	Volume (MBbls)	Weighted Average Strike Price per Bbl		Fair Value at September 30, 2021 (in millions)
Call Options – Oil
2021	57	$	60.00	$	(1)


	Volume (Bcf)	Weighted Average Strike Price per MMBtu		Fair Value at September 30, 2021 (in millions)
Swaptions – Natural Gas
2021 (1)	18	$	3.00	$	(26)

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


		Volume (Bcf)	Weighted Average Strike Price per MMBtu				Fair Value at March 31, 2021 (in millions)			Volume (Bcf)	Weighted Average Strike Price per MMBtu				Fair Value at September 30, 2021 (in millions)
			Swaps		Basis Differential						Swaps		Basis Differential
Storage (1)	Storage (1)								Storage (1)
2021	2021								2021
Purchased fixed price swaps	Purchased fixed price swaps	2	$	2.34	$	0	$	0	Purchased fixed price swaps	—	$	2.20	$	—	$	1
Purchased basis swaps	Purchased basis swaps	1	0		(0.88)		0		Purchased basis swaps	—	—		(0.88)		—
Fixed price swaps	Fixed price swaps	0	2.23		0		0		Fixed price swaps	—	3.17		—		—
Basis swaps	Basis swaps	0	0		(0.57)		0		Basis swaps	—	—		(0.57)		—
Total	Total	3					$	0	Total	—					$	1
2022	2022								2022
Purchased fixed price swaps	Purchased fixed price swaps	0	$	2.14	$	0	$	0	Purchased fixed price swaps	—	$	2.14	$	—	$	1
Fixed price swaps	Fixed price swaps	2	2.82		0		0		Fixed price swaps	2	2.82		—		(5)
Basis swaps	Basis swaps	1	0		(0.57)		0		Basis swaps	1	—		(0.57)		—
Total	Total	3					$	0	Total	3					$	(4)

(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)	Purchased Fixed Price Swaps – Marketing (Natural Gas) (1)	Volume (Bcf)	Weighted Average Strike Price per MMBtu	Fair Value at March 31, 2021 (in millions)	Purchased Fixed Price Swaps – Marketing (Natural Gas) (1)	Volume (Bcf)	Weighted Average Strike Price per MMBtu		Fair Value at September 30, 2021 (in millions)
2021	2021	4	2.44	1	2021	1	$	2.44	$	2

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

At ~~March 31,~~September 30, 2021, the net fair value of the Company’s financial instruments was a $3,491 million liability, which included a $1 million asset related to ~~commodities was a $211 million liability~~interest rate swaps and ~~included~~ a net reduction of the liability of ~~less than $1~~$7 million related to non-performance risk. See Note 10 for additional details regarding the Company’s fair value measurements of its ~~derivative positions.~~derivatives position.

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As of ~~March 31,~~September 30, 2021, 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 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 ~~March 31,~~September 30, 2021 and December 31, ~~2020:~~2020, and excludes net liability reductions of $7 million and $1 million respectively, for non-performance risk:


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

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

Fixed price swaps – natural gas	Fixed price swaps – natural gas	Derivative assets	25		37		Fixed price swaps – natural gas	Derivative assets	—		37
Fixed price swaps – oil	Fixed price swaps – oil	Derivative assets	0		13		Fixed price swaps – oil	Derivative assets	—		13

Two-way costless collars – natural gas	Two-way costless collars – natural gas	Derivative assets	39		54		Two-way costless collars – natural gas	Derivative assets	11		54

Three-way costless collars – natural gas	Three-way costless collars – natural gas	Derivative assets	39		57		Three-way costless collars – natural gas	Derivative assets	13		57
Three-way costless collars – oil	Three-way costless collars – oil	Derivative assets	6		15		Three-way costless collars – oil	Derivative assets	1		15
Basis swaps – natural gas	Basis swaps – natural gas	Derivative assets	46		60		Basis swaps – natural gas	Derivative assets	66		60
Call options – natural gas	Call options – natural gas	Derivative assets	1		4		Call options – natural gas	Derivative assets	35		4

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

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

Fixed price swaps – propane		Other long-term assets	1		0

Two-way costless collars – natural gas	Two-way costless collars – natural gas	Other long-term assets	2		20		Two-way costless collars – natural gas	Other long-term assets	17		20

Three-way costless collars – natural gas	Three-way costless collars – natural gas	Other long-term assets	82		87		Three-way costless collars – natural gas	Other long-term assets	41		87
Three-way costless collars – oil	Three-way costless collars – oil	Other long-term assets	14		15		Three-way costless collars – oil	Other long-term assets	4		15
Basis swaps – natural gas	Basis swaps – natural gas	Other long-term assets	39		15		Basis swaps – natural gas	Other long-term assets	44		15

Interest rate swaps	Interest rate swaps	Other long-term assets	1		0		Interest rate swaps	Other long-term assets	1		—
Total derivative assets	Total derivative assets		$	296	$	387	Total derivative assets		$	237	$	387

1922

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Derivative Liabilities
Fair Value
(in millions) Balance Sheet Classification March 31, 2021 December 31, 2020
Derivatives not designated as hedging instruments:
Fixed price swaps – natural gas Derivative liabilities $ 12 $ 7
Fixed price swaps – oil Derivative liabilities 32 12
Fixed price swaps – ethane Derivative liabilities 11 10
Fixed price swaps – propane Derivative liabilities 76 36
Fixed price swaps – normal butane Derivative liabilities 21 8
Fixed price swaps – natural gasoline Derivative liabilities 30 13
Two-way costless collars – natural gas Derivative liabilities 39 43
Two-way costless collars – oil Derivative liabilities 2 1
Three-way costless collars – natural gas Derivative liabilities 73 82
Three-way costless collars – oil Derivative liabilities 17 15
Basis swaps – natural gas Derivative liabilities 9 3
Call options – natural gas Derivative liabilities 13 12
Call options – oil Derivative liabilities 1 0
Put options – natural gas Derivative liabilities 1 1
Swaptions – natural gas Derivative liabilities 1 2
Fixed price swaps – natural gas Long-term derivative liabilities 1 3
Fixed price swaps – oil Long-term derivative liabilities 7 2
Fixed price swaps – ethane Long-term derivative liabilities 1 0
Fixed price swaps – propane Long-term derivative liabilities 8 2
Fixed price swaps – normal butane Long-term derivative liabilities 3 1
Fixed price swaps – natural gasoline Long-term derivative liabilities 5 2
Two-way costless collars – natural gas Long-term derivative liabilities 4 21
Three-way costless collars – natural gas Long-term derivative liabilities 88 102
Three-way costless collars – oil Long-term derivative liabilities 21 15
Three-way costless collars – propane Long-term derivative liabilities 1 0
Basis swap – natural gas Long-term derivative liabilities 8 7
Call options – natural gas Long-term derivative liabilities 21 28
Total derivative liabilities $ 506 $ 428


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


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

Fixed price swaps – natural gas storage	Derivative liabilities	5		—
Fixed price swaps – natural gas	Long-term derivative liabilities	406		3
Fixed price swaps – oil	Long-term derivative liabilities	20		2
Fixed price swaps – ethane	Long-term derivative liabilities	3		—
Fixed price swaps – propane	Long-term derivative liabilities	15		2
Fixed price swaps – normal butane	Long-term derivative liabilities	6		1
Fixed price swaps – natural gasoline	Long-term derivative liabilities	5		2
Two-way costless collars – natural gas	Long-term derivative liabilities	82		21

Three-way costless collars – natural gas	Long-term derivative liabilities	313		102
Three-way costless collars – oil	Long-term derivative liabilities	24		15
Three-way costless collars – propane	Long-term derivative liabilities	1		—
Basis swap – natural gas	Long-term derivative liabilities	20		7
Call options – natural gas	Long-term derivative liabilities	69		28

Total derivative liabilities		$	3,735	$	428

2023

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


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

						(in millions)													(in millions)
Purchased fixed price swaps – natural gas	Purchased fixed price swaps – natural gas		Gain (Loss) on Derivatives					$	0				$	(1)			Purchased fixed price swaps – natural gas		Gain (Loss) on Derivatives			$	(1)		$	4		$	1	$	4
Purchased fixed price swaps – oil		Gain (Loss) on Derivatives				0				(5)
Fixed price swaps – natural gas	Fixed price swaps – natural gas	Gain (Loss) on Derivatives				(22)				103			Fixed price swaps – natural gas			Gain (Loss) on Derivatives			(748)			(138)			(991)			(74)
Fixed price swaps – oil	Fixed price swaps – oil	Gain (Loss) on Derivatives				(40)				118			Fixed price swaps – oil			Gain (Loss) on Derivatives			—			(20)			(81)			54
Fixed price swaps – ethane	Fixed price swaps – ethane	Gain (Loss) on Derivatives				(2)				12			Fixed price swaps – ethane			Gain (Loss) on Derivatives			(12)			(13)			(25)			(23)
Fixed price swaps – propane	Fixed price swaps – propane	Gain (Loss) on Derivatives				(45)				36			Fixed price swaps – propane			Gain (Loss) on Derivatives			(32)			(17)			(120)			(25)
Fixed price swaps – normal butane	Fixed price swaps – normal butane	Gain (Loss) on Derivatives				(15)				0			Fixed price swaps – normal butane			Gain (Loss) on Derivatives			(7)			—			(41)			—
Fixed price swaps – natural gasoline	Fixed price swaps – natural gasoline	Gain (Loss) on Derivatives				(20)				0			Fixed price swaps – natural gasoline			Gain (Loss) on Derivatives			1			—			(30)			—
Two-way costless collars – natural gas	Two-way costless collars – natural gas	Gain (Loss) on Derivatives				(12)				(4)			Two-way costless collars – natural gas			Gain (Loss) on Derivatives			(358)			(34)			(518)			(45)
Two-way costless collars – oil	Two-way costless collars – oil	Gain (Loss) on Derivatives				(1)				19			Two-way costless collars – oil			Gain (Loss) on Derivatives			1			(5)			—			4
Two-way costless collars – ethane													Two-way costless collars – ethane			Gain (Loss) on Derivatives			(1)			—			(2)			—
Two-way costless collars – propane	Two-way costless collars – propane	Gain (Loss) on Derivatives				0				2			Two-way costless collars – propane			Gain (Loss) on Derivatives			—			(1)			—			(2)
Three-way costless collars – natural gas	Three-way costless collars – natural gas	Gain (Loss) on Derivatives				0				(51)			Three-way costless collars – natural gas			Gain (Loss) on Derivatives			(619)			(98)			(869)			(195)
Three-way costless collars – oil	Three-way costless collars – oil	Gain (Loss) on Derivatives				(18)				25			Three-way costless collars – oil			Gain (Loss) on Derivatives			—			(4)			(47)			15
Three-way costless collars – propane	Three-way costless collars – propane	Gain (Loss) on Derivatives				(1)				0			Three-way costless collars – propane			Gain (Loss) on Derivatives			(3)			—			(5)			—
Basis swaps – natural gas	Basis swaps – natural gas	Gain (Loss) on Derivatives				3				(1)			Basis swaps – natural gas			Gain (Loss) on Derivatives			(70)			54			(23)			40
Call options – natural gas	Call options – natural gas	Gain (Loss) on Derivatives				3				(5)			Call options – natural gas			Gain (Loss) on Derivatives			(143)			(16)			(180)			(25)
Call options – oil	Call options – oil	Gain (Loss) on Derivatives				(1)				1			Call options – oil			Gain (Loss) on Derivatives			—			—			(1)			1
Put options – natural gas													Put options – natural gas			Gain (Loss) on Derivatives			—			—			1			—
Swaptions – natural gas	Swaptions – natural gas	Gain (Loss) on Derivatives				1				0			Swaptions – natural gas			Gain (Loss) on Derivatives			(21)			—			(24)			—
Purchased fixed price swap – natural gas storage	Purchased fixed price swap – natural gas storage	Gain (Loss) on Derivatives				0				(1)			Purchased fixed price swap – natural gas storage			Gain (Loss) on Derivatives			1			1			2			—
Fixed price swap – natural gas storage	Fixed price swap – natural gas storage	Gain (Loss) on Derivatives				0				(1)			Fixed price swap – natural gas storage			Gain (Loss) on Derivatives			(3)			(2)			(5)			(2)
Interest rate swaps	Interest rate swaps	Gain (Loss) on Derivatives				1				(1)			Interest rate swaps			Gain (Loss) on Derivatives			—			—			1			—
Total gain (loss) on unsettled derivatives						$	(169)			$	246
Total loss on unsettled derivatives													Total loss on unsettled derivatives						$	(2,015)		$	(289)		$	(2,957)		$	(273)

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					2021			2020

						(in millions)
Purchased fixed price swaps – natural gas			Gain (Loss) on Derivatives					$	0				$	(1)

Fixed price swaps – natural gas		Gain (Loss) on Derivatives				5				5
Fixed price swaps – oil		Gain (Loss) on Derivatives				(17)				9
Fixed price swaps – ethane		Gain (Loss) on Derivatives				(4)				6
Fixed price swaps – propane		Gain (Loss) on Derivatives				(30)				10
Fixed price swaps – normal butane		Gain (Loss) on Derivatives				(7)				0
Fixed price swaps – natural gasoline		Gain (Loss) on Derivatives				(9)				0
Two-way costless collars – natural gas		Gain (Loss) on Derivatives				2				6
Two-way costless collars – oil		Gain (Loss) on Derivatives				(1)				3
Two-way costless collars – propane		Gain (Loss) on Derivatives				0				1
Three-way costless collars – natural gas		Gain (Loss) on Derivatives				1				36
Three-way costless collars – oil		Gain (Loss) on Derivatives				(1)				1
Basis swaps – natural gas		Gain (Loss) on Derivatives				41				16

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

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

Total gain (loss) on settled derivatives						$	(22)			$	93

Total gain (loss) on derivatives						$	(191)			$	339

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Settled Gain (Loss) on Derivatives Recognized in Earnings (1)
	Consolidated Statement of Operations Classification of Gain (Loss) on Derivatives, Settled	For the three months ended September 30,					For the nine months ended September 30,
Derivative Instrument		2021		2020			2021			2020

