UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q

(Mark One)

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

Exchange Act of 1934

For the quarterly period ended ~~September 30, 2019~~March 31, 2020

☐ 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)

~~10000 Energy DriveSpring,Texas77389(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 ~~October 22, 2019~~April 28, 2020
Common Stock, Par Value $0.01	~~541,296,926~~	541,688,616

Table of Contents

SOUTHWESTERN ENERGY COMPANY

INDEX TO FORM 10-Q

FOR THE QUARTERLY PERIOD ENDED ~~SEPTEMBER 30, 2019~~MARCH 31, 2020


PART I – FINANCIAL INFORMATION					Page

Item 1.	Financial Statements			3
	Consolidated Statements of Operations			3
	Consolidated Statements of Comprehensive Income			4
	Consolidated Balance Sheets			5
	Consolidated Statements of Cash Flows			6
	Consolidated Statements of Changes in Equity			7
	Notes to Consolidated Financial Statements			98
		Note 1. Basis of Presentation	98
		Note 2. ~~Divestitures~~Restructuring Charges	8
		Note 3. Revenue Recognition	9
		Note ~~3. Restructuring Charges~~	10
		~~Note~~ 4. ~~Leases~~Cash and Cash Equivalents	11
		Note 5. ~~Revenue Recognition~~Natural Gas and Oil Properties	11
		Note 6. Earnings per Share	11
		Note 7. Derivatives and Risk Management	13
		Note ~~6. Cash and Cash Equivalents~~8. Reclassifications From Accumulated Other Comprehensive Income (Loss)	15
		~~Note 7. Natural Gas and Oil Properties~~	15
		~~Note 8. Earnings per Share~~	1520
		Note 9. ~~Derivatives and Risk Management~~Fair Value Measurements	1620
		Note 10. ~~Reclassifications From Accumulated Other Comprehensive Income (Loss)~~Debt	2322
		Note ~~11. Fair Value Measurements~~1 1 . Commitments and Contingencies	2324
		Note ~~12. Debt~~1 2 . Income Taxes	26
		Note ~~13. Commitments~~1 3 . Pension Plan and ~~Contingencies~~Other Postretirement Benefits	28
		~~Note 14. Income Taxes~~	2926
		Note ~~15. Pension Plan and Other Postretirement Benefits~~1 4 . Stock-Based Compensation	27
		Note 1 5 . Segment Information	30
		Note ~~16. Stock-Based Compensation~~1	306
		~~Note 17. Segment Information~~	33
		~~Note 18.~~. New Accounting Pronouncements	34
		~~Note 19. Condensed Consolidated Financial Information~~	3531
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations			4231
	Results of Operations			4434
	Liquidity and Capital Resources			5340
Item 3.	Quantitative and Qualitative Disclosures About Market Risk			5745
Item 4.	Controls and Procedures			5745

PART II – OTHER INFORMATION

Item 1.	Legal Proceedings			5846
Item 1A.	Risk Factors			5947
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds			5947
Item 3.	Defaults Upon Senior Securities			5947
Item 4.	Mine Safety Disclosures			5947
Item 5.	Other Information			5947
Item 6.	Exhibits			5948

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

~~Table of Contents~~

believe the expectations expressed in such forward-looking statements are based on reasonable assumptions, such statements are not guarantees of future performance. We have no obligation and make no undertaking to publicly update or revise any forward-looking statements, except as may be required by law.

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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~~, including regional basis ~~differentials);~~differentials and the impact of reduced demand for our production and products in which our production is a component due to governmental and societal actions taken in response to the COVID-19 pandemic;

•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;~~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;

•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 September 30,						For the nine months ended September 30,							For the three months ended March 31,
(in millions, except share/per share amounts)	(in millions, except share/per share amounts)	2019		2018		2019		2018		(in millions, except share/per share amounts)	2020		2019
Operating Revenues:	Operating Revenues:									Operating Revenues:
Gas sales	Gas sales	$	238	$	465	$	943	$	1,412	Gas sales	$	248	$	430
Oil sales	Oil sales	67		62		153		141		Oil sales	52		39
NGL sales	NGL sales	52		112		191		252		NGL sales	50		81
Marketing	Marketing	279		287		1,004		805		Marketing	239		438
Gas gathering		—		25		—		73
Other	Other	—		—		2		4		Other	3		2
		636		951		2,293		2,687			592		990
Operating Costs and Expenses:	Operating Costs and Expenses:									Operating Costs and Expenses:
Marketing purchases	Marketing purchases	288		288		1,022		808		Marketing purchases	248		441
Operating expenses	Operating expenses	189		206		523		588		Operating expenses	193		165
General and administrative expenses	General and administrative expenses	42		51		119		165		General and administrative expenses	26		37
Loss on sale of operating assets		—		—		3		—

Restructuring charges	Restructuring charges	4		2		9		20		Restructuring charges	10		3
Depreciation, depletion and amortization	Depreciation, depletion and amortization	125		151		352		426		Depreciation, depletion and amortization	113		112
Impairments	Impairments	2		161		8		171		Impairments	1,479		—
Taxes, other than income taxes	Taxes, other than income taxes	15		26		51		64		Taxes, other than income taxes	13		19
		665		885		2,087		2,242			2,082		777
Operating Income (Loss)	Operating Income (Loss)	(29)		66		206		445		Operating Income (Loss)	(1,490)		213
Interest Expense:	Interest Expense:									Interest Expense:
Interest on debt	Interest on debt	42		56		125		180		Interest on debt	40		42
Other interest charges	Other interest charges	2		2		5		6		Other interest charges	2		1
Interest capitalized	Interest capitalized	(27)		(29)		(84)		(86)		Interest capitalized	(23)		(29)
		17		29		46		100			19		14

Gain (Loss) on Derivatives	Gain (Loss) on Derivatives	100		(65)		220		(108)		Gain (Loss) on Derivatives	339		(32)
Gain (Loss) on Early Extinguishment of Debt		7		—		7		(8)
Other Income (Loss), Net		(2)		(1)		(7)		1
Gain on Early Extinguishment of Debt										Gain on Early Extinguishment of Debt	28		—
Other Income, Net										Other Income, Net	1		1

Income (Loss) Before Income Taxes	Income (Loss) Before Income Taxes	59		(29)		380		230		Income (Loss) Before Income Taxes	(1,141)		168
Provision (Benefit) for Income Taxes
Provision (Benefit) for Income Taxes:										Provision (Benefit) for Income Taxes:
Current	Current	(1)		—		(1)		—		Current	(2)		—
Deferred	Deferred	11		—		(400)		—		Deferred	408		(426)
		10		—		(401)		—			406		(426)
Net Income (Loss)	Net Income (Loss)	$	49	$	(29)	$	781	$	230	Net Income (Loss)	$	(1,547)	$	594

Participating securities – mandatory convertible preferred stock		—		—		—		1
Net Income (Loss) Attributable to Common Stock		$	49	$	(29)	$	781	$	229

Earnings (Loss) Per Common Share
Earnings (Loss) Per Common Share:										Earnings (Loss) Per Common Share:
Basic	Basic	$	0.09	$	(0.05)	$	1.45	$	0.40	Basic	$	(2.86)	$	1.10
Diluted	Diluted	$	0.09	$	(0.05)	$	1.44	$	0.39	Diluted	$	(2.86)	$	1.10

Weighted Average Common Shares Outstanding:	Weighted Average Common Shares Outstanding:									Weighted Average Common Shares Outstanding:
Basic	Basic	539,221,101		581,171,753		539,315,170		577,912,421		Basic	540,308,491		539,721,751
Diluted	Diluted	540,038,187		581,171,753		540,442,649		579,828,858		Diluted	540,308,491		541,320,487

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

(Unaudited)

For the three months ended September 30, For the nine months ended September 30,
(in millions) 2019
2018 ⁽¹⁾
2019
2018⁽¹⁾
Net income (loss) $ 49 $ (29) $ 781 $ 230

Change in value of pension and other postretirement liabilities:
Amortization of prior service cost and net loss included in net periodic pension cost ⁽²⁾
1 4 5 4

Comprehensive income (loss) $ 50 $ (25) $ 786 $ 234

~~(1)In 2018, deferred tax activity incurred in other comprehensive income was offset by a valuation allowance.~~

~~(2)~~Primarily related to settlement of pension assets in 2019 and the curtailment of pension assets in 2018. Net of less than $1 million and $1 million in taxes for the three months ended September 30, 2019 and 2018, respectively, and $2 million and $1 million in taxes for the nine months ended September 30, 2019 and 2018, respectively.


	For the three months ended March 31,
(in millions)	2020		2019
Net income (loss)	$	(1,547)	$	594

Change in value of pension and other postretirement liabilities:
Amortization of prior service cost and net loss included in net periodic pension cost	—		—

Comprehensive income (loss)	$	(1,547)	$	594

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, 2020			December 31, 2019
		September 30, 2019		December 31, 2018
ASSETS	ASSETS	(in millions)							ASSETS	(in millions)
Current assets:	Current assets:					Current assets:
Cash and cash equivalents	Cash and cash equivalents	$	29	$	201	Cash and cash equivalents	$	5		$	5
Accounts receivable, net	Accounts receivable, net	323		581		Accounts receivable, net	292			345
Derivative assets	Derivative assets	239		130		Derivative assets	627			278
Other current assets	Other current assets	42		44		Other current assets	48			51
Total current assets	Total current assets	633		956		Total current assets	972			679
Natural gas and oil properties, using the full cost method, including $1,518 million as of September 30, 2019 and $1,755 million as of December 31, 2018 excluded from amortization		25,060		24,180
Natural gas and oil properties, using the full cost method, including $1,437 million as of March 31, 2020 and $1,506 million as of December 31, 2019 excluded from amortization						Natural gas and oil properties, using the full cost method, including $1,437 million as of March 31, 2020 and $1,506 million as of December 31, 2019 excluded from amortization	25,488			25,250

Other	Other	522		525		Other	523			520
Less: Accumulated depreciation, depletion and amortization	Less: Accumulated depreciation, depletion and amortization	(20,383)		(20,049)		Less: Accumulated depreciation, depletion and amortization	(22,095)			(20,503)
Total property and equipment, net	Total property and equipment, net	5,199		4,656		Total property and equipment, net	3,916			5,267
Operating lease assets						Operating lease assets	152			159
Deferred tax assets	Deferred tax assets	398		—		Deferred tax assets	—			407
Other long-term assets	Other long-term assets	368		185		Other long-term assets	235			205
Total long-term assets						Total long-term assets	387			771
TOTAL ASSETS	TOTAL ASSETS	$	6,598	$	5,797	TOTAL ASSETS	$	5,275		$	6,717
LIABILITIES AND EQUITY	LIABILITIES AND EQUITY					LIABILITIES AND EQUITY
Current liabilities:	Current liabilities:					Current liabilities:
Current portion of long-term debt		$	52	$	—

Accounts payable	Accounts payable	539		609		Accounts payable	$	465		$	525
Taxes payable	Taxes payable	55		58		Taxes payable	52			59
Interest payable	Interest payable	57		52		Interest payable	54			51

Derivative liabilities	Derivative liabilities	85		79		Derivative liabilities	268			125
Current operating lease liabilities						Current operating lease liabilities	32			34
Other current liabilities	Other current liabilities	92		48		Other current liabilities	43			54
Total current liabilities	Total current liabilities	880		846		Total current liabilities	914			848
Long-term debt	Long-term debt	2,219		2,318		Long-term debt	2,279			2,242
Long-term operating lease liabilities						Long-term operating lease liabilities	114			119
Pension and other postretirement liabilities	Pension and other postretirement liabilities	39		46		Pension and other postretirement liabilities	40			43
Other long-term liabilities	Other long-term liabilities	325		225		Other long-term liabilities	227			219
Total long-term liabilities	Total long-term liabilities	2,583		2,589		Total long-term liabilities	2,660			2,623
Commitments and contingencies (Note 13)
Commitments and contingencies (Note 11)						Commitments and contingencies (Note 11)
Equity:	Equity:					Equity:
Common stock, $0.01 par value; 1,250,000,000 shares authorized; issued 585,637,420 shares as of September 30, 2019 and 585,407,107 shares as of December 31, 2018		6		6
Common stock, $0.01 par value; 1,250,000,000 shares authorized; issued 586,023,435 shares as of March 31, 2020 and 585,555,923 shares as of December 31, 2019						Common stock, $0.01 par value; 1,250,000,000 shares authorized; issued 586,023,435 shares as of March 31, 2020 and 585,555,923 shares as of December 31, 2019	6			6