		(in millions)
Purchased fixed price swaps – natural gas	Gain (Loss) on Derivatives	$	4	$	(2)		$	5		$	(4)
Fixed price swaps – natural gas	Gain (Loss) on Derivatives	(111)		61		(2)	(112)			150		(2)
Fixed price swaps – oil	Gain (Loss) on Derivatives	(18)		17			(63)			44
Fixed price swaps – ethane	Gain (Loss) on Derivatives	(13)		(2)			(23)			6
Fixed price swaps – propane	Gain (Loss) on Derivatives	(53)		2			(113)			19
Fixed price swaps – normal butane	Gain (Loss) on Derivatives	(17)		—			(33)			—
Fixed price swaps – natural gasoline	Gain (Loss) on Derivatives	(16)		—			(38)			—
Two-way costless collars – natural gas	Gain (Loss) on Derivatives	(79)		(5)			(79)			1
Two-way costless collars – oil	Gain (Loss) on Derivatives	(1)		4			(3)			13
Two-way costless collars – ethane	Gain (Loss) on Derivatives	(1)		—			(1)			—
Two-way costless collars – propane	Gain (Loss) on Derivatives	—		—			—			2
Three-way costless collars – natural gas	Gain (Loss) on Derivatives	(84)		—			(91)			43
Three-way costless collars – oil	Gain (Loss) on Derivatives	(10)		1			(16)			5
Basis swaps – natural gas	Gain (Loss) on Derivatives	27		20			76			29
Call options – natural gas	Gain (Loss) on Derivatives	(16)		—			(16)			—
Call options – oil	Gain (Loss) on Derivatives	(1)		—			(1)			—
Put options – natural gas	Gain (Loss) on Derivatives	—		—			(2)		(3)	—
Purchased fixed price swaps – natural gas storage	Gain (Loss) on Derivatives	1		—			1			—
Fixed price swaps – natural gas storage	Gain (Loss) on Derivatives	—		1			—			2

Total gain (loss) on settled derivatives		$	(388)	$	97		$	(509)		$	310


Total Gain (Loss) on Derivatives Recognized in Earnings
	For the three months ended September 30,				For the nine months ended September 30,
	2021		2020		2021		2020

	(in millions)
Total loss on unsettled derivatives	(2,015)		(289)		(2,957)		(273)
Total gain (loss) on settled derivatives	(388)		97		(509)		310
Non-performance risk adjustment	4		—		5		1
Total gain (loss) on derivatives	$	(2,399)	$	(192)	$	(3,461)	$	38

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

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

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

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

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


(in millions)	(in millions)	Pension and Other Postretirement		Foreign Currency		Total		(in millions)	Pension and Other Postretirement		Foreign Currency		Total
Beginning balance December 31, 2020	Beginning balance December 31, 2020	$	(24)	$	(14)	$	(38)	Beginning balance December 31, 2020	$	(24)	$	(14)	$	(38)
Other comprehensive income before reclassifications	Other comprehensive income before reclassifications	0		0		0		Other comprehensive income before reclassifications	—		—		—
Amounts reclassified from other comprehensive income (1)	Amounts reclassified from other comprehensive income (1)	0		0		0		Amounts reclassified from other comprehensive income (1)	4		—		4
Net current-period other comprehensive income	Net current-period other comprehensive income	0		0		0		Net current-period other comprehensive income	4		—		4
Ending balance March 31, 2021		$	(24)	$	(14)	$	(38)
Ending balance September 30, 2021								Ending balance September 30, 2021	$	(20)	$	(14)	$	(34)

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Details about Accumulated Other Comprehensive Income

Affected Line Item in the Consolidated Statement of Operations

Amount Reclassified from Accumulated Other Comprehensive Income

For the ~~three~~nine months ended
~~March 31,~~September 30, 2021

(in millions)

Pension and other postretirement:

~~Amortization of prior service cost and net gain~~Settlement adjustment (1)

Other Income (Loss), Net

Provision (Benefit) for Income Taxes

Net Income ~~(Loss)~~

Total reclassifications for the period

Net Income ~~(Loss)~~

(1)

~~(1) For the three months ended March 31, 2021, the amount reclassified from accumulated other comprehensive income was immaterial.~~ See Note 14 for additional details regarding the Company’s pension and other postretirement benefit plans.

(10) FAIR VALUE MEASUREMENTS

Assets and liabilities measured at fair value on a recurring basis

The carrying amounts and estimated fair values of the Company’s financial instruments as of ~~March 31,~~September 30, 2021 and December 31, 2020 were as follows:


		March 31, 2021				December 31, 2020					September 30, 2021				December 31, 2020
(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	$	4	$	4	$	13	$	13	Cash and cash equivalents	$	12	$	12	$	13	$	13
2018 revolving credit facility due April 2024	2018 revolving credit facility due April 2024	567		567		700		700		2018 revolving credit facility due April 2024	665		665		700		700
Senior notes (1)	Senior notes (1)	2,471		2,640		2,471		2,609		Senior notes (1)	3,580		3,886		2,471		2,609
Derivative instruments, net	Derivative instruments, net	(210)		(210)		(41)		(41)		Derivative instruments, net	(3,491)		(3,491)		(41)		(41)

(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~~Due to limited trading activity, the fair value of the Company’s 4.10% Senior Notes

~~Table of Contents~~

due March 2022 is considered to be a Level 2 measurement on the fair value hierarchy. The fair values of the Company’s more actively traded remaining senior notes are considered the be a Level 1 measurement. The carrying values of the borrowings under the Company’s revolving credit facility (to the extent utilized) approximates fair value because the interest rate is variable and reflective of market rates. The Company considers the fair value of its revolving credit facility to be a Level 1 measurement on the fair value hierarchy.

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

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The Company has classified its derivative instruments into levels depending upon the data utilized to determine their fair values. The Company’s fixed price swaps (Level 2) are estimated using third-party discounted cash flow calculations using the New York Mercantile Exchange (“NYMEX”) futures index for natural gas and oil derivatives and Oil Price Information Service (“OPIS”) for ethane and propane derivatives. The Company utilizes discounted cash flow models for valuing its interest rate derivatives (Level 2). The net derivative values attributable to the Company’s interest rate derivative contracts as of December 31, 2020 are based on (i) the contracted notional amounts, (ii) active market-quoted London Interbank Offered Rate (“LIBOR”) yield curves and (iii) the applicable credit-adjusted risk-free rate yield curve.

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

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

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


		March 31, 2021									September 30, 2021
		Fair Value Measurements Using:									Fair Value Measurements Using:
(in millions)	(in millions)	Quoted Prices in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Assets (Liabilities) at Fair Value		(in millions)	Quoted Prices in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Assets (Liabilities) at Fair Value
Assets	Assets									Assets
Purchased fixed price swaps	Purchased fixed price swaps	$	0	$	1	$	0	$	1	Purchased fixed price swaps	$	—	$	2	$	—	$	2
Fixed price swaps		0		26		0		26

Two-way costless collars	Two-way costless collars	0		41		0		41		Two-way costless collars	—		28		—		28
Three-way costless collars	Three-way costless collars	0		141		0		141		Three-way costless collars	—		59		—		59
Basis swaps	Basis swaps	0		85		0		85		Basis swaps	—		110		—		110
Call options	Call options	0		1		0		1		Call options	—		35		—		35

Interest rate swap		0		1		0		1
Purchased fixed price swaps – storage										Purchased fixed price swaps – storage	—		2		—		2
Interest rate swaps										Interest rate swaps	—		1		—		1
Liabilities	Liabilities									Liabilities

Fixed price swaps	Fixed price swaps	0		(207)		0		(207)		Fixed price swaps	—		(1,784)		—		(1,784)
Two-way costless collars	Two-way costless collars	0		(45)		0		(45)		Two-way costless collars	—		(580)		—		(580)
Three-way costless collars	Three-way costless collars	0		(200)		0		(200)		Three-way costless collars	—		(1,020)		—		(1,020)
Basis swaps	Basis swaps	0		(17)		0		(17)		Basis swaps	—		(68)		—		(68)
Call options	Call options	0		(35)		0		(35)		Call options	—		(252)		—		(252)
Put options		0		(1)		0		(1)

Swaptions	Swaptions	0		(1)		0		(1)		Swaptions	—		(26)		—		(26)

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

Total (1)	Total (1)	$	0	$	(210)	$	0	$	(210)	Total (1)	$	—	$	(3,498)	$	—	$	(3,498)

(1)~~Includes~~Excludes a net reduction to the liability fair value of ~~less than $1~~$7 million related to estimated ~~nonperformance~~non-performance risk.

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		December 31, 2020									December 31, 2020
		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	Purchased fixed price swaps	$	0	$	1	$	0	$	1	Purchased fixed price swaps	$	—	$	1	$	—	$	1
Fixed price swaps	Fixed price swaps	0		59		0		59		Fixed price swaps	—		59		—		59
Two-way costless collars	Two-way costless collars	0		74		0		74		Two-way costless collars	—		74		—		74
Three-way costless collars	Three-way costless collars	0		174		0		174		Three-way costless collars	—		174		—		174
Basis swaps	Basis swaps	0		75		0		75		Basis swaps	—		75		—		75
Call options	Call options	0		4		0		4		Call options	—		4		—		4

Liabilities	Liabilities									Liabilities

Fixed price swaps	Fixed price swaps	0		(96)		0		(96)		Fixed price swaps	—		(96)		—		(96)
Two-way costless collars	Two-way costless collars	0		(65)		0		(65)		Two-way costless collars	—		(65)		—		(65)
Three-way costless collars	Three-way costless collars	0		(214)		0		(214)		Three-way costless collars	—		(214)		—		(214)
Basis swaps	Basis swaps	0		(10)		0		(10)		Basis swaps	—		(10)		—		(10)
Call options	Call options	0		(40)		0		(40)		Call options	—		(40)		—		(40)
Put options	Put options	0		(1)		0		(1)		Put options	—		(1)		—		(1)
Swaptions	Swaptions	0		(2)		0		(2)		Swaptions	—		(2)		—		(2)

Total (1)	Total (1)	$	0	$	(41)	$	0	$	(41)	Total (1)	$	—	$	(41)	$	—	$	(41)

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

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

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

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(11) DEBT

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

March 31, 2021
(in millions) Debt Instrument Unamortized Issuance Expense Unamortized Debt Discount Total
Current portion of long-term debt:
4.10% Senior Notes due March 2022 $ 207 $ 0 $ 0 $ 207
Total current portion of long-term debt $ 207 $ 0 $ 0 $ 207
Long-term debt:
Variable rate (2.09% at March 31, 2021) 2018 revolving credit facility due April 2024 $ 567 $ 0 (1) $ 0 $ 567
4.95% Senior Notes due January 2025 (2)
856 (4) (1) 851
7.50% Senior Notes due April 2026 618 (5) 0 613
7.75% Senior Notes due October 2027 440 (4) 0 436
8.375% Senior Notes due September 2028 350 (5) 0 345
Total long-term debt $ 2,831 $ (18) $ (1) $ 2,812
Total debt $ 3,038 $ (18) $ (1) $ 3,019
December 31, 2020
(in millions) Debt Instrument Unamortized Issuance Expense Unamortized Debt Discount Total
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
7.75% Senior Notes due October 2027 440 (5) 0 435
8.375% Senior Notes due September 2028 350 (5) 0 345
Total long-term debt $ 3,171 $ (20) $ (1) $ 3,150

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	September 30, 2021
(in millions)	Debt Instrument		Unamortized Issuance Expense			Unamortized Debt Premium		Total
Current portion of long-term debt:
4.10% Senior Notes due March 2022	$	201	$	—		$	—	$	201
Total current portion of long-term debt	$	201	$	—		$	—	$	201

Long-term debt:
Variable rate (2.08% at September 30, 2021) 2018 revolving credit facility due April 2024	$	665	$	—	(1)	$	—	$	665
4.95% Senior Notes due January 2025 (2)	689		(3)			—		686

7.75% Senior Notes due October 2027	440		(4)			—		436
8.375% Senior Notes due September 2028	350		(5)			—		345
5.375% Senior Notes due February 2029	700		(5)			26		721
5.375% Senior Notes due September 2030	1,200		(17)			—		1,183
Total long-term debt	$	4,044	$	(34)		$	26	$	4,036

Total debt	$	4,245	$	(34)		$	26	$	4,237

	December 31, 2020
(in millions)	Debt Instrument		Unamortized Issuance Expense			Unamortized Debt Discount		Total
Long-term debt:
Variable rate (2.11% at December 31, 2020) 2018 revolving credit facility due April 2024	$	700	$	—	(1)	$	—	$	700
4.10% Senior Notes due March 2022	207		—			—		207
4.95% Senior Notes due January 2025 (2)	856		(4)			(1)		851
7.50% Senior Notes due April 2026	618		(6)			—		612
7.75% Senior Notes due October 2027	440		(5)			—		435
8.375% Senior Notes due September 2028	350		(5)			—		345
Total long-term debt	$	3,171	$	(20)		$	(1)	$	3,150

(1)At ~~March 31,~~September 30, 2021 and December 31, 2020, unamortized issuance expense of ~~$11~~$10 million and $12 million, respectively, associated with the 2018 credit facility (as defined below) was classified as other long-term assets on the consolidated balance sheets.

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

The following is a summary of scheduled debt maturities by year as of ~~March 31,~~September 30, 2021:


(in millions)	(in millions)			(in millions)
2021	2021	$	0	2021	$	—
2022	2022	207		2022	201
2023	2023	0		2023	—
2024(1)	2024(1)	567		2024(1)	665
2025	2025	856		2025	689
Thereafter	Thereafter	1,408		Thereafter	2,690
		$	3,038		$	4,245

(1)The Company’s current revolving credit facility matures in 2024.

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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~~September 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, typically 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 senior note indentures currently limit liens securing indebtedness to the greater of $2.0 billion or 25% of adjusted consolidated net tangible ~~assets.~~assets, which is currently approximately $2.9 billion.

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 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. EBITDAX, as defined in the credit agreement governing the Company’s 2018 credit facility, excludes the effects of interest expense, depreciation, depletion and amortization, income tax, any non-cash impacts from 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.

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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 ~~March 31,~~September 30, 2021, the Company was in compliance with all of the covenants contained in the credit agreement governing the 2018 credit facility.

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

As of ~~March 31,~~September 30, 2021, the Company had ~~$233~~$159 million in letters of credit and ~~$567~~$665 million 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.

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The Company’s debt exposure to the anticipated transition from LIBOR in late 2021 is limited to the 2018 credit facility. Upon announcement by the administrator of LIBOR identifying 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 the Company. The ~~alternative rate will be based on the prevailing market convention and is~~USD-LIBOR settings are expected to be published through June 2023 and Southwestern anticipates using a variation of this rate until the ~~Secured Overnight Financing Rate (“SOFR”).~~underlying agreements are extended beyond the LIBOR publication date.

Senior Notes

In January 2015, the Company completed a public offering of $1.0 billion aggregate principal amount of its 4.95% senior notes 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. 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 2025 Notes bondholders at the higher interest rate was paid in January 2021. InOn September 1, 2021, S&P upgraded the ~~event~~Company’s bond rating to BB, which will have the effect of ~~future downgrades,~~decreasing the ~~coupons for this series of notes have been capped at 6.95%.~~interest rate on the 2025 Notes to 6.20% beginning with coupon payments paid after January 2022.