Additional paid-in capital	Additional paid-in capital	4,723		4,715		Additional paid-in capital	4,728			4,726
Accumulated deficit	Accumulated deficit	(1,361)		(2,142)		Accumulated deficit	(2,798)			(1,251)
Accumulated other comprehensive loss	Accumulated other comprehensive loss	(31)		(36)		Accumulated other comprehensive loss	(33)			(33)
Common stock in treasury, 44,353,224 shares as of September 30, 2019 and 39,092,537 shares as of December 31, 2018		(202)		(181)
Common stock in treasury, 44,353,224 shares as of March 31, 2020 and December 31, 2019						Common stock in treasury, 44,353,224 shares as of March 31, 2020 and December 31, 2019	(202)			(202)
Total equity	Total equity	3,135		2,362		Total equity	1,701			3,246
TOTAL LIABILITIES AND EQUITY	TOTAL LIABILITIES AND EQUITY	$	6,598	$	5,797	TOTAL LIABILITIES AND EQUITY	$	5,275		$	6,717

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

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SOUTHWESTERN ENERGY COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)


		For the nine months ended September 30,							For the three months ended March 31,
(in millions)	(in millions)	2019		2018		(in millions)	2020		2019
Cash Flows From Operating Activities:	Cash Flows From Operating Activities:					Cash Flows From Operating Activities:
Net income		$	781	$	230
Adjustments to reconcile net income to net cash provided by operating activities:
Net income (loss)						Net income (loss)	$	(1,547)	$	594
Adjustments to reconcile net income (loss) to net cash provided by operating activities:						Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization	Depreciation, depletion and amortization	352		426		Depreciation, depletion and amortization	113		112
Amortization of debt issuance costs	Amortization of debt issuance costs	5		6		Amortization of debt issuance costs	1		1
Impairments	Impairments	8		171		Impairments	1,479		—
Deferred income taxes	Deferred income taxes	(400)		—		Deferred income taxes	408		(426)
(Gain) loss on derivatives, unsettled	(Gain) loss on derivatives, unsettled	(108)		113		(Gain) loss on derivatives, unsettled	(246)		22
Stock-based compensation	Stock-based compensation	6		12		Stock-based compensation	1		2
(Gain) loss on early extinguishment of debt		(7)		8
Loss on sale of assets		3		—
Gain on early extinguishment of debt						Gain on early extinguishment of debt	(28)		—

Other	Other	11		7		Other	—		1
Change in assets and liabilities:	Change in assets and liabilities:					Change in assets and liabilities:
Accounts receivable	Accounts receivable	257		(7)		Accounts receivable	53		189
Accounts payable	Accounts payable	(124)		60		Accounts payable	(86)		(48)
Taxes payable	Taxes payable	(3)		—		Taxes payable	(6)		4
Interest payable	Interest payable	2		(5)		Interest payable	1		2
Inventories	Inventories	(2)		(9)		Inventories	8		5
Other assets and liabilities	Other assets and liabilities	(42)		(41)		Other assets and liabilities	9		(16)
Net cash provided by operating activities	Net cash provided by operating activities	739		971		Net cash provided by operating activities	160		442

Cash Flows From Investing Activities:	Cash Flows From Investing Activities:					Cash Flows From Investing Activities:
Capital investments	Capital investments	(877)		(1,008)		Capital investments	(228)		(258)
Proceeds from sale of property and equipment		42		9
Other		—		4

Net cash used in investing activities	Net cash used in investing activities	(835)		(995)		Net cash used in investing activities	(228)		(258)

Cash Flows From Financing Activities:	Cash Flows From Financing Activities:					Cash Flows From Financing Activities:

Payments on long-term debt	Payments on long-term debt	(43)		(1,191)		Payments on long-term debt	(52)		—
Payments on revolving credit facility	Payments on revolving credit facility	—		(1,122)		Payments on revolving credit facility	(500)		—
Borrowings under revolving credit facility	Borrowings under revolving credit facility	—		1,482		Borrowings under revolving credit facility	615		—
Change in bank drafts outstanding	Change in bank drafts outstanding	(11)		10		Change in bank drafts outstanding	5		3

Debt issuance costs		—		(9)

Purchase of treasury stock	Purchase of treasury stock	(21)		(25)		Purchase of treasury stock	—		(21)
Preferred stock dividend		—		(27)

Cash paid for tax withholding	Cash paid for tax withholding	(1)		(1)		Cash paid for tax withholding	—		(1)

Net cash used in financing activities		(76)		(883)
Net cash provided by (used in) financing activities						Net cash provided by (used in) financing activities	68		(19)

Decrease in cash and cash equivalents		(172)		(907)
Increase in cash and cash equivalents						Increase in cash and cash equivalents	—		165
Cash and cash equivalents at beginning of year	Cash and cash equivalents at beginning of year	201		916		Cash and cash equivalents at beginning of year	5		201
Cash and cash equivalents at end of period	Cash and cash equivalents at end of period	$	29	$	9	Cash and cash equivalents at end of period	$	5	$	366

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	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, 2018		585,407,107	$	6	$	4,715	$	(2,142)	$	(36)	39,092,537	$	(181)		$	2,362
Comprehensive income:
Net income		—	—		—		594		—		—	—			594
Balance at December 31, 2019																	Balance at December 31, 2019	585,555,923	$	6		$	4,726	$	(1,251)	$	(33)	44,353,224	$	(202)	$	3,246
Comprehensive loss:																	Comprehensive loss:
Net loss																	Net loss	—	—			—		(1,547)		—		—	—		(1,547)
Other comprehensive income	Other comprehensive income	—	—		—		—		—		—	—			—		Other comprehensive income	—	—			—		—		—		—	—		—
Total comprehensive income		—	—		—		—		—		—	—			594
Total comprehensive loss																	Total comprehensive loss	—	—			—		—		—		—	—		(1,547)
Stock-based compensation	Stock-based compensation	—	—		3		—		—		—	—			3		Stock-based compensation	—	—			1		—		—		—	—		1

Issuance of restricted stock	Issuance of restricted stock	8,798	—		—		—		—		—	—			—		Issuance of restricted stock	12,397	—			—		—		—		—	—		—
Cancellation of restricted stock	Cancellation of restricted stock	(128,324)	—		—		—		—		—	—			—		Cancellation of restricted stock	(167,130)	—			—		—		—		—	—		—
Restricted units granted																	Restricted units granted	1,005,976	—			1		—		—		—	—		1
Treasury stock	Treasury stock	—	—		—		—		—		5,260,687	(21)			(21)		Treasury stock	—	—			—		—		—		—	—		—
Performance units vested	Performance units vested	535,802	—		—		—		—		—	—			—		Performance units vested	—	—			—		—		—		—	—		—
Tax withholding – stock compensation	Tax withholding – stock compensation	(274,657)	—		(1)		—		—		—	—			(1)		Tax withholding – stock compensation	(383,731)	—			—		—		—		—	—		—
Balance at March 31, 2019		585,548,726	$	6	$	4,717	$	(1,548)	$	(36)	44,353,224	$	(202)		$	2,937
Comprehensive income:
Net income		—	—		—		138		—		—	—			138
Other comprehensive income		—	—		—		—		4		—	—			4
Total comprehensive income		—	—		—		—		—		—	—			142
Stock-based compensation		—	—		3		—		—		—	—			3
Issuance of restricted stock		6,424	—		—		—		—		—	—			—
Cancellation of restricted stock		(72,555)	—		—		—		—		—	—			—
Tax withholding – stock compensation		(4,250)	—		—		—		—		—	—			—
Balance at June 30, 2019		585,478,345	$	6	$	4,720	$	(1,410)	$	(32)	44,353,224	$	(202)		$	3,082
Comprehensive income:
Net income		—	—		—		49		—		—	—			49
Other comprehensive income		—	—		—		—		1		—	—			1
Total comprehensive income		—	—		—		—		—		—	—			50
Stock-based compensation		—	—		3		—		—		—	—			3
Issuance of restricted stock		205,883	—		—		—		—		—	—			—
Cancellation of restricted stock		(33,851)	—		—		—		—		—	—			—
Balance at March 31, 2020																	Balance at March 31, 2020	586,023,435	$	6		$	4,728	$	(2,798)	$	(33)	44,353,224	$	(202)	$	1,701

Tax withholding – stock compensation		(12,957)	—		—		—		—		—	—			—
Balance at September 30, 2019		585,637,420	$	6	$	4,723	$	(1,361)	$	(31)	44,353,224	$	(202)		$	3,135

~~Table of Contents~~

~~SOUTHWESTERN ENERGY COMPANY AND SUBSIDIARIES~~

~~CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY (CONTINUED)~~

~~(Unaudited)~~


		Common Stock					Preferred 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 Issued										Shares			Amount				Shares Issued		Amount										Shares	Amount

		(in millions, except share amounts)																																(in millions, except share amounts)
Balance at December 31, 2017		512,134,311	$	5		1,725,000	$	4,698	$	(2,679)	$	(44)	31,269	$	(1)		$	1,979
Balance at December 31, 2018																			Balance at December 31, 2018	585,407,107	$	6	$	4,715	$	(2,142)	$	(36)	39,092,537	$	(181)	$	2,362
Comprehensive income:	Comprehensive income:																		Comprehensive income:
Net income	Net income	—	—			—	—		208		—		—	—			208		Net income	—	—		—		594		—		—	—		594
Other comprehensive income	Other comprehensive income	—	—			—	—		—		—		—	—			—		Other comprehensive income	—	—		—		—		—		—	—		—
Total comprehensive income	Total comprehensive income	—	—			—	—		—		—		—	—			208		Total comprehensive income	—	—		—		—		—		—	—		594
Stock-based compensation	Stock-based compensation	—	—			—	7		—		—		—	—			7		Stock-based compensation	—	—		3		—		—		—	—		3
Conversion of preferred stock		74,998,614	1			(1,725,000)	(1)		—		—		—	—			—

Issuance of restricted stock	Issuance of restricted stock	5,076	—			—	—		—		—		—	—			—		Issuance of restricted stock	8,798	—		—		—		—		—	—		—
Cancellation of restricted stock	Cancellation of restricted stock	(160,168)	—		��	—	—		—		—		—	—			—		Cancellation of restricted stock	(128,324)	—		—		—		—		—	—		—
Treasury stock																			Treasury stock	—	—		—		—		—		5,260,687	(21)		(21)
Performance units vested	Performance units vested	214,866	—			—	—		—		—		—	—			—		Performance units vested	535,802	—		—		—		—		—	—		—
Tax withholding – stock compensation	Tax withholding – stock compensation	(338,808)	—			—	(1)		—		—		—	—			(1)		Tax withholding – stock compensation	(274,657)	—		(1)		—		—		—	—		(1)
Balance at March 31, 2018		586,853,891	$	6		—	$	4,703	$	(2,471)	$	(44)	31,269	$	(1)		$	2,193
Comprehensive income:
Net income		—	—			—	—		51		—		—	—			51
Other comprehensive income		—	—			—	—		—		—		—	—			—
Total comprehensive income		—	—			—	—		—		—		—	—			51
Stock-based compensation		—	—			—	6		—		—		—	—			6
Issuance of restricted stock		307,743	—			—	—		—		—		—	—			—
Cancellation of restricted stock		(722,465)	—			—	—		—		—		—	—			—
Tax withholding – stock compensation		(9,068)	—			—	—		—		—		—	—			—
Balance at June 30, 2018		586,430,101	$	6		—	$	4,709	$	(2,420)	$	(44)	31,269	$	(1)		$	2,250
Comprehensive loss
Net loss		—	—			—	—		(29)		—		—	—			(29)
Other comprehensive income		—	—			—	—		—		4		—	—			4
Total comprehensive loss		—	—			—	—		—		—		—	—			(25)
Stock-based compensation		—	—			—	5		—		—		—	—			5
Preferred stock dividend		—	—			—	—		—		—		—	—			—
Issuance of restricted stock		30,924	—			—	—		—		—		—	—			—
Cancellation of restricted stock		(248,342)	—			—	—		—		—		—	—			—
Treasury stock		—	—			—	—		—		—		4,829,011	(25)			(25)
Tax withholding – stock compensation		(17,521)	—			—	—		—		—		—	—			—
Balance at September 30, 2018		586,195,162	$	6		—	$	4,714	$	(2,449)	$	(40)	4,860,280	$	(26)		$	2,205
Balance at March 31, 2019																			Balance at March 31, 2019	585,548,726	$	6	$	4,717	$	(1,548)	$	(36)	44,353,224	$	(202)	$	2,937