In the first ~~quarter~~half of 2020, the Company repurchased $3$6 million of its 4.10% Senior Notes due 2022, ~~$28~~$36 million of its 4.95% Senior Notes due 2025, ~~$18~~$21 million of its 7.50% Senior Notes due 2026 and ~~$31~~$44 million of its 7.75% Senior Notes due 2027 for ~~$52~~$72 million, and recognized a ~~$28~~$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 credit facility, were utilized to fund a redemption of $510 million of Montage’s Notes in connection with the closing of the Montage Merger.

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

~~Table~~On August 30, 2021, Southwestern closed its public offering of ~~Contents~~$1,200 million aggregate principal amount of its 5.375% Senior Notes due 2030 (the “2030 Notes”), with net proceeds from the offering totaling $1,183 million after underwriting discounts and offering expenses. The proceeds were used to repurchase the remaining $618 million of the Company’s 7.50% Senior Notes due 2026, $167 million of the Company’s 4.95% Senior Notes due 2025 and $6 million of the Company’s 4.10% Senior Notes due 2022 for $844 million, and the Company recognized a $59 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.

(12) COMMITMENTS AND CONTINGENCIES

Operating Commitments and Contingencies

As of ~~March 31,~~September 30, 2021, 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 ~~$8.4~~$9.8 billion, ~~$436~~$382 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 ~~$908~~$884 million of that total amount. As of ~~March 31,~~September 30, 2021, 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	$	7,915	$	789	$	1,539	$	1,295	$	1,752	$	2,540	Infrastructure currently in service	$	9,415	$	903	$	1,965	$	1,677	$	2,115	$	2,755
Pending regulatory approval and/or construction (1)	Pending regulatory approval and/or construction (1)	436		2		30		38		81		285		Pending regulatory approval and/or construction (1)	382		2		18		27		57		278
Total transportation charges	Total transportation charges	$	8,351	$	791	$	1,569	$	1,333	$	1,833	$	2,825	Total transportation charges	$	9,797	$	905	$	1,983	$	1,704	$	2,172	$	3,033

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

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Prior to the Indigo Merger, in May 2021, Indigo closed on an agreement to divest its Cotton Valley natural gas and oil properties. Indigo retained certain contractual commitments related to volume commitments associated with natural gas gathering, for which Southwestern will assume the obligation to pay the gathering provider for any unused portion of the volume commitment under the agreement through 2027, depending on the buyer’s actual use. As of September 30, 2021, up to approximately $34 million of these contractual commitments remain (included in the table above), and the Company has recorded a $17 million liability for our portion of the estimated future payments.

Environmental Risk

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

Litigation

The Company is subject to various litigation, claims and proceedings, most of which have arisen in the ordinary course of business, such as for alleged breaches of contract, miscalculation of royalties, employment matters, traffic accidents, pollution, contamination, encroachment on others’ property or nuisance. The Company accrues for litigation, claims and proceedings when a liability is both probable and the amount can be reasonably estimated. As of ~~March 31,~~September 30, 2021, 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

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

Bryant Litigation

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

On June 12, 2018, a collection of 51 individuals and entities filed a lawsuit against 15 oil and gas company defendants, including Indigo, in Louisiana state court claiming damages arising out of current and historical exploration and production activity on certain acreage located in DeSoto Parish, Louisiana. The plaintiffs, who claim to own the properties at issue, assert that Indigo’s actions and the actions of other current operators conducting exploration and production activity, combined with the improper plugging and abandoning of legacy wells by former operators, have caused environmental contamination to their properties. Among other things, the plaintiffs contend that the defendants’ conduct resulted in the migration of natural gas, along with oilfield contaminants, into ~~account. Additionally, it is not possible at this time to estimate~~ the ~~amount~~Carrizo-Wilcox aquifer system underlying certain portions of ~~any additional loss, or range of loss, that is reasonably possible.~~DeSoto Parish. The

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plaintiffs assert claims based in tort, breach of contract and for violations of the Louisiana Civil and Mineral Codes, and they seek injunctive relief and monetary damages in an unspecified amount, including punitive damages.

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

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

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

Indemnifications

The Company has provided certain indemnifications to various third parties, including in relation to asset and entity dispositions, securities offerings and other financings, and litigation, such as the St. Lucie County Fire District Firefighters’ Pension Trust case described above. 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 nine months ended ~~March 31,~~September 30, 2021. The effective tax rate for the three and nine months ~~ended March 31,~~September 30, 2021 related to the effects of a valuation allowance against the Company’s U.S. deferred tax assets. A valuation allowance for deferred tax assets, including net operating losses, is recognized when it is more likely than not that some or all of the benefit from the deferred tax assets will not be realized. To assess that likelihood, the Company uses estimates and judgment regarding future taxable income, and considers the tax consequences in the jurisdiction where such taxable income is generated, to determine whether a valuation allowance is required. Such evidence can include current financial position, results of operations, both actual and forecasted, the reversal of deferred tax liabilities and tax planning strategies as well as current and forecasted business economics of the oil and gas industry.

In ~~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, the Company concluded that it was more likely than not that these deferred tax assets will not be realized and recorded a ~~discrete tax expense of $408 million for the increase in its~~ valuation allowance. ~~The net change in~~As of the third quarter of 2021, the Company still maintains a full valuation ~~allowance is reflected as a component of income tax expense.~~allowance. The Company also retained a valuation allowance of $87 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’s effective tax rate was approximately ~~(36)~~0% and (16)% for the three and nine months ended ~~March 31, 2020.~~September 30, 2020, respectively. The effective tax rate for the ~~three~~nine months ended ~~March 31,~~September 30, 2020 was primarily the effect of recording the valuation allowance discussed above.

Due to the issuance of common stock associated with the Indigo Merger, as discussed in Note 2, the Company incurred a cumulative ownership change and as such, the Company’s net operating losses (“NOLs”) prior to the acquisition are subject to an annual limitation under Internal Revenue Code Section 382 of approximately $48 million. The ownership changes and resulting annual limitation will result in the expiration of NOLs or other tax attributes otherwise available, with a corresponding decrease in the Company’s valuation allowance. At September 30, 2021, the Company had approximately $4.5 billion of federal NOL carryovers, of which approximately $3 billion expire between 2035 and 2037 and $1.5 billion have an indefinite carryforward life. The Company currently estimates that approximately $2 billion of these federal NOLs will expire before they are able to be used. The non-expiring NOLs remain subject to a full valuation allowance. If a subsequent ownership

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

The Company adopted Accounting Standards Update No. 2019-12 (“ASU 2019-12”) in the current period. ASU 2019-12 addressed simplification to income tax accounting rules, such as removing a few exceptions to intraperiod allocation. There was no material impact to the financial statements as a result of this adoption.

(14) PENSION PLAN AND OTHER POSTRETIREMENT BENEFITS

The Company maintains defined pension and other postretirement benefit plans, which cover substantially all of the Company’s employees. As part of 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 to receive ~~the~~an interest ~~component of~~credit to their benefit under the plan but will no longer receive a benefit accrual for additional years of service due to the ~~service component.~~ plan freeze.

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

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


		Consolidated Statements of Operations Classification of Net Periodic Benefit Cost	For the three months ended March 31,			Consolidated Statements of Operations Classification of Net Periodic Benefit Cost					For the three months ended September 30,			For the nine months ended September 30,
(in millions)	(in millions)			2021					2020	(in millions)	Consolidated Statements of Operations Classification of Net Periodic Benefit Cost	2021		2020		2021		2020
Service cost	Service cost	General and administrative expenses		$	0		$	2		Service cost		$	—	$	2	$	—	$	6
Interest cost	Interest cost	Other Income (Loss), Net		1			1			Interest cost	Other Income (Loss), Net	1		1		3		3
Expected return on plan assets	Expected return on plan assets	Other Income (Loss), Net		(1)			(1)			Expected return on plan assets	Other Income (Loss), Net	—		(2)		(3)		(5)

Amortization of net loss										Amortization of net loss	Other Income (Loss), Net	—		1		—		1
Settlement loss										Settlement loss	Other Income (Loss), Net	—		—		1		—
Net periodic benefit cost	Net periodic benefit cost			$	0		$	2		Net periodic benefit cost		$	1	$	2	$	1	$	5

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

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

As of ~~March 31,~~September 30, 2021, the Company has contributed $5 $12 million to the pension and other postretirement benefit plans and ~~expects~~does not expect to ~~contribute an~~make any additional ~~$7 million~~contributions to its pension plan during the remainder of ~~2021.~~2021 or thereafter until the plan termination is completed. The Company recognized liabilities of ~~$28~~$17 million and ~~$13~~$14 million related to its pension and other postretirement benefits, respectively, as of ~~March 31,~~September 30, 2021, compared to liabilities of $33 million and $13 million as of December 31, 2020, respectively.

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

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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. The Company issues shares of restricted stock, restricted stock units or 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.

In February of 2021 and 2020, the Company notified employees of workforce reduction plans as a result of strategic realignments of the Company’s organizational structure. ~~Theses~~These reductions were substantially complete by the end of the first quarter of each respective year. Affected employees were offered a severance package which, if applicable, included the current value of unvested long-term incentive awards that were forfeited.

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


		For the three months ended March 31,			For the three months ended September 30,						For the nine months ended September 30,
(in millions)	(in millions)		2021			2020		(in millions)	2021		2020		2021		2020
Stock-based compensation cost – expensed	Stock-based compensation cost – expensed		$	13		$	0	Stock-based compensation cost – expensed	$	5	$	2	$	27	$	8
Stock-based compensation cost – capitalized	Stock-based compensation cost – capitalized		5			0		Stock-based compensation cost – capitalized	2		2		12		3

Equity-Classified Awards

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


		For the three months ended March 31,			For the three months ended September 30,						For the nine months ended September 30,
(in millions)	(in millions)		2021			2020		(in millions)	2021		2020		2021		2020
Equity-classified awards – expensed	Equity-classified awards – expensed		$	0		$	1	Equity-classified awards – expensed	$	—	$	—	$	2	$	2
Equity-classified awards – capitalized	Equity-classified awards – capitalized		0			0		Equity-classified awards – capitalized	—		1		—		1

As of ~~March 31,~~September 30, 2021, there was less than $1 million of total unrecognized compensation cost related to the Company’s unvested equity-classified stock option grants, equity-classified restricted stock grants and equity-classified performance units. This cost is expected to be recognized over a weighted-average period of ~~1.0 year.~~1.8 years.

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Equity-Classified Stock Options

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


		Number of Options	Weighted Average Exercise Price			Number of Options	Weighted Average Exercise Price
		(in thousands)				(in thousands)
Outstanding at December 31, 2020	Outstanding at December 31, 2020	3,850	$	13.39	Outstanding at December 31, 2020	3,850	$	13.39
Granted	Granted	0	$	0	Granted	—	$	—
Exercised	Exercised	0	$	0	Exercised	—	$	—
Forfeited or expired	Forfeited or expired	(61)	$	10.93	Forfeited or expired	(151)	$	32.21
Outstanding at March 31, 2021		3,789	$	13.43
Exercisable at March 31, 2021		3,789	$	13.43
Outstanding at September 30, 2021					Outstanding at September 30, 2021	3,699	$	12.63
Exercisable at September 30, 2021					Exercisable at September 30, 2021	3,699	$	12.63

Equity-Classified Restricted Stock

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


		Number of Shares	Weighted Average Fair Value			Number of Shares	Weighted Average Fair Value
		(in thousands)				(in thousands)
Unvested shares at December 31, 2020	Unvested shares at December 31, 2020	697	$	5.97	Unvested shares at December 31, 2020	697	$	5.97
Granted	Granted	10	$	2.98	Granted	438	$	5.18
Vested	Vested	(451)	$	7.61	Vested	(893)	$	5.81
Forfeited	Forfeited	0	$	8.59	Forfeited	—	$	8.59
Unvested shares at March 31, 2021		256	$	2.94
Unvested shares at September 30, 2021					Unvested shares at September 30, 2021	242	$	5.12

Equity-Classified Restricted Stock Units

As a result of the Montage Merger, ~~with Montage,~~ certain employees became employees of Southwestern and retained their original equity awards. The following table summarizes equity-classified performance unit activity for the ~~three~~nine months ended ~~March 31,~~September 30, 2021 and provides information for unvested units as of ~~March 31,~~September 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	Unvested units at December 31, 2020	134	$	3.05	Unvested units at December 31, 2020	134	$	3.05
Granted	Granted	0	0		Granted	—	$	—
Vested	Vested	(45)	3.05		Vested	(87)	$	3.05
Forfeited	Forfeited	0	0		Forfeited	—	$	—
Unvested Units at March 31, 2021		89	3.05
Unvested units at September 30, 2021					Unvested units at September 30, 2021	47	$	3.05

Liability-Classified Awards

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


		For the three months ended March 31,			For the three months ended September 30,						For the nine months ended September 30,
(in millions)	(in millions)		2021			2020		(in millions)	2021		2020		2021		2020
Liability-classified stock-based compensation cost – expensed	Liability-classified stock-based compensation cost – expensed		$	13		$	(1)	Liability-classified stock-based compensation cost – expensed	$	5	$	2	$	25	$	6
Liability-classified stock-based compensation cost – capitalized	Liability-classified stock-based compensation cost – capitalized		5			0		Liability-classified stock-based compensation cost – capitalized	2		1		12		2

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Liability-Classified Restricted Stock Units

In the first quarter of each year beginning with 2018, the Company granted restricted stock units that vest over a period of four years and are payable in either cash or shares at the option of the Compensation Committee of the Company’s Board of Directors. The awards granted in 2021 vest over a period of three years. The Company has accounted for these as liability-classified awards, and accordingly changes in the market value of the instruments will be recorded to general and administrative expense and capitalized expense over the vesting period of the award. As of ~~March 31,~~September 30, 2021, there was ~~$32~~$27 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 ~~2.2~~1.1 years. The amount of unrecognized compensation cost for liability-classified awards will fluctuate over time as they are marked to market.


		Number of Units	Weighted Average Fair Value			Number of Units	Weighted Average Fair Value
		(in thousands)				(in thousands)
Unvested units at December 31, 2020	Unvested units at December 31, 2020	11,613	$	2.67	Unvested units at December 31, 2020	11,613	$	2.67
Granted	Granted	1,486	$	4.23	Granted	1,486	$	4.23
Vested	Vested	(4,522)	$	3.40	Vested	(4,522)	$	3.40
Forfeited	Forfeited	(416)	$	4.31	Forfeited	(592)	$	4.55
Unvested units at March 31, 2021		8,161	$	4.07
Unvested units at September 30, 2021					Unvested units at September 30, 2021	7,985	$	4.80

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 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, 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 ~~quarter~~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. The fair values of the market conditions are calculated by Monte Carlo models on a quarterly basis. As of ~~March 31,~~September 30, 2021, there was ~~$22~~$20 million of total unrecognized compensation cost related to liability-classified performance units. This cost is expected to be recognized over a weighted-average period of ~~2.1~~1.8 years. The amount of unrecognized compensation cost for liability-classified awards will fluctuate over time as they are marked to market. The final value of the performance unit awards is contingent upon the Company’s actual performance against these performance measures.