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

Table of Contents

SOUTHWESTERN ENERGY COMPANY AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

(1) BASIS OF PRESENTATION

Southwestern Energy Company (including its subsidiaries, collectively “Southwestern” or the “Company”) is an independent energy company engaged in natural gas, oil and ~~natural gas liquid (“NGL”)~~NGL exploration, development and production (“E&P”). The Company is also focused on creating and capturing additional value through its marketing business (“~~Midstream”~~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 Midstream. The Company’s historical financial and operating results include its Fayetteville Shale E&P and related midstream gathering businesses, which were sold in early December 2018 (the “Fayetteville Shale sale”). The sale is discussed in further detail in ~~Note 2~~.Marketing.

E&P. Southwestern’s primary business is the exploration for and production of natural gas, oil and NGLs, with ongoing operations focused on the development of unconventional natural gas and oil reservoirs located in Pennsylvania and West Virginia. The Company’s operations in northeast Pennsylvania, herein referred to as “Northeast Appalachia,” are primarily focused on the unconventional natural gas reservoir known as the Marcellus Shale. Operations in West Virginia and southwest Pennsylvania, herein referred to as “Southwest Appalachia,” are focused on the Marcellus Shale, the Utica and the Upper Devonian unconventional natural gas and oil reservoirs. Collectively, Southwestern refers to its properties located in Pennsylvania and West Virginia as ~~the “Appalachian Basin.~~“Appalachia.” The Company also operates drilling rigs located in Pennsylvania and West Virginia, and provides certain oilfield products and services, principally serving the Company’s E&P operations through vertical integration.

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

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 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, ~~2018~~2019 (“~~2018~~2019 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 ~~2018~~2019 Annual Report.

Certain reclassifications have been made to the prior year financial statements to conform to the 2019 presentation. The effects of the reclassifications were not material to the Company’s consolidated financial statements.

(2) ~~DIVESTITURES~~

On August 30, 2018, the Company entered into an agreement with Flywheel Energy Operating, LLC to sell 100% of the equity in the Company’s subsidiaries that owned and operated its Fayetteville Shale E&P and related midstream gathering assets for $1,865 million in cash, subject to customary closing adjustments, with an economic effective date of July 1, 2018. On December 3, 2018, the Company closed on the Fayetteville Shale sale and received approximately $1,650 million, which included purchase price adjustments of approximately $215 million primarily related to the net cash flows from the economic effective date to the closing date.

The Company retained certain contractual commitments related to firm transportation, with the buyer obligated to pay the transportation provider directly for these charges. As of September 30, 2019, approximately $135 million of these contractual commitments remain of which the Company will reimburse the buyer for certain of these potential obligations up to approximately $70 million through 2020 depending on the buyer’s actual use. At September 30, 2019, the Company has recorded a $57 million liability for the estimated future payments.

~~Table of Contents~~

In accordance with accounting guidance for Property, Plant and Equipment, assets held for sale are measured at the lower of the carrying value or fair value less costs to sell. Because the assets outside of the full cost pool included in the Fayetteville Shale sale met the criteria for held for sale accounting as of September 30, 2018, the Company determined the carrying value of certain non-full cost pool assets exceeded the fair value less costs to sell. As a result, an impairment charge of $161 million was recorded during the three and nine months ended September 30, 2018, of which $145 million related to midstream gathering assets held for sale and $15 million related to E&P assets held for sale. Additionally, the Company recorded a $1 million impairment related to other non-core assets that were not included in the sale.

From the proceeds received, $914 million was used to repurchase $900 million of the Company’s outstanding senior notes, including premiums and $9 million in accrued interest paid in December 2018. In addition, $201 million, including approximately $1 million in commissions, was used to repurchase approximately 44 million shares of the Company’s outstanding common stock, including $21 million during the first quarter of 2019. The Company earmarked the remaining net proceeds from the sale to supplement Appalachian Basin development and for general corporate purposes.

In June 2019, the Company sold non-core acreage for $25 million. There was no production or proved reserves associated with this acreage. In addition, during July 2019, the Company sold the land associated with its headquarters office building for $16 million, and recognized a $2 million gain on the sale. The Company also from time to time sells leases and other properties whose value, individually, is not material but is reflected in the Company’s financial statements.

~~(3)~~ RESTRUCTURING CHARGES

~~In June 2018,~~On February 4, 2020, the Company notified ~~affected~~ employees of a workforce reduction plan ~~which resulted primarily from~~as a ~~previously announced study~~result of ~~structural, process and organizational changes to enhance shareholder value and continues with respect to other aspects~~a strategic realignment of the Company’s ~~business activities.~~organizational structure. This reduction was substantially complete by the end of the first quarter of 2020. 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 ~~a portion of equity~~unvested long-term incentive awards that were forfeited. These costs were recognized as restructuring charges for the three months ended March 31, 2020, and a liability of approximately $0.3 million has been accrued as of March 31, 2020 related to future payments associated with the February 2020 restructuring.

In December 2018, the Company closed on the sale of the equity in certain of its subsidiaries that owned and operated its Fayetteville Shale E&P and related midstream gathering assets in ~~Arkansas.~~Arkansas (the “Fayetteville Shale sale”). As part of the transaction, most employees associated with those assets became employees of the buyer although the employment of some was terminated. Due to the scale of the assets that were sold, the temporary employment of certain employees was extended through a transition period into 2019. All 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 ~~a portion of~~ equity awards that were forfeited. ~~As of September 30, 2019, the~~The Company ~~has substantially completed the Fayetteville Shale sale-related employment terminations.~~

~~In July 2019, the Company terminated its existing lease agreement on its headquarters~~also incurred charges related to office ~~building and entered into a new 10-year lease agreement for a smaller~~consolidation. A portion of ~~the building. Approximately $3 million of the fees associated~~these costs along with the ~~Company’s office consolidation are reflected~~aforementioned severance costs were recognized as restructuring charges ~~for the three months ended September 30, 2019. The Company also recognized additional severance costs~~ in the ~~third~~first quarter of ~~2019, related to continued organizational restructuring, for which a liability~~2019.

Table of ~~$1 million has been accrued as of September 30, 2019.~~Contents

The following table presents a summary of the restructuring charges included in Operating Income (Loss) for the three ~~and nine~~ months ended ~~September 30, 2019~~March 31, 2020 and ~~2018:~~2019:


		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)	2019		2018		2019		2018		(in millions)	2020		2019
Severance (including payroll taxes)	Severance (including payroll taxes)	$	1	$	1	$	4	$	18	Severance (including payroll taxes)	$	10	$	2
Office consolidation	Office consolidation	3		—		5		—		Office consolidation	—		1
Professional fees		—		1		—		2

Total restructuring charges⁽¹⁾	Total restructuring charges⁽¹⁾	$	4	$	2	$	9	$	20	Total restructuring charges⁽¹⁾	$	10	$	3

(1)Total restructuring charges were $4$10 million and ~~$9 million for the Company’s E&P segment for the three and nine months ended September 30, 2019, respectively. Total restructuring charges were $2~~$3 million for the Company’s E&P segment for the three months ended ~~September 30, 2018,~~March 31, 2020 and ~~$18 million and $2 million for the Company’s E&P and Midstream segments, respectively, for the nine months ended September 30, 2018.~~2019, respectively.

The following table presents a reconciliation of the liability associated with the Company’s restructuring activities at ~~September 30, 2019,~~March 31, 2020, which is reflected in accounts payable on the consolidated balance sheet:


(in millions)
Liability at December 31, ~~2018~~2019	$	52
Additions	910
Distributions	~~(13)~~(12)
Liability at ~~September 30, 2019~~March 31, 2020	$	1—

~~Table of Contents~~

~~(4) LEASES~~

In February 2016, the FASB issued Accounting Standards Update No. 2016-02, Leases (Topic 842) (“Update 2016-02”), which seeks to increase transparency and comparability among organizations by, among other things, recognizing lease assets and lease liabilities on the balance sheet for leases classified as operating leases under previous GAAP and disclosing key information about leasing arrangements. The codification was amended through additional ASUs. For public entities, Update 2016-02 became effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years. The Company adopted ASC 842 with an effective date of January 1, 2019 using the modified retrospective approach for all leases that existed at the date of initial application. The Company elected to apply the transition as of the beginning of the period of adoption. For leases that existed at the period of adoption on January 1, 2019, the incremental borrowing rate as of the application date was used to calculate the present value of remaining lease payments.

~~The standard provides optional practical expedients to ease the burden of transition. The Company has adopted the following practical expedients through implementation:~~

•an election not to apply the recognition requirements in the leases standard to short-term leases and recognize lease payments in the consolidated statement of operations (a lease that at commencement date has an initial term of 12 months or less and does not contain a purchase option that the Company is reasonably certain to exercise);

•~~a package of practical expedients to not reassess: whether a contract is or contains a lease, lease classification and initial direct costs;~~

•~~a practical expedient that permits combining lease and non-lease components in a contract and accounting for the combination as a lease (elected by asset class);~~

•~~a practical expedient to not reassess certain land easements in existence prior to January 1, 2019; and~~

•an election to adopt the modified retrospective approach for all leases existing at or entered into after the initial date of adoption which does not require a restatement of prior period. No cumulative-effect adjustment to retained earnings was required as a result of the modified retrospective approach.

Upon adoption of ASC 842, the Company recognized a discounted right-of-use asset and corresponding lease liability with opening balances of approximately $105 million as of January 1, 2019. The adoption of the standard did not materially change the Company’s consolidated statement of operations or its consolidated statement of cash flows.

The Company determines if a contract contains a lease at inception. A lease is defined as a contract, or part of a contract, that conveys the right to control the use of identified property, plant or equipment (an identified asset) for a period of time in exchange for consideration. A right-of-use asset and corresponding lease liability are recognized on the balance sheet at commencement at an amount based on the present value of the remaining lease payments over the lease term. As the implicit rate of the lease is not always readily determinable, the Company uses the incremental borrowing rate to calculate the present value of the lease payments based on information available at commencement date. Operating right-of-use assets are included in other long-term assets while operating lease liabilities are included in other current and other long-term liabilities on the consolidated balance sheet. The Company does not have any financing lease type of arrangements as of September 30, 2019. By policy election, leases with an initial term of twelve months or less are not recorded on the balance sheet. The Company recognizes lease expense for these leases on a straight-line basis, and variable lease payments are recognized in the period as incurred.

Certain leases contain both lease and non-lease components. The Company has chosen to account for most of these leases as a single lease component instead of bifurcating lease and non-lease components. However, for compression service leases and fleet vehicle leases, the lease and non-lease components are accounted for separately.