		Number of Units	Weighted Average Fair Value			Number of Units	Weighted Average Fair Value
		(in thousands)				(in thousands)
Unvested units at December 31, 2020	Unvested units at December 31, 2020	8,699	$	2.57	Unvested units at December 31, 2020	8,699	$	2.57
Granted	Granted	3,580	$	4.14	Granted	3,580	$	4.14
Vested	Vested	(2,020)	$	4.05	Vested	(2,020)	$	4.05
Forfeited	Forfeited	(622)	$	2.98	Forfeited	(744)	$	3.40
Unvested units at March 31, 2021		9,637	$	2.88
Unvested units at September 30, 2021					Unvested units at September 30, 2021	9,515	$	3.32

Cash-Based Compensation

Performance Cash Awards

In 2021 and 2020, the Company granted performance cash awards that vest over a four-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 ~~March 31,~~September 30, 2021, there was ~~$30~~$24 million of total unrecognized compensation cost related to performance cash awards. This cost is expected to be

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recognized over a weighted average ~~3.5~~3.0 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	Unvested units at December 31, 2020	18,353	$	1.00	Unvested units at December 31, 2020	18,353	$	1.00
Granted	Granted	18,546	$	1.00	Granted	18,546	$	1.00
Vested	Vested	(4,319)	$	1.00	Vested	(4,955)	$	1.00
Forfeited	Forfeited	(1,615)	$	1.00	Forfeited	(3,008)	$	1.00
Unvested units at March 31, 2021		30,965	$	1.00
Unvested units at September 30, 2021					Unvested units at September 30, 2021	28,936	$	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. 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 Annual Report. Management evaluates the performance of its segments based on operating income, defined as operating revenues less operating costs. Income before income taxes, for the purpose of reconciling the operating income amount shown below to consolidated income before income taxes, is the sum of operating income, interest expense, gain (loss) on derivatives, gain on early extinguishment of debt and other income (loss). The “Other” column includes items not related to the Company’s reportable segments, including real estate and corporate items. Corporate general and administrative costs, depreciation expense and taxes, other than income taxes, are allocated to the segments.


		E&P			Marketing		Other		Total			E&P			Marketing		Other		Total

Three months ended March 31, 2021		(in millions)
Three months ended September 30, 2021											Three months ended September 30, 2021	(in millions)
Revenues from external customers	Revenues from external customers	$	719		$	353	$	0	$	1,072	Revenues from external customers	$	1,179		$	419	$	—	$	1,598
Intersegment revenues	Intersegment revenues	(14)			644		0		630		Intersegment revenues	(14)			947		—		933
Depreciation, depletion and amortization expense	Depreciation, depletion and amortization expense	94			2		0		96		Depreciation, depletion and amortization expense	136			2		—		138
Impairments											Impairments	6			—		—		6
Operating income											Operating income	628		(1)	8		—		636
Interest expense (2)											Interest expense (2)	34			—		—		34
Loss on derivatives											Loss on derivatives	(2,398)			—		(1)		(2,399)
Loss on extinguishment of debt											Loss on extinguishment of debt	—			—		(59)		(59)
Other loss, net											Other loss, net	(1)			—		—		(1)

Operating income		295		(1)	6		0		301
Assets											Assets	8,572		(3)	546		123		9,241
Capital investments (4)											Capital investments (4)	291			—		—		291

Three months ended September 30, 2020											Three months ended September 30, 2020
Revenues from external customers											Revenues from external customers	$	308		$	219	$	—	$	527
Intersegment revenues											Intersegment revenues	(10)			276		—		266
Depreciation, depletion and amortization expense											Depreciation, depletion and amortization expense	68			2		—		70
Impairments											Impairments	361			—		—		361
Operating loss											Operating loss	(379)		(1)	(2)		—		(381)
Interest expense (2)	Interest expense (2)	31			0		0		31		Interest expense (2)	22			—		—		22
Loss on derivatives	Loss on derivatives	(191)			0		0		(191)		Loss on derivatives	(192)			—		—		(192)

Other income, net	Other income, net	1			0		0		1		Other income, net	2			—		—		2

Assets	Assets	4,741		(3)	396		110		5,247		Assets	3,705		(3)	240		212		4,157
Capital investments (4)	Capital investments (4)	266			0		0		266		Capital investments (4)	223			—		—		223

Three months ended March 31, 2020
Revenues from external customers		$	353		$	239	$	0	$	592
Intersegment revenues		(9)			309		0		300
Depreciation, depletion and amortization expense		111			2		0		113
Impairments		1,479			0		0		1,479
Operating loss		(1,486)		(1)	(4)		0		(1,490)
Interest expense (2)		19			0		0		19
Gain on derivatives		339			0		0		339
Gain on early extinguishment of debt		0			0		28		28
Other income, net		1			0		0		1
Benefit from income taxes (2)		406			0		0		406
Assets		4,900		(3)	214		161		5,275
Capital investments (4)		237			0		0		237

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	E&P			Marketing		Other		Total

Nine months ended September 30, 2021	(in millions)
Revenues from external customers	$	2,616		$	1,104	$	—	$	3,720
Intersegment revenues	(42)			2,242		—		2,200
Depreciation, depletion and amortization expense	327			7		—		334
Impairments	6			—		—		6
Operating income	1,209		(1)	21		—		1,230
Interest expense (2)	95			—		—		95
Loss on derivatives	(3,461)			—		—		(3,461)
Loss on early extinguishment of debt	—			—		(59)		(59)
Other loss, net	(1)			—		—		(1)

Assets	8,572		(3)	546		123		9,241
Capital investments (4)	816			—		—		816

Nine months ended September 30, 2020
Revenues from external customers	$	884		$	645	$	—	$	1,529
Intersegment revenues	(31)			787		—		756
Depreciation, depletion and amortization expense	260			7		—		267
Impairments	2,495			—		—		2,495
Operating loss	(2,613)		(1)	(14)		—		(2,627)
Interest expense (2)	63			—		—		63
Gain on derivatives	38			—		—		38
Gain on early extinguishment of debt	—			—		35		35
Other income, net	2			—		1		3
Benefit from income taxes (2)	406			—		—		406
Assets	3,705		(3)	240		212		4,157
Capital investments (4)	705			—		—		705

(1)Operating income (loss) for the E&P segment includes $6$7 million and ~~$10~~$12 million of restructuring charges for the ~~three~~nine months ended ~~March 31,~~September 30, 2021 and 2020, respectively. The E&P segment operating income (loss) also includes $1$35 million ~~of merger-related charges~~and $3 million for the three months ended ~~March 31, 2021.~~September 30, 2021 and 2020, respectively, and $39 million and $3 million for the nine months ended September 30, 2021 and 2020, respectively, for merger-related expenses.

(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. ~~E&P assets also includes deferred tax assets which are an allocation of corporate amounts as they are incurred at the corporate level.~~

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(4)Capital investments ~~include increases~~includes an increase of ~~$38~~$34 million and $8a decrease of $7 million for the three months ended ~~March 31,~~September 30, 2021 and 2020, respectively, and increases of $63 million and $1 million for the nine months ended September 30, 2021 and 2020, respectively, relating to the change in accrued expenditures between periods.

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


		As of March 31,					As of September 30,
(in millions)	(in millions)	2021		2020		(in millions)	2021		2020
Cash and cash equivalents	Cash and cash equivalents	$	4	$	5	Cash and cash equivalents	$	12	$	95
Accounts receivable						Accounts receivable	4		7

Income taxes receivable		0		32

Prepayments	Prepayments	6		9		Prepayments	13		3
Property, plant and equipment	Property, plant and equipment	15		23		Property, plant and equipment	12		18
Unamortized debt expense	Unamortized debt expense	11		10		Unamortized debt expense	10		10
Right-of-use lease assets	Right-of-use lease assets	70		77		Right-of-use lease assets	67		74
Non-qualified retirement plan	Non-qualified retirement plan	4		5		Non-qualified retirement plan	4		5
Long-term hedging asset (interest rate swaps)						Long-term hedging asset (interest rate swaps)	1		—
		$	110	$	161		$	123	$	212

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(17) NEW ACCOUNTING PRONOUNCEMENTS

New Accounting Standards Implemented in this Report

In August 2018, the Financial Accounting Standards Board (the “FASB”) issued ASU 2018-14, Disclosure Framework – Changes to the Disclosure Requirements for Defined Benefit Plans ("(“ASU ~~2018-14"~~2018-14”). ASU 2018-14 amends, adds and removes certain disclosure requirements under FASB ASC Topic 715 – Compensation – Retirement Benefits. The guidance in ASU 2018-14 is effective for fiscal years beginning after December 15, 2020 and was adopted on January 1, 2021. Adoption of ASU 2018-14 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 consolidated financial statements.

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

New Accounting Standards Not Yet Adopted in this Report

In March 2020, the FASB issued ASU 2020-04, Reference Rate Reform, as a new ASC Topic, ASC 848. The purpose of ASC 848 is to provide optional guidance to ease the potential effects on financial reporting of the market-wide migration away from Interbank Offered Rates, such as LIBOR, which is expected to be phased out at the end of calendar year 2021, to alternative reference rates. ASC 848 applies only to contracts, hedging relationships, debt arrangements and other 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 ASU 2020-04 are effective for all entities as of March 12, 2020 through December 31, 2022.

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

(18)SUBSEQUENT EVENTS

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

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 Annual Report and analyzes the changes in the results of operations between the three and nine month periods ended ~~March 31,~~September 30, 2021 and 2020. 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 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

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

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OVERVIEW

Background

Southwestern Energy Company (including its subsidiaries, collectively, “we,” “our,” “us,” “the Company” or “Southwestern”) is an independent energy company engaged in natural gas, oil and ~~NGLs~~natural gas liquids (“NGLs”) 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.” We conduct most of our businesses through subsidiaries, and we currently operate exclusively in the lower 48 United States.

E&P. Our primary business is the exploration for 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 are herein referred~~Louisiana, which we refer to as ~~“Appalachia.~~“Haynesville,” primarily focuses on the Haynesville and Bossier natural gas reservoirs. We also have drilling rigs located in Appalachia, and we provide certain oilfield products and services, principally serving our E&P operations through vertical integration.

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

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

On November 13, 2020, we closed on 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 ~~“Merger”~~“Montage Merger”). The Montage Merger ~~expanded~~increased our footprint in ~~Appalachia by supplementing our Northeast Appalachia~~West Virginia and ~~Southwest Appalachia operations~~Pennsylvania and ~~by expanding~~expanded our operations into Ohio. See Note 2 to the consolidated financial statements of this Quarterly Report for more information on the Montage Merger.

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

Recent Financial and Operating Results

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

Total Company

•Net ~~income~~loss of ~~$80~~$1,857 million, or ~~$0.12~~($2.36) per diluted share, increased compared to net loss of ~~$1,547~~$593 million, or ($~~2.86)~~1.04) per diluted share, for the same period in 2020. ~~The~~Net loss increased as a $1,017 million increase in operating income was ~~primarily due to~~more than offset by a ~~$1,479~~$2,207 million reduction resulting from the impact of improved forward pricing on our derivatives position, $1,722 million of which was unrealized. Excluding the change in derivatives position and $361 million non-cash full cost ceiling test impairment recorded in the ~~first quarter~~third quarters of ~~2020. Excluding the impact of the impairment,~~2021 and 2020, respectively, net income increased ~~$148~~$582 million in the ~~first~~third quarter of 2021, compared to the same period in 2020, primarily as a ~~$406 million improvement in income tax expense and a $312~~$656 million improvement in operating income was partially offset by a ~~$530~~$59 million ~~reduction~~loss on the early extinguishment of debt recorded in ~~our derivative position, $415 million~~the third quarter of ~~which was unrealized, resulting from an improved forward-pricing strip,~~2021 and a $12 million increase in interest expense. ~~The first quarter~~

Table of ~~2020 also included a $28 million gain on the early extinguishment of debt.~~Contents

•Operating income of ~~$301~~$636 million increased compared to operating loss of ~~$1,490~~$381 million for the same period in 2020 on a consolidated basis. Operating loss in the third quarter of 2020 included a ~~$1,479~~$361 million non-cash full cost ceiling test ~~impairment in the first quarter of 2020.~~impairment. Excluding the non-cash impairment, operating income ~~of $301 million~~ improved ~~$312~~$656 million, compared to the same period in 2020, as a ~~$480~~$1,071 million increase in operating revenues more than offset a ~~$168~~$415 million increase in operating costs, primarily associated with increased production, and expenses.

•Net cash provided by operating activities of ~~$347~~$213 million increased ~~117%~~39% from ~~$160~~$153 million for the same period in 2020 as the effects of improved commodity pricing and higher production were only partially offset by a decrease in settled derivatives combined with an increase in operating expenses associated with higher liquids production.

•Total capital investment of ~~$266~~$291 million in the third quarter of 2021 increased ~~12%~~30% from ~~$237~~$223 million for the same period in 2020.

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

E&P

•E&P segment operating ~~income of $295 million increased from an operating~~ loss of ~~$1,486~~$379 million for the ~~same period in~~third quarter of 2020 ~~primarily related to the~~included a non-cash full cost ceiling test impairment of ~~$1,479 million in the first quarter of 2020.~~$361 million. Excluding the non-cash impairment, E&P operating income of $628 million in the third quarter of 2021 increased ~~$302~~$646 million, compared to the same period in 2020, primarily as ~~a $361~~an $867 million increase in E&P operating revenues resulting from a ~~$0.93~~$2.40 per Mcfe increase in our realized weighted average price per Mcfe (excluding derivatives) and ~~a 68~~an 89 Bcfe increase in production volumes was only partially offset by a ~~$59~~$221 million increase in E&P operating costs and expenses.

•Total net production of ~~269~~310 Bcfe, which was comprised of ~~79%~~81% natural gas and ~~21%~~19% oil and NGLs, increased ~~34%~~40% from ~~201~~221 Bcfe in the same period in 2020, primarily due to a ~~37%~~45% increase in our natural gas production, ~~26%~~46% and 39% of which was associated with natural gas production from our Montage Merger- and Indigo Merger-related properties acquired in November ~~2020.~~2020 and September 2021, respectively.

•Excluding the effect of derivatives, our realized natural gas price of ~~$2.11~~$3.18 per Mcf increased ~~38%~~192%, our realized oil price of ~~$48.14~~$62.32 per barrel increased ~~31%~~112% and our realized NGL price of ~~$22.86~~$31.76 per barrel increased ~~180%~~207%, as compared to the same period in 2020. Excluding the effect of derivatives, our total weighted average realized price of ~~$2.62~~$3.74 per Mcfe increased ~~55%~~179% from the same period in 2020.

•E&P segment invested ~~$266~~$291 million in capital; drilling 2317 wells, completing 2923 wells and placing 1724 wells to sales.