The Company leases drilling rigs, pressure pumping equipment, vehicles, office space, certain water transportation lines, an aircraft and other equipment under non-cancelable operating leases expiring through 2032. Certain lease agreements include options to renew the lease, early terminate the lease or purchase the underlying asset(s). The Company determines the lease term at the lease commencement date as the non-cancelable period of the lease, including options to extend or terminate the lease when such an option is reasonably certain to be exercised. The Company’s water transportation lines are the only leases with renewal options that are reasonably certain to be exercised. These renewal options are reflected in the right-of-use asset and lease liability balances.

In July 2019, the Company terminated its existing lease agreement and entered into a new 10-year lease agreement for a smaller portion of the headquarters office building, which resulted in the Company making a $6 million residual value guarantee short-fall payment to the building’s previous lessor. The net impact to the Company’s right of use asset balance increased $56 million in the third quarter of 2019 as a result of entering into the new lease agreement, which was partially offset

~~Table of Contents~~

by the early lease termination of the previous lease. The Company’s variable lease costs are primarily comprised of variable operating charges incurred in connection with the new building lease which are expected to continue throughout the lease term. There are currently no material residual value guarantees in the Company’s existing leases.

~~The components of lease costs are shown below:~~


	For the nine months ended September 30, 2019
~~(in millions)~~
~~Operating lease cost~~	$	33



~~Short-term lease cost~~	49
~~Variable lease cost~~	1
~~Total lease cost~~	$	83

As of September 30, 2019, the Company has operating leases of $20 million, related primarily to compressor leases, that have been executed but not yet commenced. These operating leases are planned to commence during 2019 with lease terms expiring through 2023. The Company’s existing operating leases do not contain any material restrictive covenants.

~~Supplemental cash flow information related to leases is set forth below:~~


	For the nine months ended September 30, 2019
~~(in millions)~~
~~Cash paid for amounts included in the measurement of lease liabilities:~~
~~Operating cash flows from operating leases~~	$	34



~~Right-of-use assets obtained in exchange for new operating liabilities:~~
~~Operating leases~~	$	88

~~Supplemental balance sheet information related to leases is as follows:~~



~~Right-of-use asset balance:~~ ~~(in millions)~~	~~September 30, 2019~~
~~Operating leases~~	$	~~164~~

~~Lease liability balance:(in millions)~~
~~Short-term operating leases~~	$	35
~~Long-term operating leases~~	~~124~~
~~Total operating leases~~	$	~~159~~


~~Weighted average remaining lease term:~~ ~~(years)~~
~~Operating leases~~	~~6.8~~


~~Weighted average discount rate:~~
~~Operating leases~~	~~5.54~~		%

~~Maturity analysis of operating lease liabilities:~~

(in millions) September 30, 2019
2019 $ 12
2020 40
2021 31
2022 21
2023 19
2024 15
Thereafter 52
Total undiscounted lease liability 190
Imputed interest (31)
Total discounted lease liability $ 159

~~Table of Contents~~

(in millions) December 31, 2018
2019 $ 38
2020 28
2021 14
2022 6
2023 5
Thereafter 4
Total minimum payments required $ 95

~~(5)~~(3) REVENUE RECOGNITION

Revenues from Contracts with Customers

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

The Company records revenue from its natural gas and liquids production in the amount of its net revenue interest in sales from its properties. Accordingly, natural gas and liquid sales are not recognized for deliveries in excess of the Company’s net revenue interest, while natural gas and liquid sales are recognized for any under-delivered volumes. Production imbalances are generally recorded as receivables and payables and not contract assets or contract liabilities as the imbalances are between the Company and other working interest owners, not the end customer.

Marketing. The Company, through its marketing affiliate, ~~generally~~ markets natural gas, oil and NGLs for its affiliated E&P company as well as other joint interest owners ~~who~~that choose to market with ~~Southwestern.~~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 a market index 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 tofor which the Company has a right to invoice and has not disclosed information regarding its remaining performance obligations.

~~Gas gathering.~~ Prior to the Fayetteville Shale sale in December 2018, the Company, through its gathering affiliate, gathered natural gas pursuant to a variety of contracts with customers, including an affiliated E&P company. The performance obligations for gas gathering services included delivery of each unit of natural gas to the designated delivery point, which may include treating of certain natural gas units to meet interstate pipeline specifications. Revenue was recognized at the point in time when performance obligations were fulfilled. Under the Company’s gathering contracts, customers were invoiced and revenue was recognized each month based on the volume of natural gas transported and treated at a contractually agreed upon price per unit. Payment terms were typically within 30 to 60 days of completion of the performance obligations. Furthermore, consideration from a customer corresponded directly with the value to the customer of the Company’s performance completed to date. As a result, the Company recognized revenue in the amount to which the Company had a right to invoice and had not disclosed information regarding its remaining performance obligations. Any imbalances were settled on a monthly basis by cashing-out with the respective shipper. Accordingly, there were no contract assets or contract liabilities related to the Company’s gas gathering revenues.

139

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Disaggregation of Revenues

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

(in millions) E&P Midstream Intersegment
Revenues Total
Three months ended September 30, 2019
Gas sales $ 230 $ — $ 8 $ 238
Oil sales 66 — 1 67
NGL sales 52 — — 52
Marketing — 592 (313) 279
Total $ 348 $ 592 $ (304) $ 636
Three months ended September 30, 2018
Gas sales $ 460 $ — $ 5 $ 465
Oil sales 61 — 1 62
NGL sales 112 — — 112
Marketing — 846 (559) 287
Gas gathering ⁽¹⁾
— 66 (41) 25
Total $ 633 $ 912 $ (594) $ 951


(in millions)	(in millions)	E&P		Midstream		Intersegment Revenues		Total		(in millions)	E&P		Marketing		Intersegment Revenues		Total
Nine months ended September 30, 2019
Three months ended March 31, 2020										Three months ended March 31, 2020
Gas sales	Gas sales	$	918	$	—	$	25	$	943	Gas sales	$	239	$	—	$	9	$	248
Oil sales	Oil sales	151		—		2		153		Oil sales	52		—		—		52
NGL sales	NGL sales	191		—		—		191		NGL sales	50		—		—		50
Marketing	Marketing	—		2,158		(1,154)		1,004		Marketing	—		548		(309)		239
Other ⁽²⁾⁽¹⁾	Other ⁽²⁾⁽¹⁾	1		1		—		2		Other ⁽²⁾⁽¹⁾	3		—		—		3
Total	Total	$	1,261	$	2,159	$	(1,127)	$	2,293	Total	$	344	$	548	$	(300)	$	592

Nine months ended September 30, 2018
Three months ended March 31, 2019										Three months ended March 31, 2019
Gas sales	Gas sales	$	1,395	$	—	$	17	$	1,412	Gas sales	$	421	$	—	$	9	$	430
Oil sales	Oil sales	139		—		2		141		Oil sales	39		—		—		39
NGL sales	NGL sales	252		—		—		252		NGL sales	81		—		—		81
Marketing	Marketing	—		2,403		(1,598)		805		Marketing	—		940		(502)		438
Gas gathering ⁽¹⁾		—		202		(129)		73
Other ⁽²⁾	Other ⁽²⁾	4		—		—		4		Other ⁽²⁾	1		1		—		2
Total	Total	$	1,790	$	2,605	$	(1,708)	$	2,687	Total	$	542	$	941	$	(493)	$	990

(1)~~The Company’s gas gathering assets were divested in December 2018 as part~~For the three months ended March 31, 2020, other E&P revenues consists primarily of ~~the Fayetteville Shale sale.~~gains on purchaser imbalances associated with certain NGLs.

(2)~~Other~~For the three months ended March 31, 2019, other E&P revenues consists primarily of water sales to third-party operators, and other ~~Midstream~~Marketing revenues consists primarily of sales of gas from storage.

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 and West Virginia. ~~In December 2018, the Company sold 100% of its Fayetteville Shale assets.~~

For the three months ended September 30, For the nine months ended September 30,
(in millions) 2019 2018 2019 2018
Northeast Appalachia $ 175 $ 254 $ 740 $ 794
Southwest Appalachia 173 235 519 557
Fayetteville Shale — 140 — 431
Other — 4 2 8
Total $ 348 $ 633 $ 1,261 $ 1,790

~~Table of Contents~~


	For the three months ended March 31,
(in millions)	2020		2019
Northeast Appalachia	$	195	$	348
Southwest Appalachia	149		193
Other	—		1
Total	$	344	$	542

Receivables from Contracts with Customers

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


(in millions)	(in millions)	September 30, 2019		December 31, 2018		(in millions)	March 31, 2020		December 31, 2019
Receivables from contracts with customers	Receivables from contracts with customers	$	235	$	494	Receivables from contracts with customers	$	195	$	284
Other accounts receivable	Other accounts receivable	88		87		Other accounts receivable	97		61
Total accounts receivable	Total accounts receivable	$	323	$	581	Total accounts receivable	$	292	$	345

Amounts recognized against the Company’s allowance for doubtful accounts related to receivables arising from contracts with customers were immaterial for the three ~~and nine~~ months ended ~~September 30, 2019~~March 31, 2020 and ~~2018.~~2019. The Company has 0 contract assets or contract liabilities associated with its revenues from contracts with customers.

Table of Contents

~~(6)~~(4) CASH AND CASH EQUIVALENTS

The following table presents a summary of cash and cash equivalents as of ~~September 30, 2019~~March 31, 2020 and December 31, ~~2018:~~2019:


(in millions)	(in millions)	September 30, 2019		December 31, 2018		(in millions)	March 31, 2020		December 31, 2019
Cash	Cash	$	9	$	32	Cash	$	5	$	5
Marketable securities ⁽¹⁾	Marketable securities ⁽¹⁾	20		169		Marketable securities ⁽¹⁾	—		—

Total	Total	$	29	$	201	Total	$	5	$	5

(1)~~Consists~~At March 31, 2020, marketable securities were immaterial and consisted of government stable value money market funds.

~~(7)~~(5) 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 and other internal costs directly attributable to these activities, are capitalized on a country-by-country basis and amortized over the estimated lives of the properties using the units-of-production method. These capitalized costs are subject to a ceiling test that limits such pooled costs, net of applicable deferred taxes, to the aggregate of the present value of future net revenues attributable to proved natural gas, oil and NGL reserves discounted at 10% (standardized measure). Any costs in excess of the ceiling are written off as a non-cash expense. The expense may not be reversed in future periods, even though higher natural gas, oil and NGL prices may subsequently increase the ceiling. Companies using the full cost method are required to use the average quoted price from the first day of each month from the previous 12 months, including the impact of derivatives designated for hedge accounting, to calculate the ceiling value of their reserves. The Company had no hedge positions that were designated for hedge accounting as of March 31, 2020. Prices used to calculate the ceiling value of reserves were as follows:


(in millions)	March 31, 2020		March 31, 2019
Natural gas (per MMBtu)	$	2.30	$	3.07
Oil (per Bbl)	$	55.77	$	63.00
NGLs (per Bbl)	$	9.96	$	17.65

Using the average quoted ~~price from the first day of each month from the previous 12 months~~prices above, adjusted for ~~Henry Hub natural gas of $2.87 per MMBtu, West Texas Intermediate oil of $57.77 per Bbl and NGLs of $12.59 per Bbl, adjusted for~~market differentials, the Company’s net book value of its United States natural gas and oil properties ~~did not exceed~~exceeded the ceiling ~~amount~~by $1.5 billion at ~~September 30, 2019. The Company had 0 derivative positions that were designated for hedge accounting as of September 30, 2019.~~March 31, 2020, resulting in a non-cash ceiling test impairment. 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. ~~Should market~~Given the decline in commodity prices ~~continue below~~in 2019 and early 2020, the ~~average~~Company expects that an additional non-cash impairment of ~~the previous 12-months, as was the case~~its assets will likely occur in the ~~third~~second quarter of ~~2019, such impairments may occur in upcoming quarters.~~2020 and perhaps later.

Using the average quoted price from the first day of each month from the previous 12 months for Henry Hub natural gas of $2.91 per MMBtu, West Texas Intermediate oil of $63.43 per Bbl and NGLs of $17.47 per Bbl, adjusted for differentials, theThe Company’s net book value of its United States natural gas and oil properties did not exceed the ceiling amount at ~~September 30, 2018. The~~March 31, 2019, and the Company had 0 derivative positions that were designated for hedge accounting as of ~~September 30, 2018.~~March 31, 2019.

~~(8)~~(6) EARNINGS PER SHARE

Basic earnings per common share is computed by dividing net income attributable to common stock by the weighted average number of common shares outstanding during the reportable period. The diluted earnings per share calculation adds to the weighted average number of common shares outstanding: the incremental shares that would have been outstanding assuming the exercise of dilutive stock options, the vesting of unvested restricted shares of common stock, performance units and the assumed conversion of mandatory convertible preferred stock. 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.

~~Table of Contents~~

In January 2015, the Company issued 34,500,000 depositary shares that entitled the holder to a proportional fractional interest in the rights and preferences of the mandatory convertible preferred stock, including conversion, dividend, liquidation and voting rights. The mandatory convertible preferred stock had the non-forfeitable right to participate on an as-converted basis at the conversion rate then in effect in any common stock dividends declared and, therefore, was considered a participating security. Accordingly, it has been included in the computation of basic and diluted earnings per share, pursuant to the two-class method. In the calculation of basic earnings per share attributable to common shareholders, earnings are allocated to participating securities based on actual dividend distributions received plus a proportionate share of undistributed net income attributable to common shareholders, if any, after recognizing distributed earnings. The Company’s participating securities do not participate in undistributed net losses because they are not contractually obligated to do so. On January 12, 2018, all outstanding shares of mandatory convertible preferred stock converted to 74,998,614 shares of the Company’s common stock. The Company paid out its last dividend payment of approximately $27 million associated with the depositary shares in January 2018.

~~During the second half of 2018, the Company repurchased 39,061,269 shares of its outstanding common stock for approximately $180 million at an average price of $4.63 per share.~~ In the first quarter of 2019, the Company ~~completed its share repurchase program by purchasing~~repurchased 5,260,687 shares of its outstanding common stock as part of a share repurchase program for approximately $21 million at an average price of $3.84 per share.

Table of Contents

The following table presents the computation of earnings per share for the three ~~and nine~~ months ended ~~September 30, 2019~~March 31, 2020 and ~~2018:~~2019:


		For the three months ended September 30,						For the nine months ended September 30,							For the three months ended March 31,
(in millions, except share/per share amounts)	(in millions, except share/per share amounts)	2019		2018		2019		2018		(in millions, except share/per share amounts)	2020		2019
Net income (loss)	Net income (loss)	$	49	$	(29)	$	781	$	230	Net income (loss)	$	(1,547)	$	594
Participating securities – mandatory convertible preferred stock		—		—		—		1
Net income (loss) attributable to common stock		$	49	$	(29)	$	781	$	229

Number of common shares:	Number of common shares:									Number of common shares:
Weighted average outstanding	Weighted average outstanding	539,221,101		581,171,753		539,315,170		577,912,421		Weighted average outstanding	540,308,491		539,721,751
Issued upon assumed exercise of outstanding stock options	Issued upon assumed exercise of outstanding stock options	—		—		—		—		Issued upon assumed exercise of outstanding stock options	—		—
Effect of issuance of non-vested restricted common stock	Effect of issuance of non-vested restricted common stock	187,706		—		400,120		640,365		Effect of issuance of non-vested restricted common stock	—		665,435
Effect of issuance of non-vested restricted units										Effect of issuance of non-vested restricted units	—		—
Effect of issuance of non-vested performance units	Effect of issuance of non-vested performance units	629,380		—		727,359		1,276,072		Effect of issuance of non-vested performance units	—		933,301
Weighted average and potential dilutive outstanding	Weighted average and potential dilutive outstanding	540,038,187		581,171,753		540,442,649		579,828,858		Weighted average and potential dilutive outstanding	540,308,491		541,320,487

Earnings per common share	Earnings per common share									Earnings per common share
Basic	Basic	$	0.09	$	(0.05)	$	1.45	$	0.40	Basic	$	(2.86)	$	1.10
Diluted	Diluted	$	0.09	$	(0.05)	$	1.44	$	0.39	Diluted	$	(2.86)	$	1.10

The following table presents the common stock shares equivalent excluded from the calculation of diluted earnings per share for the three ~~and nine~~ months ended ~~September 30,~~March 31, 2020 and 2019, ~~and 2018,~~ as they would have had an antidilutive effect:


		For the three months ended September 30,			For the nine months ended September 30,				For the three months ended March 31,
		2019	2018	2019	2018		2020	2019
Unexercised stock options	Unexercised stock options	5,102,882	717	5,115,334	—	Unexercised stock options	4,584,563	5,128,640
Unvested share-based payment	Unvested share-based payment	2,136,453	3,463,802	1,797,963	4,246,492	Unvested share-based payment	1,006,860	1,881,355
Restricted stock units						Restricted stock units	1,312,293	—
Performance units	Performance units	240,450	2,000,553	247,443	856,703	Performance units	2,275,498	260,201
Mandatory convertible preferred stock		—	—	—	3,296,642
Total	Total	7,479,785	5,465,072	7,160,740	8,399,837	Total	9,179,214	7,270,196

~~(9)~~

Table of Contents

(7) DERIVATIVES AND RISK MANAGEMENT

The Company is exposed to volatility in market prices and basis differentials for natural gas, oil and NGLs which impacts the predictability of its cash flows related to the sale of those commodities. These risks are managed by the Company’s use of certain derivative financial instruments. As of ~~September 30, 2019,~~March 31, 2020, the Company’s derivative financial instruments consisted of fixed price swaps, two-way costless collars, three-way costless collars, basis swaps, call options and interest rate swaps. A description of the Company’s derivative financial instruments is provided below:

~~Table of Contents~~


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

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

Three-way costless collars			Arrangements that contain a purchased put option, a sold call option and a sold put option based on an index price ~~which,~~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.

Call options			The Company purchases and sells call options in exchange for a premium. 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.

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 ~~chooses~~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 9 for additional details regarding the Company’s fair value measurements of its derivative positions. The Company presents its derivative positions on a gross basis and does not net the asset and liability positions.

As part of the Fayetteville Shale sale, the Company entered into certain natural gas derivative positions that were subsequently novated to the buyer in conjunction with finalization of the sale. The derivatives that were novated to the buyer are not included in the tables below.

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Table of Contents

The following tables provide information about the Company’s financial instruments that are sensitive to changes in commodity prices and that are used to protect the Company’s exposure. None of the financial instruments below are designated for hedge accounting treatment. The tables present the notional amount, the weighted average contract prices and the fair value by expected maturity dates as of ~~September 30, 2019:~~March 31, 2020:


Financial Protection on Production	Financial Protection on Production																												Financial Protection on Production
			Weighted Average Price per MMBtu																							Weighted Average Price per MMBtu
		Volume (Bcf)	Swaps		Sold Puts		Purchased Puts		Sold Calls		Basis Differential		Fair Value at September 30, 2019 (in millions)				Volume (Bcf)	Swaps		Sold Puts		Purchased Puts		Sold Calls		Basis Differential		Fair Value at March 31, 2020 (in millions)
Natural Gas	Natural Gas															Natural Gas
2019
2020																2020
Fixed price swaps	Fixed price swaps	61	$	2.89	$	—	$	—	$	—	$	—	$	28		Fixed price swaps	279	$	2.50	$	—	$	—	$	—	$	—	$	181	⁽¹⁾
Two-way costless collars	Two-way costless collars	6	—		—		2.78		2.92		—		2			Two-way costless collars	23	—		—		2.50		2.79		—		3
Three-way costless collars	Three-way costless collars	44	—		2.43		2.82		3.15		—		13			Three-way costless collars	136	—		2.08		2.42		2.70		—		15
Total	Total	111											$	43		Total	438											$	199
2020
2021																2021
Fixed price swaps	Fixed price swaps	151	$	2.58	$	—	$	—	$	—	$	—	$	45	⁽¹⁾	Fixed price swaps	36	$	2.53	$	—	$	—	$	—	$	—	$	5
Two-way costless collars																Two-way costless collars	29	—		—		2.28		2.77		—		(1)
Three-way costless collars																Three-way costless collars	265	—		2.18		2.49		2.84		—		(20)
Total																Total	330											$	(16)
2022																2022
Two-way costless collars																Two-way costless collars	29	$	—	$	—	$	2.10	$	2.83	$	—	$	—
Three-way costless collars																Three-way costless collars	91	—		2.10		2.46		2.86		—		(2)
Total																Total	120											$	(2)
2023																2023

Three-way costless collars	Three-way costless collars	209	—		2.34		2.67		2.98		—		22			Three-way costless collars	2	$	—	$	2.15	$	2.55	$	3.35	$	—	$	—
Total		360											$	67
2021
Three-way costless collars		134	$	—	$	2.27	$	2.55	$	2.85	$	—	$	(1)
2022
Three-way costless collars		23	$	—	$	2.30	$	2.70	$	3.14	$	—	$	—


Basis Swaps	Basis Swaps															Basis Swaps
2019		35	$	—	$	—	$	—	$	—	$	(0.40)	$	9
2020	2020	141	—		—		—		—		(0.31)		(13)			2020	199	$	—	$	—	$	—	$	—	$	(0.44)	$	(3)
2021	2021	65	—		—		—		—		(0.48)		(1)			2021	103	—		—		—		—		(0.03)		12
2022	2022	45	—		—		—		—		(0.50)		—			2022	88	—		—		—		—		(0.48)		(4)
Total	Total	286											$	(5)		Total	390											$	5

(1)Includes $9 million in premiums paid related to certain natural gas fixed price swaps recognized as a component of derivative assets within current assets on the consolidated balance sheet at ~~September 30, 2019.~~March 31, 2020. As certain natural gas fixed price swaps settle, the premium will be amortized and recognized as a component of gain (loss) on derivatives on the consolidated statements of operations.

1814

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		Volume (MBbls)	Weighted Average Strike Price per Bbl																						Fair Value at September 30, 2019 (in millions)			Volume (MBbls)				Weighted Average Strike Price per Bbl									Fair Value at March 31, 2020 (in millions)
					Swaps			Sold Puts			Purchased Puts			Sold Calls					Fair Value at September 30, 2019 (in millions)	Volume (MBbls)							Swaps			Sold Puts				Purchased Puts				Sold Calls		Fair Value at March 31, 2020 (in millions)
Oil	Oil																Oil
2019
2020																	2020
Fixed price swaps⁽¹⁾	Fixed price swaps⁽¹⁾	632	$	60.65		$	—		$	—		$	—		$	4	Fixed price swaps⁽¹⁾	2,442				$	57.75			$	—			$	—			$	—			$	66
Two-way costless collars	Two-way costless collars	382	—			—			61.45			67.16			3		Two-way costless collars	731		—				—				56.88				59.81				19
Three-way costless collars	Three-way costless collars	138	—			45.00			55.00			63.67			—		Three-way costless collars	1,210		—				43.94				53.17				58.05				9
Total	Total	1,152													$	7	Total	4,383																		$	94
2021																	2021
Fixed price swaps																	Fixed price swaps	2,328		$	53.72			$	—			$	—			$	—			$	39
Three-way costless collars																	Three-way costless collars	1,445		—				43.52				53.25				58.14				10
Total																	Total	3,773																		$	49
2022																	2022
Fixed price swaps																	Fixed price swaps	438		$	51.74			$	—			$	—			$	—			$	5
Three-way costless collars																	Three-way costless collars	666		—				42.50				53.20				58.00				4
Total																	Total	1,104																		$	9