Outlook

Our primary focus in 2021 is to strengthen the balance sheet 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 ~~Merger with~~ Montage and Indigo mergers while further developing our knowledge of our asset base.

•Generating Free Cash Flow. We expect to generate cash flow from operations, net of changes in working capital, in excess of our expected capital investments, which are designed 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 ~~the~~ free cash flow generated in 2021 to pay down our debt, further strengthen our balance sheet and progress towards our lower leverage targets.

•Building Scale. We will continue to seek opportunities to leverage our operational expertise of integrating and developing large-scale assets to expand our portfolio, create economies of scale and increase optionality in our operations and our capital investment program.

We believe that we and our industry will continue to face challenges due to 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 and elsewhere in our 2020 Annual Report.

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COVID-19

During the first ~~quarter~~three quarters of 2021, 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 continue to monitor the 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 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 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 on early extinguishment of debt and income taxes are discussed on a consolidated basis.

E&P


		For the three months ended March 31,						For the three months ended September 30,						For the nine months ended September 30,
(in millions)	(in millions)		2021			2020				(in millions)	2021			2020			2021			2020
Revenues	Revenues		$	705		$	344			Revenues	$	1,165		$	298		$	2,574		$	853
Operating costs and expenses	Operating costs and expenses		410		(1)	1,830			(2)	Operating costs and expenses	537		(1)	677		(2)	1,365		(1)	3,466		(2)
Operating income (loss)	Operating income (loss)		$	295		$	(1,486)			Operating income (loss)	$	628		$	(379)		$	1,209		$	(2,613)

Gain (loss) on derivatives, settled	Gain (loss) on derivatives, settled		$	(22)		$	93			Gain (loss) on derivatives, settled	$	(388)		$	97		$	(509)		$	310

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

(2)Includes ~~$1,479~~$361 million and $2,490 million related to non-cash full cost ceiling test impairments for the three and ~~$10~~nine months ended September 30, 2020, respectively, $12 million in restructuring charges for the ~~three~~nine months ended ~~March 31,~~September 30, 2020 and $5 million related to the non-cash impairment of other non-core assets for the nine months ended September 30, 2020.

Operating Income (Loss)

•E&P segment operating income increased ~~$1,781~~$1,007 million for the three months ended ~~March 31,~~September 30, 2021, compared to the same period in 2020. The operating loss for the ~~first~~third quarter of 2020 included a ~~$1,479~~$361 million non-cash full cost ceiling test impairment. Excluding the effect of the impairment, operating income improved ~~$302~~$646 million, compared to the same period in 2020, as an $867 million increase in E&P operating revenues resulting from a 179% increase in our realized weighted average price per Mcfe (excluding derivatives) and a 40% increase in production volumes was only partially offset by a $221 million increase in E&P operating costs and expenses.

•Operating income for the E&P segment increased $3,822 million for the nine months ended September 30, 2021 compared to the same period in 2020. The operating loss for the nine months ended September 30, 2020 included a $2,490 million non-cash full cost ceiling test impairment. Excluding the effect of the impairment, operating income improved $1,332 million, compared to the same period in 2020, as a ~~$361~~$1,721 million increase in E&P operating revenues resulting from a ~~55%~~121% increase in our realized weighted average price per Mcfe (excluding derivatives) and a 37% increase in production volumes was only partially offset by a ~~$59~~$389 million increase in E&P operating costs and expenses.

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Revenues

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


		Three months ended March 31,													Three months ended September 30,
(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)	2020 sales revenues (1)	$	239		$	52		$	50		$	341		2020 sales revenues (1)	$	190		$	39		$	68		$	297
Changes associated with prices	Changes associated with prices	123			18			111			252			Changes associated with prices	524			56			173			753
Changes associated with production volumes	Changes associated with production volumes	89			10			12			111			Changes associated with production volumes	85			13			14			112
2021 sales revenues (2)	2021 sales revenues (2)	$	451		$	80		$	173		$	704		2021 sales revenues (2)	$	799		$	108		$	255		$	1,162
Increase from 2020	Increase from 2020	89		%	54		%	246		%	106		%	Increase from 2020	321		%	177		%	275		%	291		%

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

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


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

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

(2)Excludes $1$4 million in other operating revenues for the ~~three~~nine months ended ~~March 31,~~September 30, 2021 primarily related to gains on purchaser imbalances associated with certain NGLs.

3645

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Production Volumes


		For the three months ended March 31,					Increase/(Decrease)			For the three months ended September 30,				Increase/(Decrease)		For the nine months ended September 30,					Increase/(Decrease)
Production volumes:	Production volumes:		2021			2020					Production volumes:	2021				Increase/(Decrease)			2021					Increase/(Decrease)
Natural Gas (Bcf)	Natural Gas (Bcf)												Natural Gas (Bcf)
Northeast Appalachia				118			114		4%
Southwest Appalachia				96			42		129%
Appalachia													Appalachia	221				173		28%			654			487		34%
Haynesville													Haynesville	30		—			100%		30			—			100%

Total	Total			214			156		37%				Total	251		173			45%		684			487			40%

Oil (MBbls)	Oil (MBbls)												Oil (MBbls)
Southwest Appalachia				1,658			1,395		19%
Appalachia													Appalachia	1,722		1,290			33%		5,206			3,764			38%
Haynesville													Haynesville	2		—			100%		2			—			100%
Other	Other			4			4		—%				Other	5		4			25%		14			12			17%
Total	Total			1,662			1,399		19%				Total	1,729		1,294			34%		5,222			3,776			38%

NGL (MBbls)	NGL (MBbls)												NGL (MBbls)
Southwest Appalachia				7,577			6,127		24%
Appalachia													Appalachia	8,011		6,687			20%		23,253			18,924			23%
Other	Other			1			1		—%				Other	—		—			—%		2			2			—%
Total	Total			7,578			6,128		24%				Total	8,011		6,687			20%		23,255			18,926			23%

Production volumes by area: (Bcfe)	Production volumes by area: (Bcfe)												Production volumes by area: (Bcfe)
Northeast Appalachia				118			114		4%
Southwest Appalachia				151			87		74%
Appalachia													Appalachia	280		221			27%		825			623			32%
Haynesville													Haynesville	30		—			100%		30			—			100%

Total (1)				269			201		34%
Total													Total	310		221			40%		855			623			37%

Production percentage: (Bcfe)
Production volumes by formation: (Bcfe)													Production volumes by formation: (Bcfe)
Marcellus Shale													Marcellus Shale	245		221			11%		700			622			13%
Utica Shale (1)													Utica Shale (1)	34		—			100%		124			1			12,300%
Haynesville Shale													Haynesville Shale	16		—			100%		16			—			100%
Bossier Shale													Bossier Shale	14		—			100%		14			—			100%
Other													Other	1		—			100%		1			—			100%
Total													Total	310		221			40%		855			623			37%

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

(1)~~Approximately 213 Bcfe and 201 Bcfe for~~Prior to the ~~three months ended March 31, 2021 and~~Montage Merger in November 2020, ~~respectively, were produced~~our production from the ~~Marcellus~~Utica Shale ~~formation.~~was immaterial.

•E&P production volumes increased by 6889 Bcfe for the three months ended ~~March 31,~~September 30, 2021, compared to the same period in 2020, primarily due to incremental production volumes of 4842 Bcfe associated with ~~our~~the properties acquired from Montage in November 2020 and 30 Bcfe associated with the recently acquired Indigo properties.

•E&P production volumes increased by 232 Bcfe for the nine months ended September 30, 2021, compared to the same period in 2020, primarily due to incremental production volumes of 134 Bcfe associated with the properties acquired from Montage ~~properties, of which 47~~in November 2020 and 30 Bcfe ~~is reflected in Southwest Appalachia and 1 Bcfe is reflected in Northeast Appalachia.~~associated with the recently acquired Indigo properties.

•Oil and NGL production increased ~~19%~~34% and ~~24%~~20%, respectively, for the three months ended ~~March 31,~~September 30, 2021, compared to the same period in 2020. Production volumes associated with the ~~recently~~properties acquired from Montage ~~properties~~in November 2020 were ~~341~~260 MBbls and ~~934~~800 MBbls for oil and NGLs, respectively, for the three months ended ~~March 31,~~September 30, 2021.

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

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Commodity Prices

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

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		For the three months ended March 31,						Increase/(Decrease)				For the three months ended September 30,			Increase/(Decrease)		For the nine months ended September 30,						Increase/(Decrease)
			2021				2020						2021				Increase/(Decrease)				2021						Increase/(Decrease)
Natural Gas Price:	Natural Gas Price:													Natural Gas Price:
NYMEX Henry Hub Price ($/MMBtu) (1)	NYMEX Henry Hub Price ($/MMBtu) (1)			$	2.69			$	1.95		38%			NYMEX Henry Hub Price ($/MMBtu) (1)	$	4.01			$	1.98		103%			$	3.18			$	1.88		69%
Discount to NYMEX (2)	Discount to NYMEX (2)			(0.58)				(0.42)			38%			Discount to NYMEX (2)	(0.83)		(0.89)				(7)%		(0.74)				(0.68)				9%
Average realized gas price, excluding derivatives ($/Mcf)	Average realized gas price, excluding derivatives ($/Mcf)			$	2.11			$	1.53		38%			Average realized gas price, excluding derivatives ($/Mcf)	$	3.18	$	1.09			192%		$	2.44			$	1.20			103%
Gain on settled financial basis derivatives ($/Mcf)	Gain on settled financial basis derivatives ($/Mcf)			0.19				0.10						Gain on settled financial basis derivatives ($/Mcf)	0.11		0.12						0.11				0.06
Gain on settled commodity derivatives ($/Mcf)				0.03				0.31
Gain (loss) on settled commodity derivatives ($/Mcf)														Gain (loss) on settled commodity derivatives ($/Mcf)	(1.14)		0.31						(0.43)				0.39
Average realized gas price, including derivatives ($/Mcf)	Average realized gas price, including derivatives ($/Mcf)			$	2.33			$	1.94		20%			Average realized gas price, including derivatives ($/Mcf)	$	2.15	$	1.52			41%		$	2.12			$	1.65			28%

Oil Price:	Oil Price:													Oil Price:
WTI oil price ($/Bbl)(3)	WTI oil price ($/Bbl)(3)			$	57.84			$	46.17		25%			WTI oil price ($/Bbl)(3)	$	70.56	$	40.93			72%		$	64.82			$	38.32			69%
Discount to WTI	Discount to WTI			(9.70)				(9.45)			3%			Discount to WTI	(8.24)		(11.47)				(28)%		(8.71)				(10.12)				(14)%
Average oil price, excluding derivatives ($/Bbl)	Average oil price, excluding derivatives ($/Bbl)			$	48.14			$	36.72		31%			Average oil price, excluding derivatives ($/Bbl)	$	62.32	$	29.46			112%		$	56.11			$	28.20			99%
Gain (loss) on settled derivatives ($/Bbl)	Gain (loss) on settled derivatives ($/Bbl)			(11.17)				9.25						Gain (loss) on settled derivatives ($/Bbl)	(17.49)		17.23						(16.05)				16.77
Average oil price, including derivatives ($/Bbl)	Average oil price, including derivatives ($/Bbl)			$	36.97			$	45.97		(20)%			Average oil price, including derivatives ($/Bbl)	$	44.83	$	46.69			(4)%		$	40.06			$	44.97			(11)%

NGL Price:	NGL Price:													NGL Price:
Average realized NGL price, excluding derivatives ($/Bbl)	Average realized NGL price, excluding derivatives ($/Bbl)			$	22.86			$	8.16		180%			Average realized NGL price, excluding derivatives ($/Bbl)	$	31.76	$	10.34			207%		$	26.05			$	8.37			211%
Gain (loss) on settled derivatives ($/Bbl)	Gain (loss) on settled derivatives ($/Bbl)			(6.75)				2.62						Gain (loss) on settled derivatives ($/Bbl)	(12.45)		0.16						(8.92)				1.48
Average realized NGL price, including derivatives ($/Bbl)	Average realized NGL price, including derivatives ($/Bbl)			$	16.11			$	10.78		49%			Average realized NGL price, including derivatives ($/Bbl)	$	19.31	$	10.50			84%		$	17.13			$	9.85			74%
Percentage of WTI, excluding derivatives	Percentage of WTI, excluding derivatives			40		%		18		%				Percentage of WTI, excluding derivatives	45%		25%						40%				22%

Total Weighted Average Realized Price:	Total Weighted Average Realized Price:													Total Weighted Average Realized Price:
Excluding derivatives ($/Mcfe)	Excluding derivatives ($/Mcfe)			$	2.62			$	1.69		55%			Excluding derivatives ($/Mcfe)	$	3.74	$	1.34			179%		$	3.01			$	1.36			121%
Including derivatives ($/Mcfe)	Including derivatives ($/Mcfe)			$	2.54			$	2.16		18%			Including derivatives ($/Mcfe)	$	2.49	$	1.78			40%		$	2.41			$	1.86			30%

(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.