Ethane																	Ethane
2020	2020																2020
Fixed price swaps	Fixed price swaps	1,556	$	60.18		$	—		$	—		$	—		$	14	Fixed price swaps	6,952		$	8.59			$	—			$	—			$	—			$	21
Two-way costless collars		366	—			—			60.00			69.80			4
Three-way costless collars		915	—			45.00			55.00			61.75			3
Total		2,837													$	21
2021	2021																2021
Three-way costless collars		730	$	—		$	45.00		$	53.00		$	59.50		$	1
Fixed price swaps																	Fixed price swaps	3,017		$	7.40			$	—			$	—			$	—			$	2

Propane	Propane																Propane
2019
Fixed price swaps		978	$	30.18		$	—		$	—		$	—		$	11
Two-way costless collars		138	—			—			25.62			28.77			1
Total		1,116													$	12
2020	2020																2020
Fixed price swaps	Fixed price swaps	2,928	$	25.58		$	—		$	—		$	—		$	18	Fixed price swaps	4,049		$	23.06			$	—			$	—			$	—			$	43
Two-way costless collars	Two-way costless collars	366	—			—			25.20			$	29.40		2		Two-way costless collars	275		—				—				25.20				29.40				4
Total	Total	3,294													$	20	Total	4,324																		$	47
2021	2021																2021
Fixed price swaps	Fixed price swaps	456	$	22.24		$	—		$	—		$	—		$	1	Fixed price swaps	2,460		$	21.77			$	—			$	—			$	—			$	17

Ethane
2019
Fixed price swaps		2,194	$	10.53		$	—		$	—		$	—		$	6
2020
Fixed price swaps		3,843	$	9.80		$	—		$	—		$	—		$	7

(1)Includes 69186 MBbls of purchased fixed price oil swaps ~~hedged~~ at ~~$69.10~~$57.46 per ~~Bbl~~barrel with a fair value of ($1)5) million and ~~701~~2,628 MBbls of sold fixed price oil swaps ~~hedged~~ at ~~$61.48~~$57.73 per ~~Bbl~~barrel with a fair value of $5$71 million.


Other Derivative Contracts	Other Derivative Contracts											Other Derivative Contracts
		Volume (Bcf)	Weighted Average Strike Price per MMBtu		Fair Value at September 30, 2019 (in millions)			Volume (Bcf)	Weighted Average Strike Price per MMBtu		Fair Value at March 31, 2020 (in millions)
Purchased Call Options – Natural Gas
2019		5	$	3.50	$	—

Sold Call Options – Natural Gas (Net)							Sold Call Options – Natural Gas (Net)
2020	2020	68	3.63		1		2020	51	$	2.83	$	(2)
2021	2021	57	3.52		2		2021	57	3.15		(7)
Total		130			$	3

Sold Call Options – Natural Gas
2019		13	$	3.50	$	—
2020		137	3.39		(5)
2021		114	3.33		(6)
2022							2022	58	3.00		(6)
2023	2023	6	3.00		(1)		2023	17	2.84		(3)
2024	2024	9	3.00		(2)		2024	9	3.00		(2)
Total	Total	279			$	(14)	Total	192			$	(20)

໿


	Volume (MBbls)	Weighted Average Strike Price per Bbl		Fair Value at March 31, 2020 (in millions)
Sold Call Options – Oil
2021	226	$	60.00	$	—

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										Volume (Bcf)	Weighted Average Strike Price per MMBtu								Fair Value at March 31, 2020 (in millions)
		Volume (Bcf)	Weighted Average Strike Price per MMBtu		Basis Differential per MMBtu		Fair Value at September 30, 2019 (in millions)						Swaps			Basis Differential
Storage ⁽¹⁾	Storage ⁽¹⁾								Storage ⁽¹⁾
2019
Purchased fixed price swaps		—	$	2.90	$	—	$	—
Purchased basis swaps		—	—		(0.61)		—
Total		—					$	—
2020	2020								2020
Purchased fixed price swaps	Purchased fixed price swaps	—	$	2.37	$	—	$	—	Purchased fixed price swaps	3	$	2.00		$	—		$	(1)
Purchased basis swaps	Purchased basis swaps	—	—		(0.32)		—		Purchased basis swaps	1	—			(0.49)			—
Sold fixed price swaps	Sold fixed price swaps	2	3.06		—		1		Sold fixed price swaps	2	1.99			—			—
Sold basis swaps	Sold basis swaps	—	—		(0.32)		—		Sold basis swaps	1	—			(0.51)			—
Total	Total	2					$	1	Total	7							$	(1)
2021									2021
Purchased fixed price swaps									Purchased fixed price swaps	1	$	2.04		$	—		$	—
Sold fixed price swaps									Sold fixed price swaps	2	2.49			—			—
Sold basis swaps									Sold basis swaps	1	—			(0.38)			—
Total									Total	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 at a later date.


Purchased Fixed Price Swaps – Marketing (Natural Gas) ⁽¹⁾	Volume (Bcf)	Weighted Average Strike Price per MMBtu		Fair Value at March 31, 2020 (in millions)
2020	6	$	2.44	$	(2)
2021	6	2.44		—
Total	12			$	(2)

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

At ~~September 30, 2019,~~March 31, 2020, the net fair value of the Company’s financial instruments related to commodities was a ~~$169~~$402 million ~~asset.~~asset and included a net reduction of less than $1 million related to non-performance risk. See Note 9 for additional details regarding the Company’s fair value measurements of its derivative positions.

As of ~~September 30, 2019,~~March 31, 2020, the Company had no positions designated for hedge accounting treatment. Gains and losses on derivatives that are not designated for hedge accounting treatment, or do not meet hedge accounting requirements, are recorded as a component of gain (loss) on derivatives on the consolidated statements of operations. Accordingly, the gain (loss) on derivatives component of the statement of operations reflects the gain and losses on both settled and unsettled derivatives. The Company calculates gains and losses on settled derivatives as the summation of gains and losses on positions which have settled within the reporting period. Only the settled gains and losses are included in the Company’s realized commodity price calculations.

The Company is a party to interest rate swaps that were entered into to mitigate the Company’s exposure to volatility in interest rates. The interest rate swaps have a notional amount of $170 million and expire in June 2020. ~~The Company did not designate the interest rate swaps for hedge accounting treatment.~~ Changes in the fair value of the interest rate swaps are included in gain (loss) on derivatives on the consolidated statements of operations.

At March 31, 2020, the net fair value of the Company’s interest rate swaps was a $1 million liability.

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The balance sheet classification of the assets and liabilities related to derivative financial instruments (none of which are designated for hedge accounting treatment) is summarized below as of ~~September 30, 2019~~March 31, 2020 and December 31, ~~2018:~~2019:


Derivative Assets	Derivative Assets							Derivative Assets
			Fair Value										Fair Value
(in millions)	(in millions)	Balance Sheet Classification	September 30, 2019			December 31, 2018		(in millions)	Balance Sheet Classification	March 31, 2020			December 31, 2019
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		$	—
Fixed price swaps – natural gas	Fixed price swaps – natural gas	Derivative assets	$	68	⁽¹⁾	$	32	Fixed price swaps – natural gas	Derivative assets	181		⁽¹⁾	77		⁽¹⁾
Fixed price swaps – oil	Fixed price swaps – oil	Derivative assets	15			13		Fixed price swaps – oil	Derivative assets	80			4
Fixed price swaps – ethane								Fixed price swaps – ethane	Derivative assets	22			11
Fixed price swaps – propane	Fixed price swaps – propane	Derivative assets	25			11		Fixed price swaps – propane	Derivative assets	48			21
Fixed price swaps – ethane		Derivative assets	12			7
Two-way costless collars – natural gas	Two-way costless collars – natural gas	Derivative assets	2			11		Two-way costless collars – natural gas	Derivative assets	13			10
Two-way costless collars – oil	Two-way costless collars – oil	Derivative assets	6			6		Two-way costless collars – oil	Derivative assets	28			5
Two-way costless collars – propane	Two-way costless collars – propane	Derivative assets	3			—		Two-way costless collars – propane	Derivative assets	4			2
Three-way costless collars – natural gas	Three-way costless collars – natural gas	Derivative assets	84			41		Three-way costless collars – natural gas	Derivative assets	189			126
Three-way costless collars – oil	Three-way costless collars – oil	Derivative assets	5			—		Three-way costless collars – oil	Derivative assets	36			3
Basis swaps – natural gas	Basis swaps – natural gas	Derivative assets	17			8		Basis swaps – natural gas	Derivative assets	22			17
Purchased call options – natural gas	Purchased call options – natural gas	Derivative assets	1			—		Purchased call options – natural gas	Derivative assets	3			1
Storage – fixed price swaps		Derivative assets	1			—
Interest rate swaps		Derivative assets	—			1
Fixed price swaps – natural gas storage								Fixed price swaps – natural gas storage	Derivative assets	—			1

Fixed price swaps – natural gas	Fixed price swaps – natural gas	Other long-term assets	5			6		Fixed price swaps – natural gas	Other long-term assets	5			7
Fixed price swaps – oil	Fixed price swaps – oil	Other long-term assets	4			6		Fixed price swaps – oil	Other long-term assets	35			1
Fixed price swaps – ethane								Fixed price swaps – ethane	Other long-term assets	1			—
Fixed price swaps – propane	Fixed price swaps – propane	Other long-term assets	5			—		Fixed price swaps – propane	Other long-term assets	12			3
Fixed price swaps – ethane		Other long-term assets	1			1
Two-way costless collars – natural gas								Two-way costless collars – natural gas	Other long-term assets	5			4

Two-way costless collars – oil		Other long-term assets	1			5

Three-way costless collars – natural gas	Three-way costless collars – natural gas	Other long-term assets	63			34		Three-way costless collars – natural gas	Other long-term assets	71			74
Three-way costless collars – oil	Three-way costless collars – oil	Other long-term assets	8			—		Three-way costless collars – oil	Other long-term assets	29			7
Basis swaps – natural gas	Basis swaps – natural gas	Other long-term assets	7			3		Basis swaps – natural gas	Other long-term assets	5			15
Purchased call options – natural gas	Purchased call options – natural gas	Other long-term assets	2			6		Purchased call options – natural gas	Other long-term assets	1			2
Total derivative assets	Total derivative assets		$	335		$	191	Total derivative assets		$	791		$	391

Derivative Liabilities
Fair Value
(in millions) Balance Sheet Classification September 30, 2019 December 31, 2018
Derivatives not designated as hedging instruments:
Purchased fixed price swap – oil Derivative liabilities $ 1 $ 6
Fixed price swaps – natural gas Derivative liabilities — 9
Fixed price swaps – ethane Derivative liabilities — 3
Two-way costless collars – natural gas Derivative liabilities — 7
Three-way costless collars – natural gas Derivative liabilities 53 33
Three-way costless collars – oil Derivative liabilities 3 —
Basis swaps – natural gas Derivative liabilities 24 18
Sold call options – natural gas Derivative liabilities 4 3
Fixed price swaps – natural gas Other long-term liabilities — 1
Two-way costless collars – oil Other long-term liabilities — 1
Three-way costless collars – natural gas Other long-term liabilities 60 35
Three-way costless collars – oil Other long-term liabilities 6 —
Basis swap – natural gas Other long-term liabilities 5 4
Sold call options – natural gas Other long-term liabilities 10 19
Total derivative liabilities $ 166 $ 139

(1) Includes $9 million in premiums paid related to certain natural gas fixed price swaps recognized as a component of derivative assets within current assets on the consolidated balance sheet at ~~September 30,~~both March 31, 2020 and December 31, 2019. As certain natural gas fixed price swaps settle, the premium will be amortized and recognized as a component of gain (loss) on derivatives on the consolidated statements of operations.

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Derivative Liabilities
		Fair Value
(in millions)	Balance Sheet Classification	March 31, 2020		December 31, 2019
Derivatives not designated as hedging instruments:
Purchased fixed price swaps – natural gas	Derivative liabilities	$	3	$	1
Purchased fixed price swaps – oil	Derivative liabilities	5		—
Fixed price swaps – natural gas	Derivative liabilities	—		1
Fixed price swaps – oil	Derivative liabilities	—		6

Two-way costless collars – natural gas	Derivative liabilities	10		4
Two-way costless collars – oil	Derivative liabilities	9		5
Three-way costless collars – natural gas	Derivative liabilities	194		84
Three-way costless collars – oil	Derivative liabilities	24		4
Basis swaps – natural gas	Derivative liabilities	12		17
Sold call options – natural gas	Derivative liabilities	9		3
Interest rate swaps	Derivative liabilities	1		—
Purchased fixed price swaps – natural gas storage	Derivative liabilities	1		—

Fixed price swaps – oil	Other long-term liabilities	—		2
Two-way costless collars – natural gas	Other long-term liabilities	6		4

Three-way costless collars – natural gas	Other long-term liabilities	73		72
Three-way costless collars – oil	Other long-term liabilities	18		8
Basis swap – natural gas	Other long-term liabilities	10		9
Sold call options – natural gas	Other long-term liabilities	15		15
Sold call options – oil	Other long-term liabilities	—		1
Total derivative liabilities		$	390	$	236

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The following tables summarize the before-tax effect of the Company’s derivative instruments on the consolidated statements of operations for the three ~~and nine~~ months ended ~~September 30, 2019~~March 31, 2020 and ~~2018:~~2019:


Unsettled Gain (Loss) on Derivatives Recognized in Earnings	Unsettled Gain (Loss) on Derivatives Recognized in Earnings																												Unsettled Gain (Loss) on Derivatives Recognized in Earnings

Derivative Instrument	Derivative Instrument	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		Consolidated Statement of Operations Classification of Gain (Loss) on Derivatives, Unsettled								For the three months ended March 31,
								2019			2018			2019			2018			Derivative Instrument														2020				2019

			(in millions)																															(in millions)
Purchased fixed price swaps – natural gas															Purchased fixed price swaps – natural gas			Gain (Loss) on Derivatives								$	(1)		$	—
Purchased fixed price swaps – oil	Purchased fixed price swaps – oil	Gain (Loss) on Derivatives	$	—		$	—		$	5		$	—		Purchased fixed price swaps – oil			Gain (Loss) on Derivatives							(5)			4
Fixed price swaps – natural gas	Fixed price swaps – natural gas	Gain (Loss) on Derivatives	(19)			(17)			36			(46)			Fixed price swaps – natural gas			Gain (Loss) on Derivatives							103			(2)
Fixed price swaps – oil	Fixed price swaps – oil	Gain (Loss) on Derivatives	8			—			—			—			Fixed price swaps – oil			Gain (Loss) on Derivatives							118			(13)
Fixed price swaps – ethane															Fixed price swaps – ethane			Gain (Loss) on Derivatives							12			7
Fixed price swaps – propane	Fixed price swaps – propane	Gain (Loss) on Derivatives	10			(10)			19			(19)			Fixed price swaps – propane			Gain (Loss) on Derivatives							36			(4)
Fixed price swaps – ethane		Gain (Loss) on Derivatives	1			(27)			8			(29)
Two-way costless collars – natural gas	Two-way costless collars – natural gas	Gain (Loss) on Derivatives	(11)			2			(2)			4			Two-way costless collars – natural gas			Gain (Loss) on Derivatives							(4)			(1)
Two-way costless collars – oil	Two-way costless collars – oil	Gain (Loss) on Derivatives	—			—			(3)			—			Two-way costless collars – oil			Gain (Loss) on Derivatives							19			(7)
Two-way costless collars – propane	Two-way costless collars – propane	Gain (Loss) on Derivatives	1			—			3			—			Two-way costless collars – propane			Gain (Loss) on Derivatives							2			—
Three-way costless collars – natural gas	Three-way costless collars – natural gas	Gain (Loss) on Derivatives	3			(7)			27			(36)			Three-way costless collars – natural gas			Gain (Loss) on Derivatives							(51)			2
Three-way costless collars – oil	Three-way costless collars – oil	Gain (Loss) on Derivatives	3			—			4			—			Three-way costless collars – oil			Gain (Loss) on Derivatives							25			—
Basis swaps – natural gas	Basis swaps – natural gas	Gain (Loss) on Derivatives	12			(5)			6			11			Basis swaps – natural gas			Gain (Loss) on Derivatives							(1)			(10)
Purchased call options – natural gas	Purchased call options – natural gas	Gain (Loss) on Derivatives	(1)			(2)			(3)			2			Purchased call options – natural gas			Gain (Loss) on Derivatives							1			—
Sold call options – natural gas	Sold call options – natural gas	Gain (Loss) on Derivatives	2			5			8			2			Sold call options – natural gas			Gain (Loss) on Derivatives							(6)			2
Sold call options – oil	Sold call options – oil	Gain (Loss) on Derivatives	—			1			—			(5)			Sold call options – oil			Gain (Loss) on Derivatives							1			—
Storage – fixed price swap		Gain (Loss) on Derivatives	2			—			1			—
Purchased fixed price swap – natural gas storage															Purchased fixed price swap – natural gas storage			Gain (Loss) on Derivatives							(1)			—
Fixed price swap – natural gas storage															Fixed price swap – natural gas storage			Gain (Loss) on Derivatives							(1)			—
Interest rate swaps	Interest rate swaps	Gain (Loss) on Derivatives	1			1			(1)			3			Interest rate swaps			Gain (Loss) on Derivatives							(1)			—
Total gain (loss) on unsettled derivatives	Total gain (loss) on unsettled derivatives					$	12		$	(59)		$	108		$	(113)			Total gain (loss) on unsettled derivatives												$	246		$	(22)

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

Derivative Instrument	Derivative Instrument	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		Consolidated Statement of Operations Classification of Gain (Loss) on Derivatives, Settled									For the three months ended March 31,
								2019			2018			2019			2018			Derivative Instrument													2020			2019

			(in millions)																																		(in millions)
Purchased fixed price swaps – natural gas															Purchased fixed price swaps – natural gas			Gain (Loss) on Derivatives								$	(1)		$	—
Purchased fixed price swaps – oil	Purchased fixed price swaps – oil	Gain (Loss) on Derivatives	$	—		$	—		$	(2)		$	—		Purchased fixed price swaps – oil			Gain (Loss) on Derivatives							—			(1)
Fixed price swaps – natural gas	Fixed price swaps – natural gas	Gain (Loss) on Derivatives	45			5			53			18			Fixed price swaps – natural gas			Gain (Loss) on Derivatives							5			(6)
Fixed price swaps – oil	Fixed price swaps – oil	Gain (Loss) on Derivatives	3			—			7			—			Fixed price swaps – oil			Gain (Loss) on Derivatives							9			2
Fixed price swaps – ethane															Fixed price swaps – ethane			Gain (Loss) on Derivatives							6			1
Fixed price swaps – propane	Fixed price swaps – propane	Gain (Loss) on Derivatives	11			(5)			20			(6)			Fixed price swaps – propane			Gain (Loss) on Derivatives							10			2
Fixed price swaps – ethane		Gain (Loss) on Derivatives	6			(6)			12			(6)
Two-way costless collars – natural gas	Two-way costless collars – natural gas	Gain (Loss) on Derivatives	10			—			12			4			Two-way costless collars – natural gas			Gain (Loss) on Derivatives							6			(1)
Two-way costless collars – oil	Two-way costless collars – oil	Gain (Loss) on Derivatives	2			—			4			—			Two-way costless collars – oil			Gain (Loss) on Derivatives							3			1
Two-way costless collars – propane	Two-way costless collars – propane	Gain (Loss) on Derivatives	1			—			1			—			Two-way costless collars – propane			Gain (Loss) on Derivatives							1			—
Three-way costless collars – natural gas	Three-way costless collars – natural gas	Gain (Loss) on Derivatives	15			5			19			24			Three-way costless collars – natural gas			Gain (Loss) on Derivatives							36			(4)
Three-way costless collars – oil															Three-way costless collars – oil			Gain (Loss) on Derivatives							1			—
Basis swaps – natural gas	Basis swaps – natural gas	Gain (Loss) on Derivatives	(3)			(4)			(11)			(28)			Basis swaps – natural gas			Gain (Loss) on Derivatives							16			(4)
Purchased call options – natural gas		Gain (Loss) on Derivatives	(1)		⁽²⁾	—			(1)		⁽²⁾	2		⁽³⁾
Sold call options – natural gas		Gain (Loss) on Derivatives	—			—			(1)			(1)
Sold call options – oil		Gain (Loss) on Derivatives	—			(1)			—			(2)
Storage – fixed price swap		Gain (Loss) on Derivatives	(1)			—			(1)			—

Fixed price swaps – natural gas storage															Fixed price swaps – natural gas storage			Gain (Loss) on Derivatives							1			—
Total gain (loss) on settled derivatives	Total gain (loss) on settled derivatives					$	88		$	(6)		$	112		$	5			Total gain (loss) on settled derivatives													$	93		$	(10)

Total gain (loss) on derivatives	Total gain (loss) on derivatives					$	100		$	(65)		$	220		$	(108)			Total gain (loss) on derivatives												$	339		$	(32)

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

~~(2)~~Includes $1 million amortization of premiums paid related to certain natural gas purchased call options for the three and nine months ended September 30, 2019, which is included in gain (loss) on derivatives on the consolidated statements of operations.

~~(3)~~Includes $1 million amortization of premiums paid related to certain natural gas purchased call options for the nine months ended September 30, 2018, which is included in gain (loss) on derivatives on the consolidated statements of operations.

2219

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~~(10)~~(8) RECLASSIFICATIONS FROM ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)

In the first ~~half~~quarter of ~~2019,~~2020, changes in accumulated other comprehensive income ~~primarily~~ related to ~~settlements in~~ the Company’s pension and other postretirement benefits. The following tables detail the components of accumulated other comprehensive income and the related tax effects for the ~~nine~~three months ended ~~September 30, 2019:~~March 31, 2020:


(in millions)	(in millions)	Pension and Other Postretirement		Foreign Currency		Total		(in millions)	Pension and Other Postretirement		Foreign Currency		Total
Beginning balance December 31, 2018		$	(22)	$	(14)	$	(36)
Beginning balance December 31, 2019								Beginning balance December 31, 2019	$	(19)	$	(14)	$	(33)
Other comprehensive income before reclassifications	Other comprehensive income before reclassifications	—		—		—		Other comprehensive income before reclassifications	—		—		—
Amounts reclassified from other comprehensive income ⁽¹⁾	Amounts reclassified from other comprehensive income ⁽¹⁾	5		—		5		Amounts reclassified from other comprehensive income ⁽¹⁾	—		—		—
Net current-period other comprehensive income	Net current-period other comprehensive income	5		—		5		Net current-period other comprehensive income	—		—		—
Ending balance September 30, 2019		$	(17)	$	(14)	$	(31)
Ending balance March 31, 2020								Ending balance March 31, 2020	$	(19)	$	(14)	$	(33)

(1)~~See separate table below~~Amounts reclassified from other comprehensive income to earnings were immaterial for ~~details about these reclassifications.~~

Details about Accumulated Other
Comprehensive Income

Affected Line Item in the
Consolidated Statement of Operations

~~Amount Reclassified from Accumulated Other Comprehensive Income~~

For the nine months ended
September 30, 2019

~~(in millions)~~

~~Pension and other postretirement:~~

~~Amortization of prior service cost and net loss~~⁽¹⁾

~~Other Income, Net~~

~~Provision for income taxes~~

~~Net income~~

~~Total reclassifications for the period~~

~~Net income~~

໿

~~(1)~~the three months ended March 31, 2020. See Note 1513 for additional details regarding the Company’s pension and other postretirement benefit plans.