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 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 below presents the amount of our future natural gas production in which the basis is protected as of ~~March 31,~~September 30, 2021:


		Volume (Bcf)	Basis Differential			Volume (Bcf)	Basis Differential
Basis Swaps – Natural Gas	Basis Swaps – Natural Gas				Basis Swaps – Natural Gas
2021	2021	233	$	(0.49)	2021	71	$	(0.36)
2022	2022	220	(0.44)		2022	284	(0.38)
2023	2023	119	(0.56)		2023	197	(0.49)
2024	2024	24	(0.64)		2024	46	(0.71)
2025	2025	9	(0.64)		2025	9	(0.64)
Total	Total	605			Total	607

Physical NYMEX Sales Arrangements – Natural Gas	Physical NYMEX Sales Arrangements – Natural Gas				Physical NYMEX Sales Arrangements – Natural Gas
2021	2021	189	$	(0.40)	2021	167	$	(0.16)
2022	2022	105	(0.36)		2022	514	(0.12)
2023	2023	60	(0.35)		2023	375	(0.08)
2024	2024	24	(0.49)		2024	292	(0.06)
2025	2025	12	(0.50)		2025	252	(0.04)

2026					2026	125	0.01
2027					2027	125	0.01
2028					2028	125	0.01
2029					2029	125	0.01
2030					2030	47	—
Total	Total	390			Total	2,147

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,~~September 30, 2021:


		Remaining 2021	Full Year 2022	Full Year 2023		Remaining 2021	Full Year 2022	Full Year 2023	Full Year 2024
Natural gas (Bcf)	Natural gas (Bcf)	589	453	103	Natural gas (Bcf)	274	1,013	572	68
Oil (MBbls)	Oil (MBbls)	4,926	3,099	1,268	Oil (MBbls)	1,376	4,583	2,114	54
Ethane (MBbls)	Ethane (MBbls)	4,869	1,893	—	Ethane (MBbls)	2,630	3,496	—	—
Propane (MBbls)	Propane (MBbls)	5,443	3,028	—	Propane (MBbls)	2,107	4,776	—	—
Normal Butane (MBbls)	Normal Butane (MBbls)	1,568	888	—	Normal Butane (MBbls)	617	1,295	—	—
Natural Gasoline (MBbls)	Natural Gasoline (MBbls)	1,513	857	—	Natural Gasoline (MBbls)	635	1,256	—	—
Total financial protection on future production (Bcfe)	Total financial protection on future production (Bcfe)	699	512	111	Total financial protection on future production (Bcfe)	318	1,105	585	68

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)			For the three months ended September 30,			Increase/(Decrease)				For the nine months ended September 30,				Increase/(Decrease)
(in millions except percentages)	(in millions except percentages)		2021			2020					(in millions except percentages)	2021			2020			Increase/(Decrease)		2021		2020		Increase/(Decrease)
Lease operating expenses(1)	Lease operating expenses(1)			$	250		$	194	29%					Lease operating expenses(1)	$	297				46%		$	807			39%
General & administrative expenses	General & administrative expenses			35			23		52%					General & administrative expenses	28			27		4%		93				79		18%
Montage merger-related expenses				1			—		100%
Merger-related expenses														Merger-related expenses	35			3		1,067%		39		3			1,200%
Restructuring charges	Restructuring charges			6			10		(40)%					Restructuring charges	—			—		—%		7		12			(42)%
Taxes, other than income taxes	Taxes, other than income taxes			24			13		85%					Taxes, other than income taxes	35			15		133%		86		38			126%
Full cost pool amortization	Full cost pool amortization			90			106		(15)%					Full cost pool amortization	132			65		103%		316		248			27%
Non-full cost pool DD&A	Non-full cost pool DD&A			4			5		(20)%					Non-full cost pool DD&A	4			3		33%		11		12			(8)%
Impairments	Impairments			—			1,479		(100)%					Impairments	6			361		(98)%		6		2,495			(100)%
Total operating costs	Total operating costs			$	410		$	1,830	(78)%					Total operating costs	$	537		$	677	(21)%		$	1,365	$	3,466		(61)%

Table of Contents


		For the three months ended March 31,				Increase/			For the three months ended September 30,						Increase/			For the nine months ended September 30,				Increase/
Average unit costs per Mcfe:	Average unit costs per Mcfe:		2021			2020				(Decrease)	Average unit costs per Mcfe:	2021			2020			(Decrease)	2021			2020			(Decrease)
Lease operating expenses (1)	Lease operating expenses (1)		$	0.93		$	0.96			(3)%	Lease operating expenses (1)	$	0.95		$	0.91		4%	$	0.94		$	0.93		1%
General & administrative expenses	General & administrative expenses		$	0.13	(2)	$	0.11	(3)		18%	General & administrative expenses	$	0.09	(2)	$	0.12	(3)	(25)%	$	0.11	(2)	$	0.13	(3)	(15)%
Taxes, other than income taxes	Taxes, other than income taxes		$	0.09		$	0.07			29%	Taxes, other than income taxes	$	0.11		$	0.07		57%	$	0.10		$	0.06		67%
Full cost pool amortization	Full cost pool amortization		$	0.33		$	0.53			(38)%	Full cost pool amortization	$	0.43		$	0.29		48%	$	0.37		$	0.40		(8)%

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

(2)Excludes $6$35 million ~~in restructuring charges~~ and $1$39 million in ~~Montage~~ merger-related expenses for the three and nine months ended ~~March 31, 2021.~~

~~Table of Contents~~

~~(3)Excludes $10~~September 30, 2021, respectively, and $7 million in restructuring charges for the ~~three~~nine months ended ~~March 31,~~September 30, 2021.

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

~~Lease~~ Operating Costs and Expenses

•Lease operating expenses per Mcfe decreased $0.03 per Mcf for the three months ended March 31, 2021, compared to the same period in 2020, as a 34% increase in production volumes primarily associated with the Merger more than offset a $56 million increase in lease operating expenses. 85% of the increase in production volumes related to natural gas, which has lower operating expenses than oil or NGLs.

~~General and Administrative Expenses~~

•General and administrative expenses increased $12 million for the three months ended March 31, 2021, compared to the same period in 2020, as a result of the increase in our share price and related mark-to-market impact on the value of our share-based awards, which are accounted for as liability awards.

~~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. We recognized restructuring expense of $6 million for the three months ended months ended March 31, 2021 related to cash severance expenses, including payroll taxes.

•In February 2020, employees were notified of a workforce reduction plan as a result 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 $10 million for the three months ended months ended March 31, 2020 related to cash severance expenses, including payroll taxes.

~~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 $0.02 for the three months ended March 31, 2021, compared to the same period in 2020, primarily due to the impact of higher commodity pricing on our severance taxes.

~~Full Cost Pool Amortization~~

•Our full cost pool amortization rate decreased $0.20 per Mcfe for the three months ended March 31, 2021, as compared to the same period in 2020. The average amortization rate decreased primarily as a result of the impact of $2,825 million in non-cash full cost ceiling test impairments recorded in 2020.

•No impairment expense was recorded for the three months ended March 31, 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 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 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 Merger was based on forward strip natural gas and oil pricing existing at the date of the Merger, and we affirmed that there has not been a material decline to the fair value of these acquired assets since the Merger. The properties acquired in the Merger have an unamortized cost at March 31, 2021 of $1,102 million. Due to the improvement in commodity prices in the first quarter of 2021, we would not have recorded any impairment charge for the three months ended March 31, 2021 had we included our recently acquired Montage natural gas and oil properties.


	For the three months ended September 30,				Increase/(Decrease)	For the nine months ended September 30,				Increase/(Decrease)
(in millions except percentages)	2021		2020			2021		2020
Lease operating expenses (1)	$	297	$	203	46%	$	807	$	579	39%
General & administrative expenses	28		27		4%	93		79		18%
Merger-related expenses	35		3		1,067%	39		3		1,200%
Restructuring charges	—		—		—%	7		12		(42)%
Taxes, other than income taxes	35		15		133%	86		38		126%
Full cost pool amortization	132		65		103%	316		248		27%
Non-full cost pool DD&A	4		3		33%	11		12		(8)%
Impairments	6		361		(98)%	6		2,495		(100)%
Total operating costs	$	537	$	677	(21)%	$	1,365	$	3,466	(61)%

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~~downs that result from non-cash full cost ceiling test impairments, proceeds from the sale of properties that reduce the full cost pool~~


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

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

•(2)~~Unevaluated costs excluded from amortization were $1,488~~Excludes $35 million and ~~$1,472~~$39 million at March 31, 2021 and at December 31, 2020, respectively. The unevaluated costs excluded from amortization increased slightly as the impact of $98 million of unevaluated capital invested during the period was only partially offset by the evaluation of previously unevaluated properties totaling $83 million.

~~Impairments~~

•During the three months ended March 31, 2020, we recognized a $1,479 million non-cash full cost ceiling test impairment primarily due to decreased commodity pricing over the prior twelve months. There were no impairments in ~~the first quarter of 2021.~~

~~Marketing~~

For the three months ended March 31, Increase/
(Decrease)
(in millions except volumes and percentages) 2021 2020
Marketing revenues $ 996 $ 548 82%
Other operating revenues 1 — 100%
Marketing purchases 986 547 80%
Operating costs and expenses 5 5 —%
Operating income (loss) $ 6 $ (4) (250)%
Volumes marketed (Bcfe)
345 263 31%
Percent natural gas production marketed from affiliated E&P operations 93 % 87 %
Percent oil and NGL production marketed from affiliated E&P operations 80 % 77 %

~~Operating Income~~

•~~Marketing operating income increased $10 million~~merger-related expenses for the three and nine months ended ~~March 31,~~September 30, 2021, ~~compared to~~respectively, and $7 million in restructuring charges for the ~~same period in 2020, primarily due to a $9 million increase in the marketing margin and a $1 million increase in natural gas storage gains recorded in the first quarter of~~nine months ended September 30, 2021.

•(3)~~The margin generated from marketing activities was $10~~Excludes $3 million ~~and $1 million~~in merger-related expenses for the three and nine months ended ~~March 31, 2021~~September 30, 2020, respectively, and ~~2020, respectively. The marketing margin increased~~$12 million in restructuring charges for the ~~three~~nine months ended March 31, 2021, compared to the same period in 2020, primarily due to a 31% increase in the volumes marketed and a corresponding reduction in third-party sales and purchases used to optimize the transportation portfolio due to increased affiliated volumes available for marketing.September 30, 2020.

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~~

•For the three months ended March 31, 2021, revenues from our marketing activities increased $448 million compared to the same period in 2020, primarily due to a 39% increase in the price received for volumes marketed and a 31% increase in volumes marketed.

Operating Costs and Expenses


	For the three months ended September 30,				Increase/(Decrease)	For the nine months ended September 30,				Increase/(Decrease)
(in millions except percentages)	2021		2020			2021		2020
Lease operating expenses (1)	$	297	$	203	46%	$	807	$	579	39%
General & administrative expenses	28		27		4%	93		79		18%
Merger-related expenses	35		3		1,067%	39		3		1,200%
Restructuring charges	—		—		—%	7		12		(42)%
Taxes, other than income taxes	35		15		133%	86		38		126%
Full cost pool amortization	132		65		103%	316		248		27%
Non-full cost pool DD&A	4		3		33%	11		12		(8)%
Impairments	6		361		(98)%	6		2,495		(100)%
Total operating costs	$	537	$	677	(21)%	$	1,365	$	3,466	(61)%

Table of Contents


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

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

(2)Excludes $35 million and $39 million in merger-related expenses for the three and nine months ended September 30, 2021, respectively, and $7 million in restructuring charges for the nine months ended September 30, 2021.

Lease Operating Expenses

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

•Lease operating expenses per Mcfe increased $0.01 per Mcfe for the nine months ended September 30, 2021, compared to the same period in 2020, as a 37% increase in production volumes, primarily associated with the Montage Merger, was more than offset by a $228 million increase in lease operating expenses.

General and Administrative Expenses

•General and administrative expenses increased $1 million and $14 million for the three and nine months ended September 30, 2021, respectively, compared to the same periods in 2020, as a result of the increase in our share price and related mark-to-market impact on the value of our share-based awards, which are accounted for as liability awards.

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. We recognized restructuring expense of $7 million for the nine months ended months ended September 30, 2021 related to cash severance expenses, including payroll taxes.

•In February 2020, employees were notified of a workforce reduction plan as a result of a strategic realignment of our organizational structure. Affected employees were offered a severance package, which included a one-time cash payment depending on length of service and, if applicable, the current value of unvested long-term incentive awards that were forfeited. We recognized restructuring expense of $12 million for the nine months ended September 30, 2020 related to cash severance expenses, including payroll taxes.

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

Taxes, Other than Income Taxes

•On a per Mcfe basis, taxes, other than income taxes, may vary from period to period due to changes in ad valorem and severance taxes that result from the mix of our production volumes and fluctuations in commodity prices. Taxes, other than income taxes, per Mcfe increased $0.04 for the three and nine months ended September 30, 2021, respectively, compared to the same period in 2020, primarily due to the impact of higher commodity pricing on our severance taxes.

Full Cost Pool Amortization

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

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

Table of Contents

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

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

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

Impairments

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

Marketing


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


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

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

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

Operating Income

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

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•Marketing operating income increased $35 million for the nine months ended September 30, 2021, compared to the same period in 2020, primarily due to a $34 million increase in the marketing margin (discussed below).

•The margin generated from marketing activities was $13 million and $4 million for the three months ended September 30, 2021 and 2020, respectively, and $37 million and $3 million for the nine months ended September 30, 2021 and 2020, respectively. The marketing margin increased in 2021, compared to the same periods in 2020, primarily due to increased volumes marketed and a corresponding reduction in third-party purchases and sales used to optimize the transportation portfolio due to increased affiliated volumes available for marketing.

Revenues

•Revenues from our marketing activities increased $870 million for the three months ended September 30, 2021 compared to the same period in 2020, primarily due to a 134% increase in the price received for volumes marketed and a 52 Bcfe increase in volumes marketed.

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

Operating Costs and Expenses

•Operating costs and expenses for the marketing segment remained ~~flat~~approximately the same for the ~~three~~third quarter and increased $1 million for the nine months ended ~~March 31,~~September 30, 2021, respectively, compared to the same ~~period~~periods in 2020, primarily ~~due to~~as a result of the ~~prior implementation~~increase in our share price and related mark-to-market impact on the value of ~~cost reduction initiatives.~~our share-based awards, which are accounted for as liability awards.

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Consolidated

Interest Expense


		For the three months ended March 31,					Increase/(Decrease)			For the three months ended September 30,				Increase/(Decrease)		For the nine months ended September 30,						Increase/(Decrease)
(in millions except percentages)	(in millions except percentages)		2021			2020					(in millions except percentages)	2021				Increase/(Decrease)				2021						Increase/(Decrease)
Gross interest expense:	Gross interest expense:												Gross interest expense:
Senior notes	Senior notes			$	44		$	37	19%				Senior notes	$	48			$	39		23%			$	135			$	112		21%
Credit arrangements	Credit arrangements			6			3		100%				Credit arrangements	8		4				100%		19				11				73%
Amortization of debt costs	Amortization of debt costs			3			2		50%				Amortization of debt costs	3		2				50%		9				7				29%
Total gross interest expense	Total gross interest expense			53			42		26%				Total gross interest expense	59		45				31%		163				130				25%
Less: capitalization	Less: capitalization			(22)			(23)		(4)%				Less: capitalization	(25)		(23)				9%		(68)				(67)				1%
Net interest expense	Net interest expense			$	31		$	19	63%				Net interest expense	$	34	$	22			55%		$	95			$	63			51%

•Interest expense related to our senior notes increased for the three and nine months ended ~~March 31,~~September 30, 2021, compared to the same period in 2020, as the interest savings from the repurchase of ~~$80~~$107 million of our outstanding senior notes during the first ~~quarter~~half of 2020 was more than offset by the interest associated with the August 2020 public offering of $350 million aggregate principal amount of our 8.375% Senior Notes due ~~2028.~~2028, the September 2021 assumption of Indigo Notes, which were exchanged for $700 million aggregate principal amount of our 5.375% Senior Notes due 2029, and the September 2021 public offering of $1,200 million aggregate principal amount of our 5.375% Senior Notes due 2030.

•Capitalized interest ~~decreased~~increased for the three and nine months ended ~~March 31,~~September 30, 2021, both as compared to the same ~~period~~periods in 2020, primarily due to the ~~evaluation of natural gas and oil properties over~~incremental capitalized interest associated with the ~~past twelve months.~~recently acquired Haynesville unevaluated properties.

•Capitalized interest decreased as a percentage of gross interest expense for the three and nine months ended ~~March 31,~~September 30, 2021, compared to the same period in 2020, primarily related to a smaller percentage change in our unevaluated natural gas and oil properties balance as compared to the larger percentage increase in our gross interest expense over the same period.

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The impact of the addition of the unevaluated Haynesville properties was isolated to September 2021 and is expected to increase the amount of capitalized interest until such time as it is evaluated.

Gain (Loss) on Derivatives


								For the three months ended September 30,				For the nine months ended September 30,
		For the three months ended March 31,
(in millions)	(in millions)		2021		2020		(in millions)	2021		2020		2021		2020
Gain (loss) on unsettled derivatives			$	(169)	$	246
Loss on unsettled derivatives							Loss on unsettled derivatives	$	(2,015)	$	(289)	$	(2,957)	$	(273)
Gain (loss) on settled derivatives	Gain (loss) on settled derivatives		(22)		93		Gain (loss) on settled derivatives	(388)		97		(509)		310
Non-performance risk adjustment							Non-performance risk adjustment	4		—		5		1
Gain (loss) on derivatives	Gain (loss) on derivatives		$	(191)	$	339	Gain (loss) on derivatives	$	(2,399)	$	(192)	$	(3,461)	$	38

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 and nine months ended September 31, 2021, we recorded a loss on early extinguishment of debt of $59 million as a result of our repurchase of $791 million in aggregate principal amount of our outstanding senior notes for $844 million in the third quarter of 2021 and the write-off of $6 million in related unamortized debt discounts and debt issuance costs.

For the ~~three~~nine months ended ~~March 31,~~September 30, 2020, we recorded a gain on early extinguishment of debt of ~~$28~~$35 million as a result of our repurchase of ~~$80~~$107 million in aggregate principal amount of our outstanding senior notes for ~~$52 million.~~$72 million in the first three quarters of 2020. See Note 11 to the consolidated financial statements of this Quarterly Report for more information on our long-term debt.

Income Taxes


		For the three months ended March 31,							For the three months ended September 30,		For the nine months ended September 30,
(in millions except percentages)	(in millions except percentages)		2021			2020				(in millions except percentages)	2021			2020			2021			2020
Income tax expense	Income tax expense		$	—		$	406			Income tax expense	$	—		$	—		$	—		$	406
Effective tax rate	Effective tax rate		0		%	(36)		%		Effective tax rate	0		%	0		%	0		%	(16)		%

•As 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 all of the valuation allowance. However,In 2020, due to ~~commodity price~~significant pricing declines ~~during 2020~~ and the material write-down of the carrying value of our natural gas and oil properties in addition to other negative evidence, wemanagement concluded that it was more likely than not that ~~these~~a portion of our deferred tax assets will not be realized and recorded a ~~discrete tax expense~~valuation allowance. As of ~~$408 million for~~ the ~~increase in our valuation allowance in the first~~third quarter of ~~2020. The net change in valuation allowance is reflected as a component of income tax expense. We continue to have~~2021, we still maintain a full valuation ~~allowance for the first quarter of 2021.~~allowance. We also ~~continue to retain~~retained a valuation allowance of $87 million related to net operating losses in jurisdictions in which we no longer operate. Management will continue to assess available positive and negative evidence to estimate whether sufficient future taxable income will be generated to permit the use of deferred tax assets. The amount of the deferred tax asset considered realizable, however, could be adjusted based on changes in subjective estimates of future taxable income or if objective negative evidence is no longer present.

Due to the issuance of common stock associated with the Indigo Merger, as discussed in ~~Table of Contents~~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 September 30, 2021, we had approximately $4.5 billion of federal NOL carryovers, of which approximately $3 billion expire between 2035 and 2037 and $1.5 billion have an indefinite carryforward life. We currently estimate that approximately $2 billion of these federal NOLs will expire before they are able to be used. The non-expiring NOLs remain subject to a full valuation allowance. If a subsequent ownership change were to occur as a result of future transactions in our common stock, our use of remaining U.S. tax attributes may be further limited.

New Accounting Standards Implemented in this Report

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

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New Accounting Standards Not Yet Implemented in this Report

Refer to Note 17 to the consolidated financial statements of this Quarterly Report for a discussion of new accounting standards that have not yet been implemented.

LIQUIDITY AND CAPITAL RESOURCES

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~~September 2021, the banks participating in our 2018 credit facility reaffirmed our elected borrowing base and aggregate commitments to be $2.0 billion. At ~~March 31,~~September 30, 2021, we had approximately $1.2 billion of total available liquidity, which exceeds our currently modeled needs, and we remain committed to our strategy of capital discipline. We ~~refer you~~expect to continue to generate cash flow from operations, net of changes in working capital, in excess of our expected capital investments, and we intend to utilize this free cash flow to pay down our debt.

On June 1, 2021, we entered into the Indigo Merger Agreement. Upon the close of the Indigo Merger, and pursuant to the terms of the Indigo Merger Agreement, the outstanding equity interests in Indigo were cancelled and converted into (i) $373 million in cash consideration, and (ii) approximately $1,588 million in Southwestern common stock. Additionally, we assumed $700 million in aggregate principal amount of 5.375% Senior Notes due 2029 of Indigo (the “Indigo Notes”). We funded the $373 million cash portion of the September 2021 Indigo Merger consideration with the remaining proceeds from our recently issued 2030 Senior Notes (defined below) and borrowings on our credit facility. See Note 2 and Note 11 to the consolidated financial statements ~~included in~~of this Quarterly Report for more information on the Indigo Merger and ~~the section below under “Credit Arrangements and Financing Activities” for additional discussion of our 2018 credit facility and related covenant requirements.~~2030 Senior Notes, respectively.

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. The sales price we receive for our production is also influenced by our commodity derivative program. Our derivative contracts allow us to ensure 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 and 2023 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” in Item 3 in Part I and Note 8 in the consolidated financial statements included in this Quarterly Report for further details.

Our commodity hedging activities are subject to the credit risk of our counterparties being financially unable to settle the transaction. We actively monitor the credit status of our counterparties, performing both quantitative and qualitative assessments based on their credit ratings and credit default swap rates where applicable, and to date have not had any credit defaults associated with our transactions. However, any future failures by one or more counterparties could negatively impact our cash flow from operating activities.

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

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

Credit Arrangements and Financing Activities

In September 2021, we completed a public offering of $1,200 million aggregate principal amount of our 5.375% Senior Notes due 2030 (the “2030 Notes”), with net proceeds from the offering totaling $1,183 million after underwriting discounts and offering expenses. The proceeds were used to repurchase the $791 million principal amount of certain of our outstanding senior notes. The remaining proceeds were used to pay borrowings under our revolving credit facility and for general corporate purposes, including consideration for the Indigo Merger.

In April 2018, we entered into a new revolving credit facility (the “2018 credit facility”) with a group of banks that, as amended, has a maturity date of April 2024. The 2018 credit facility has an aggregate maximum revolving credit amount of $3.5 billion and, in ~~March~~September 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, typically in April and October, and is subject to change based primarily on drilling results, commodity prices, our

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future ~~derivative~~derivatives position, the level of capital investment and operating costs. The 2018 credit facility is secured by substantially all of our assets, including most of our subsidiaries. The permitted lien provisions in certain senior note indentures currently limit liens securing indebtedness to the greater of $2.0 billion or 25% of adjusted consolidated net tangible assets. We may utilize the 2018 credit facility in the form of loans and letters of credit. As of ~~March 31,~~September 30, 2021, we had ~~$567~~$665 million borrowings outstanding on our revolving credit facility and ~~$233~~$159 million in outstanding letters of credit. We refer you to Note 11 to the consolidated financial statements included in this Quarterly Report for additional discussion of our revolving credit facility.

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As of ~~March 31,~~September 30, 2021, we were in compliance with all of the covenants contained in the credit agreement governing our revolving credit facility. Our ability to comply with financial covenants in future periods depends, among other things, on the success of our development program and upon other factors beyond our control, such as the market demand and prices for natural gas 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.

The credit status of the financial institutions participating in our revolving credit facility could adversely impact our ability to borrow funds under the revolving 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 the anticipated transition from LIBOR in late 2021 is limited to the 2018 credit facility. Upon announcement by the administrator of LIBOR identifying 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~~USD-LIBOR settings are expected to be published through June 2023 and we anticipate using a variation of this rate until the ~~Secured Overnight Financing Rate (or “SOFR”).~~underlying agreements are extended beyond the LIBOR publication date.

Because of the focused work on refinancing and repayment of our debt ~~during the last three~~in recent years, only ~~$207~~$201 million, or 8%6%, of our senior notes outstanding as of ~~March 31,~~September 30, 2021 are scheduled to become due prior to 2025.

At ~~April 27,~~November 1, 2021, we had a long-term issuer credit rating of Ba2 by Moody’s (rating and stable outlook affirmed on April ~~2, 2020)~~28, 2021), a long-term debt rating of ~~BB-~~BB by S&P (rating ~~affirmed~~upgraded to BB and outlook upgraded to ~~stable~~positive on ~~October 15, 2020)~~September 1, 2021) and a long-term issuer default rating of BB by Fitch Ratings (rating affirmed and outlook upgraded to ~~stable~~positive on ~~January 29,~~September 1, 2021). 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 first coupon payment to the 2025 Notes bondholders at the higher interest rate was January 2021. On September 1, 2021 S&P upgraded the Company’s bond rating to BB, which will have the effect of decreasing the interest rate on the 2025 Notes to 6.20% 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.

Cash Flows


		For the three months ended March 31,					For the nine months ended September 30,
(in millions)	(in millions)	2021		2020		(in millions)	2021		2020
Net cash provided by operating activities	Net cash provided by operating activities	$	347	$	160	Net cash provided by operating activities	$	830	$	407
Net cash used in investing activities	Net cash used in investing activities	(227)		(228)		Net cash used in investing activities	(1,062)		(698)
Net cash provided by (used in) financing activities		(129)		68
Net cash provided by financing activities						Net cash provided by financing activities	231		381

Cash Flow from Operating Activities


		For the three months ended March 31,					For the nine months ended September 30,
(in millions)	(in millions)	2021		2020		(in millions)	2021		2020
Net cash provided by operating activities	Net cash provided by operating activities	$	347	$	160	Net cash provided by operating activities	$	830	$	407
Add back (subtract) changes in working capital	Add back (subtract) changes in working capital	—		21		Add back (subtract) changes in working capital	146		(9)
Net cash provided by operating activities, net of changes in working capital	Net cash provided by operating activities, net of changes in working capital	$	347	$	181	Net cash provided by operating activities, net of changes in working capital	$	976	$	398

•Net cash provided by operating activities increased ~~117%~~104%, or ~~$187~~$423 million, for the ~~three~~nine months ended ~~March 31,~~September 30, 2021, compared to the same period in 2020, primarily due to a ~~$252~~$1,408 million increase resulting from higher commodity prices, a ~~$111~~$313 million increase associated with increased production ~~a $21 million increase in impact of working capital~~ and a $5$23 million increase in marketing margin. These increases were partially offset by ~~a $115~~an $819 million decrease in our settled derivatives, a ~~$77~~$322 million increase in operating costs and expenses, a $155 million decreased impact of working capital and a ~~$12~~$32 million increase in interest expense.

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•Net cash generated from operating activities, net of changes in working capital, provided ~~130%~~120% of our cash requirements for capital investments for the ~~three~~nine months ended ~~March 31,~~September 30, 2021, compared to providing ~~76%~~56% of our cash requirements for capital investments for the same period in 2020. We remain committed to our disciplined capital investment ~~strategy.~~strategy and to utilizing our excess cash generated from operating activities to reduce our debt.

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Cash Flow from Investing Activities

•Total capital investments increased ~~$29~~$111 million for the ~~three~~nine months ended ~~March 31,~~September 30, 2021, compared to the same period in 2020, due to a ~~$28~~$102 million increase in direct E&P capital investments and a $1$9 million increase in capitalized interest and internal costs, as compared to the same period in 2020.


		For the three months ended March 31,					For the nine months ended September 30,
(in millions)	(in millions)	2021		2020		(in millions)	2021		2020
Additions to properties and equipment	Additions to properties and equipment	$	227	$	228	Additions to properties and equipment	$	747	$	700
Adjustments for capital investments	Adjustments for capital investments					Adjustments for capital investments
Changes in capital accruals	Changes in capital accruals	38		8		Changes in capital accruals	63		1
Other (1)	Other (1)	1		1		Other (1)	6		4
Total capital investment	Total capital investment	$	266	$	237	Total capital investment	$	816	$	705

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

Capital Investment

For the three months ended March 31, Increase/(Decrease)
(in millions except percentages) 2021 2020
E&P capital investment $ 266 $ 237 12%
Other capital investment (1)
— — —%
Total capital investment $ 266 $ 237 12%


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

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


		For the three months ended March 31,					For the three months ended September 30,		For the nine months ended September 30,
(in millions)	(in millions)		2021		2020			(in millions)	2021		2020		2021		2020
E&P Capital Investments by Type:	E&P Capital Investments by Type:							E&P Capital Investments by Type:
Exploratory and development drilling, including workovers	Exploratory and development drilling, including workovers		$	215	$	190		Exploratory and development drilling, including workovers	$	229	$	163	$	648	$	550
Acquisition of properties	Acquisition of properties		10		6			Acquisition of properties	14		15		36		29

Water infrastructure project			—		1
Water infrastructure								Water infrastructure	2		5		4		8
Other	Other		4		4			Other	6		3		13		12
Capitalized interest and expenses	Capitalized interest and expenses		37		36			Capitalized interest and expenses	40		37		115		106
Total E&P capital investments	Total E&P capital investments		$	266	$	237		Total E&P capital investments	$	291	$	223	$	816	$	705

E&P Capital Investments by Area:	E&P Capital Investments by Area:							E&P Capital Investments by Area:
Northeast Appalachia			$	80	$	86
Southwest Appalachia			183		146
Appalachia								Appalachia	$	224	$	215	$	741	$	685
Haynesville								Haynesville	59		—		59		—
Other E&P ~~(1)~~	Other E&P ~~(1)~~		3		5			Other E&P ~~(1)~~	8		8		16		20
Total E&P capital investments	Total E&P capital investments		$	266	$	237		Total E&P capital investments	$	291	$	223	$	816	$	705

~~(1)Includes $1 million for the three months ended March 31, 2020 related to our water infrastructure project.~~


		For the three months ended March 31,		For the three months ended September 30,				For the nine months ended September 30,
			2021		2020		2021	2020	2021	2020
Gross Operated Well Count Summary:	Gross Operated Well Count Summary:					Gross Operated Well Count Summary:
Drilled	Drilled		23		38	Drilled	17	16	63	84
Completed	Completed		29		22	Completed	23	25	71	78
Wells to sales	Wells to sales		17		12	Wells to sales	24	30	72	73

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

~~Cash Flow from Financing Activities~~

•~~For the three months ended March 31, 2021, we paid down $133 million on our revolving credit facility.~~

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Cash Flow from Financing Activities

•For the nine months ended September 30, 2021, we completed the previously mentioned $1,200 million debt offering which resulted in $1,183 million in net proceeds. We used $844 million to retire $791 million in principal on our outstanding senior notes and used $95 million to retire the Indigo revolving credit facility as part of the Indigo Merger. In addition, we paid down $35 million on our revolving credit facility.

•In the first ~~quarter~~three quarters of 2020, we ~~borrowed $115~~had net payments of $34 million ~~from~~on our revolving credit facility. In addition, we repurchased ~~$80~~$107 million principal amount of our outstanding senior notes for ~~$52~~$72 million and recognized a ~~$28~~$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 ~~$768~~$3,260 million at ~~March 31,~~September 30, 2021, a ~~$427~~$2,919 million decrease from December 31, 2020, as a ~~$32~~$340 million increase in accounts receivable was more than offset by a $2,635 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 of long-term debt to short-term debt of ~~$207~~$201 million related to our 2022 senior notes and a ~~$177 million reduction in the current mark-to-market value of our derivative position related to improved forward strip pricing across all commodities, a $56~~$386 million increase in various payables, ~~a $9 million decrease in cash and cash equivalents and a $7 million decrease in our net leasing assets,~~ as compared to December 31, 2020. We believe that our anticipated cash flows from operations, the remaining borrowing capacity on our credit facility and our existing cash and cash equivalents ~~and our available credit facility~~ will be sufficient to meet our working capital and operational spending requirements.

Off-Balance Sheet Arrangements

We may enter into off-balance sheet arrangements and transactions that can give rise to material off-balance sheet obligations. As of ~~March 31,~~September 30, 2021, our material off-balance sheet arrangements and transactions include operating service arrangements and ~~$233~~$159 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.

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 Annual Report.

Contingent Liabilities and Commitments

As of ~~March 31,~~September 30, 2021, 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 ~~$8.4~~$9.8 billion, ~~$436~~$382 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 ~~$908~~$884 million. As of ~~March 31,~~September 30, 2021, 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	$	7,915	$	789	$	1,539	$	1,295	$	1,752	$	2,540	Infrastructure currently in service	$	9,415	$	903	$	1,965	$	1,677	$	2,115	$	2,755
Pending regulatory approval and/or construction (1)	Pending regulatory approval and/or construction (1)	436		2		30		38		81		285		Pending regulatory approval and/or construction (1)	382		2		18		27		57		278
Total transportation charges	Total transportation charges	$	8,351	$	791	$	1,569	$	1,333	$	1,833	$	2,825	Total transportation charges	$	9,797	$	905	$	1,983	$	1,704	$	2,172	$	3,033

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

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Prior to the Indigo Merger, in May 2021, Indigo closed on an agreement to divest its Cotton Valley natural gas and oil properties. Indigo retained certain contractual commitments related to volume commitments associated with natural gas gathering, for which we will assume the obligation to pay the gathering provider for any unused portion of the volume commitment under the agreement through 2027, depending on the buyer’s actual use. As of September 30, 2021, up to approximately $34 million of these contractual commitments remain (included in the table above), and we have recorded a $17 million liability for the estimated future payments.

Excluding the Cotton Valley gathering agreement (discussed above), we have recorded additional liabilities totaling $81 million as of September 30, 2021, primarily related to purchase or volume commitments associated with gathering, fresh water and sand. These amounts will be recognized as payments are made over a period ranging from two to seven years.

Substantially all of our employees who were employed prior to January 1, 2021 are covered by defined benefit and postretirement benefit plans. As part of ongoing effort to reduce costs, we elected to freeze ~~its~~the pension plan effective January 1, 2021. Employees that were participants in the pension plan prior to January 1, 2021 will continue to receive the interest component of the plan but will no longer receive 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. In addition, we expect to make a payment equal to the difference between the total benefits due under the plan and the total value of the assets available, which, as of September 30, 2021, was approximately $7 million.

For the ~~three~~nine months ended ~~March 31,~~September 30, 2021, we have contributed $5$12 million to the pension and postretirement benefit plans, and we do not expect to contribute an additional ~~$7 million~~funds to our pension plan during the remainder of 2021. We recognized liabilities of ~~$41~~$31 million and $46 million as of ~~March 31,~~September 30, 2021 and December 31, 2020, respectively, 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

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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.

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”). The Guarantor Subsidiaries also granted liens and security interests to support their guarantees under the 2018 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 and senior notes.

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

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

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 and basis swaps to reduce the volatility of earnings and cash flow due to fluctuations in the prices of natural gas, oil and certain NGLs. Our Board of Directors has approved risk management policies and procedures to utilize financial products for the reduction of defined commodity price risk. 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 ~~March 31,~~September 30, 2021, no purchaser accounted for greater than 10% of our revenues. For the year ended December 31, 2020, one purchaser accounted for 10% of our revenues. 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. See “Commodities Risk” below for discussion of credit risk associated with commodities trading.

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Interest Rate Risk

As of ~~March 31,~~September 30, 2021, we had approximately ~~$2,471~~$3,580 million principal amount of outstanding senior notes with a weighted average interest rate of ~~7.02%~~6.10% and ~~$567~~$665 million of borrowings under our revolving credit facility. The 1% improvement to the Company’s weighted average fixed rate interest cost since the second quarter of 2021 is a result of the refinancing activities previously described. At ~~March 31,~~September 30, 2021, we had a long-term issuer credit rating of Ba2 by Moody’s, a long-term debt rating of ~~BB-~~BB by S&P and a long-term issuer default rating of BB by Fitch Ratings. In April 2020, S&P downgraded our bond rating to BB-, which had the effect of increasing the interest rate on our 2025 Notes to 6.45% following the July 23, 2020 interest payment date. The first coupon payment to the bondholders at the higher interest rate was paid in January 2021. On September 1, 2021 S&P upgraded our bond rating to BB, which will have the effect of decreasing the interest rate on the 2025 Notes to 6.20% 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.


		Expected Maturity Date																				Expected Maturity Date
($ in millions)	($ in millions)	2022			2023			2024			2025			2026			Thereafter			Total			($ in millions)	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)	$	201		$	—		$	—		$	689		$	—		$	2,690		$	3,580
Weighted average interest rate	Weighted average interest rate	4.10		%	—		%	—		%	6.45		%	7.50		%	8.03		%	7.02		%	Weighted average interest rate	4.10		%	—		%	—		%	6.45		%	—		%	6.15		%	6.10		%

Variable rate payments (1)	Variable rate payments (1)	$	—		$	—		$	567		$	—		$	—		$	—		$	567		Variable rate payments (1)	$	—		$	—		$	665		$	—		$	—		$	—		$	665
Weighted average interest rate	Weighted average interest rate	—		%	—		%	2.09		%	—		%	—		%	—		%	2.09		%	Weighted average interest rate	—		%	—		%	2.08		%	—		%	—		%	—		%	2.08		%

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

Commodities Risk

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

The primary market risks relating to our derivative contracts are the volatility in market prices and basis differentials for our production. However, the market price risk is offset by the gain or loss recognized upon the related sale or purchase of the production that is financially protected. Credit risk relates to the risk of loss as a result of non-performance by our counterparties. The counterparties are primarily major banks and integrated energy companies that management believes

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present minimal credit risks. The credit quality of each counterparty and the level of financial exposure we have to each counterparty are closely monitored to limit our credit risk exposure. Additionally, we perform both quantitative and qualitative assessments of these counterparties based on their credit ratings and credit default swap rates where applicable. We have not incurred any counterparty losses related to non-performance and do not anticipate any losses given the information we have currently. However, we cannot be certain that we will not experience such losses in the future. The fair value of our derivative assets and liabilities includes a non-performance risk factor. We refer you to Note 8 and Note 10 of the consolidated financial statements included in this Quarterly Report for additional details about our derivative instruments and their fair value.

ITEM 4. CONTROLS AND PROCEDURES

Disclosure Controls and Procedures

We have performed an evaluation under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, ~~(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. 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 ~~March 31,~~September 30, 2021 at a reasonable assurance level.

Changes in Internal Control over Financial Reporting

~~There~~During the quarter ended September 30, 2021, the Company completed its acquisition of Indigo Natural Resources. As part of the ongoing integration of the acquired business, we are in the process of incorporating the controls and related procedures of Indigo. Other than incorporating the Indigo 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 ~~March 31,~~September 30, 2021 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 Annual ~~Report.~~Report, except as set forth below.

Risks Factors Relating to SWN Following the Indigo Merger

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

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

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

•not realizing anticipated operating synergies;

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

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

•integrating relationships with customers, vendors and business partners;

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

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

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

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

•recoverable reserves;

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

•availability and cost of transportation of production to markets;

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

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

•regulatory, permitting and similar matters.

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

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

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

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

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

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

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

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

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

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

•general market conditions, including fluctuations in commodity prices;

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

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

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

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

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

•the operating and financial performance of the combined company;

•future mergers and strategic alliances;

•market conditions in the oil industry;

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

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

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

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

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

•speculation in the press or investment community;

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

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

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

•announcements concerning the combined company or its competitors;

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

•strategic actions taken by competitors;

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•actions taken by the combined company shareholders;

•additions or departures of key management personnel;

•maintenance of acceptable credit ratings or credit quality; and

•the general state of the securities markets.

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

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

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

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

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

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, iswas 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.

ITEM 5. OTHER INFORMATION

Not applicable.

ITEM 6. EXHIBITS


(2.1)			Agreement and Plan of Merger, dated as of August 12, 2020, by and between Southwestern Energy Company and Montage Resources Corporation (Incorporated by reference to Exhibit 2.1 to the Registrant’s Current Report on Form 8-K/A filed on August 12, 2020).
(2.2)			Agreement and Plan of Merger, dated June 1, 2021, by and among Southwestern Energy Company, Ikon Acquisition Company, LLC, Indigo Natural Resources LLC, and Ibis Unitholder Representative, LLC solely in its capacity as the Unitholder Representative (Incorporated by reference to Exhibit 2.1 to the Registrant's Current Report on Form 8-K filed June 2, 2021).
(3.1)			Amended and Restated Certificate of Incorporation of Southwestern Energy ~~Company.~~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).

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(4.1)			Fifth Supplemental Indenture, dated as of September 10, 2021 among Southwestern Energy Company, the guarantors named therein and the Bank of New York Mellon Trust Company, N.A., as trustee (incorporated by reference to Exhibit 4.6 to our Post-Effective Amendment No.1 on Form S-4 filed on September 16, 2021).
(4.2)			Seventh Supplemental Indenture, dated as of September 10, 2021 among Southwestern Energy Company, the guarantors named therein and Regions Bank, as trustee (incorporated by reference to Exhibit 4.14 to our Post-Effective Amendment No.1 on Form S-4 filed on September 16, 2021).
(4.3)			Sixth Supplemental Indenture, dated as of August 30, 2021 among Southwestern Energy Company, the guarantors named therein and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.4 to our Current Report on Form 8-K filed on August 30, 2021).
(4.4)			Seventh Supplemental Indenture, dated as of September 10, 2021 among Southwestern Energy Company, the guarantors named therein and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.23 to our Post-Effective Amendment No.1 on Form S-4 filed on September 16, 2021).
(4.4)			Indenture dated August 30, 2021, between Southwestern Energy Company and Regions Bank, as trustee (incorporated by reference to Exhibit 4.1 to our Current Report on Form 8-K filed on August 30, 2021).
(4.5)			First Supplemental Indenture, dated as of August 30, 2021 among Indigo Natural Resources LLC, the Security Guarantors party thereto and Wells Fargo Bank, National Association, as trustee (incorporated by reference to Exhibit 4.2 to our Current Report on Form 8-K filed on August 30, 2021).
(4.6)			Second Supplemental Indenture dated as of September 3, 2021 among Southwestern Energy Company, the Security Guarantors party thereto and Regions Bank, as trustee (incorporated by reference to Exhibit 4.1 to our Current Report on Form 8-K filed on September 3, 2021).
(4.7)			Third Supplemental Indenture, dated as of September 10, 2021 among Southwestern Energy Company, the guarantors named therein and Regions Bank, as trustee (incorporated by reference to Exhibit 4.31 to our Post-Effective Amendment No.1 on Form S-4 filed on September 16, 2021).
(4.8)			Form of 5.375% Senior Notes due 2029 (incorporated by reference to Exhibit 4.2 to our Current Report on Form 8-K filed with the SEC on September 3, 2021).
(4.9)			Exchange and Registration Rights Agreement, dated 3, 2021, among Southwestern Energy Company, the Guarantors thereto, J.P. Morgan Securities LLC and Credit Agricole Securities (USA) Inc. (incorporated by reference to Exhibit 4.3 to our Current Report on Form 8-K filed on September 3, 2021).
(4.10)			Indenture, dated as of February 2, 2021 among Indigo Natural Resources LLC, the guarantors named therein and Wells Fargo Bank, National Association, as trustee (incorporated by reference to Exhibit 4.34 to our Post-Effective Amendment No.1 on Form S-4 filed on September 16, 2021).
(4.11)			First Supplemental Indenture, dated as of August 26, 2021 among Indigo Natural Resources LLC, the guarantors named therein and Wells Fargo Bank, National Association, as trustee (incorporated by reference to Exhibit 4.35 to our Post-Effective Amendment No.1 on Form S-4 filed on September 16, 2021).
(4.12)			Form of 5.375% Notes due 2029 (incorporated by reference to Exhibit 4.36 to our Post-Effective Amendment No.1 on Form S-4 filed on September 16, 2021).
(10.1)			Amendment No.10 to Credit Agreement, dated June 9, 2021, among Southwestern Energy Corporation, the lenders party thereto and JP Morgan Chase Bank, N.A., as administrative agent for the lenders (Incorporated by reference to Exhibit 10.1 to the Registrant's Current Report on Form 8-K filed June 9, 2021).
(31.1)*			Certification of CEO filed pursuant to Section 302 of the Sarbanes-Oxley Act of ~~2002~~2002.
(31.2)*			Certification of CFO filed pursuant to Section 302 of the Sarbanes-Oxley Act of ~~2002~~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~~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~~2002.
(95.1)*			Mine Safety ~~Disclosure~~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

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Signatures

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


		SOUTHWESTERN ENERGY COMPANY
		Registrant

Dated:	~~April 29,~~November 4, 2021	/s/ ~~MICHAEL E. HANCOCK~~CARL F. GIESLER, JR.
		~~Michael E. Hancock~~Carl F. Giesler, Jr. Executive Vice President and Chief Financial Officer ~~(Interim)~~

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	March 31, 2021		March 31, 2020
Natural gas (per MMBtu)	$	2.16	$	2.30
Oil (per Bbl)	$	40.01	$	55.77
NGLs (per Bbl)	$	13.57	$	9.96