~~(11)~~(9) FAIR VALUE MEASUREMENTS

Assets and liabilities measured at fair value on a recurring basis

The carrying amounts and estimated fair values of the Company’s financial instruments as of ~~September 30, 2019~~March 31, 2020 and December 31, ~~2018~~2019 were as follows:


		September 30, 2019								December 31, 2018									March 31, 2020						December 31, 2019
(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	$	29		$	29		$	201	$	201	Cash and cash equivalents	$	5		$	5		$	5		$	5
2018 revolving credit facility due April 2023		—			—			—		—
2018 revolving credit facility due April 2024												2018 revolving credit facility due April 2024	149			149			34			34
Senior notes⁽¹⁾	Senior notes⁽¹⁾	2,292			2,109			2,342		2,190		Senior notes⁽¹⁾	2,148			1,460			2,228			2,085
Derivative instruments, net	Derivative instruments, net	169		⁽²⁾	169		⁽²⁾	52		52		Derivative instruments, net	401		⁽²⁾	401		⁽²⁾	155		⁽²⁾	155		⁽²⁾

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

(2)Includes $9 million in premiums paid related to certain natural gas fixed price swaps recognized as a component of derivative assets within current assets on the consolidated balance sheet.

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 ~~were~~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. ~~These instruments were previously classified as~~The fair value of the Company's 4.10% Senior Notes due March 2022 is considered to be a Level 2 measurement ~~but substantially all~~on the fair value hierarchy. The fair values of the Company's remaining senior notes ~~were updated to~~are considered the be a Level 1 ~~measurement in the second quarter of 2018~~

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~~as the market activity of the Company’s debt has resulted in timely quoted prices. The 3.42% Senior Notes due January 2020 remain a Level 2 measurement due to relative market inactivity.~~

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 ~~all~~its derivative instruments isbased upon a pricing model that utilizes market-based inputs, including, but not limited to, the ~~amount at which~~contractual price of the ~~instrument could be exchanged currently between willing parties. The amounts~~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 ~~quoted market prices, best estimates obtained from counterparties~~published credit default swap rates and ~~an option pricing model, when necessary, for price option contracts.~~the duration of each

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outstanding derivative position. As of March 31, 2020, the impact of non-performance risk on the fair value of the Company’s net derivative asset position was a net reduction of less than $1 million.

The Company has classified its ~~derivatives~~derivative instruments into ~~these~~ levels depending upon the data utilized to determine their fair values. The Company’s fixed price swaps (Level 2) are estimated using third-party discounted cash flow calculations using the New York Mercantile Exchange (“NYMEX”) futures index for natural gas and oil derivatives and Oil Price Information Service (“OPIS”) for ethane and propane derivatives. The Company utilizes discounted cash flow models for valuing its interest rate derivatives (Level 2). The net derivative values attributable to the Company’s interest rate derivative contracts as of ~~September 30, 2019~~March 31, 2020 are based on (i) the contracted notional amounts, (ii) active market-quoted LIBOR yield curves and (iii) the applicable credit-adjusted risk-free rate yield curve.

The Company’s call 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. The Company’s basis swaps (Level 2) are estimated using third-party calculations based upon forward commodity price curves. These instruments were previously classified as a Level 3 measurement in the fair value hierarchy but were updated to a Level 2 measurement in the second quarter of 2018 as a result of the Company’s ability to derive volatility inputs and forward commodity price curves from directly observable sources.

Inputs to the Black-Scholes model, including the volatility input, are obtained from a third-party pricing source, with independent verification of the most significant inputs on a monthly basis. An increase (decrease) in volatility would result in an increase (decrease) in fair value measurement, respectively.

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

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

September 30, 2019
Fair Value Measurements Using:
(in millions) Quoted Prices in Active Markets (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) Assets (Liabilities) at Fair Value
Assets
Fixed price swap – natural gas⁽¹⁾
$ — $ 73 $ — $ 73
Fixed price swap – oil — 19 — 19
Fixed price swap – propane — 30 — 30
Fixed price swap – ethane — 13 — 13
Two-way costless collar – natural gas — 2 — 2
Two-way costless collar – oil — 7 — 7
Two-way costless collar – propane — 3 — 3
Three-way costless collar – natural gas — 147 — 147
Three-way costless collar – oil — 13 — 13
Basis swap – natural gas — 24 — 24
Purchased call option – natural gas — 3 — 3
Storage – fixed price swap — 1 — 1
Liabilities
Purchased fixed price swap – oil — (1) — (1)
Three-way costless collar – natural gas — (113) — (113)
Three-way costless collar – oil — (9) — (9)
Basis swap – natural gas — (29) — (29)
Sold call option – natural gas — (14) — (14)
Total $ — $ 169 $ — $ 169


	March 31, 2020
	Fair Value Measurements Using:
(in millions)	Quoted Prices in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Assets (Liabilities) at Fair Value
Assets
Purchased fixed price swaps	$	—	$	1	$	—	$	1
Fixed price swaps ⁽¹⁾	—		384		—		384
Two-way costless collars	—		50		—		50
Three-way costless collars	—		325		—		325
Basis swaps	—		27		—		27
Purchased call options	—		4		—		4


Liabilities
Purchased fixed price swaps	—		(8)		—		(8)

Two-way costless collars	—		(25)		—		(25)
Three-way costless collars	—		(309)		—		(309)
Basis swaps	—		(22)		—		(22)
Sold call options	—		(24)		—		(24)
Purchased fixed price swaps – storage	—		(1)		—		(1)
Interest rate swaps	—		(1)		—		(1)
Total⁽²⁾	$	—	$	401	$	—	$	401

(1)Includes $9 million in premiums paid related to certain natural gas fixed price swaps recognized as a component of derivative assets within current assets on the consolidated balance sheet at ~~September 30,~~March 31, 2020. As certain natural gas fixed price swaps settle, the premium will be amortized and recognized as a component of gain (loss) on derivatives on the consolidated statements of operations.

(2)Includes a net fair value reduction of less than $1 million related to estimated nonperformance risk.

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	December 31, 2019
	Fair Value Measurements Using:
(in millions)	Quoted Prices in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Assets (Liabilities) at Fair Value
Assets

Fixed price swaps ⁽¹⁾	$	—	$	124	$	—	$	124
Two-way costless collars	—		21		—		21
Three-way costless collars	—		210		—		210
Basis Swaps	—		32		—		32
Purchased call options	—		3		—		3
Fixed price swaps - storage	—		1		—		1
Liabilities
Purchased fixed price swaps	—		(1)		—		(1)
Fixed price swaps	—		(9)		—		(9)
Two-way costless collars	—		(13)		—		(13)
Three-way costless collars	—		(168)		—		(168)
Basis Swaps	—		(26)		—		(26)
Sold call options	—		(19)		—		(19)


Total	$	—	$	155	$	—	$	155

(1)Includes $9 million in premiums paid related to certain natural gas fixed price swaps recognized as a component of derivative assets within current assets on the consolidated balance sheet at December 31, 2019. As certain natural gas fixed price swaps settle, the premium will be amortized and recognized as a component of gain (loss) on derivatives on the consolidated statements of operations.

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December 31, 2018
Fair Value Measurements Using:
(in millions) Quoted Prices in Active Markets (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) Assets (Liabilities) at Fair Value
Assets
Fixed price swap – natural gas $ — $ 38 $ — $ 38
Fixed price swap – oil — 19 — 19
Fixed price swap – propane — 11 — 11
Fixed price swap – ethane — 8 — 8
Two-way costless collar – natural gas — 11 — 11
Two-way costless collar – oil — 11 — 11
Three-way costless collar – natural gas — 75 — 75
Basis swap – natural gas — 11 — 11
Purchased call option – natural gas — 6 — 6
Interest rate swap — 1 — 1
Liabilities
Purchased fixed price swap – oil — (6) — (6)
Fixed price swap – natural gas — (10) — (10)
Fixed price swap – ethane — (3) — (3)
Two-way costless collar – natural gas — (7) — (7)
Two-way costless collar – oil — (1) — (1)
Three-way costless collar – natural gas — (68) — (68)
Basis swap – natural gas — (22) — (22)
Sold call option – natural gas — (22) — (22)
Total $ — $ 52 $ — $ 52

The table below presents reconciliations for the change in net fair value of derivative assets and liabilities measured at fair value on a recurring basis using significant unobservable inputs (Level 3) for the nine months ended September 30, 2019 and 2018. There were no derivatives presented as Level 3 in the third quarters of 2019 and 2018. The fair values of Level 3 derivative instruments ~~were~~are estimated using proprietary valuation models that ~~utilized~~utilize both market observable and unobservable parameters. Level 3 instruments ~~presented in the table consisted~~consist of net derivatives valued using pricing models incorporating assumptions that, in the Company’s judgment, ~~reflected~~reflect reasonable assumptions a marketplace participant would ~~have used as of September 30, 2018. Commodity derivatives previously presented as~~use. There were no Level 3 ~~were transferred to Level 2~~derivatives in the ~~second quarter~~first quarters of ~~2018 as the Company moved from using proprietary volatility inputs~~2020 and ~~forward curves to more widely available published information, increasing market observability.~~

໿

For the nine months ended September 30,
(in millions) 2019
2018
Balance at beginning of period $ —
$ 22
Total gains (losses):
Included in earnings —
(17)
Settlements — 1
⁽¹⁾
Transfers into/out of Level 3 —
(6)
⁽²⁾
Balance at end of period $ —
$ —
Change in gains (losses) included in earnings relating to derivatives still held as of September 30 $ —
$ —

~~(1)Includes $1 million amortization of premiums paid related to certain purchased natural gas call options for the nine months ended September 30, 2018.~~

~~(1)~~Commodity derivatives previously presented as Level 3 were transferred to Level 2 in the second quarter of 2018 as the Company moved from using proprietary volatility inputs and forward curves to more widely available published information, increasing market observability.

~~Assets and liabilities measured at fair value on a nonrecurring basis~~

In accordance with accounting guidance for Property, Plant and Equipment, assets held for sale are measured at the lower of the carrying value or fair value less costs to sell. Because the assets outside of the full cost pool included in the Fayetteville Shale sale met the criteria for held for sale accounting as of September 30, 2018, the Company determined the carrying value of certain non-full cost pool assets exceeded the fair value less costs to sell, the Company recorded an impairment charge of $161 million during the third quarter of 2018, of which $145 million related to midstream gathering assets and $15 million related to E&P assets which were both reflected as assets held for sale as of September 30, 2018. Additionally, the Company recorded an $1 million impairment related to other non-core assets that were not included in the sale. The estimated fair value

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of the gathering assets was based on an estimated discounted cash flow model and market assumptions. The significant Level 3 assumptions used in the calculation of estimated discounted cash flows included future commodity prices, projections of estimated quantities of natural gas reserves, operating costs, projections of future rates of production, inflation factors and risk adjusted discount rates.2019.

~~(12)~~(10) DEBT

The components of debt as of ~~September 30, 2019~~March 31, 2020 and December 31, ~~2018~~2019 consisted of the following:


		September 30, 2019																	March 31, 2020
(in millions)	(in millions)	Debt Instrument		Unamortized Issuance Expense			Unamortized Debt Discount		Total		(in millions)	Debt Instrument		Unamortized Issuance Expense			Unamortized Debt Discount		Total
Current portion of long-term debt:
4.05% Senior Notes due January 2020⁽¹⁾		$	52	$	—		$	—	$	52
Total current portion of long-term debt		$	52	$	—		$	—	$	52

Long-term debt:	Long-term debt:										Long-term debt:
Variable rate (3.420% at September 30, 2019) 2018 revolving credit facility, due April 2023		$	—	$	—	⁽²⁾	$	—	$	—
Variable rate (2.120% at March 31, 2020) 2018 revolving credit facility due April 2024											Variable rate (2.120% at March 31, 2020) 2018 revolving credit facility due April 2024	$	149	$	—	⁽¹⁾	$	—	$	149
4.10% Senior Notes due March 2022	4.10% Senior Notes due March 2022	213		(1)			—		212		4.10% Senior Notes due March 2022	210		(1)			—		209
4.95% Senior Notes due January 2025⁽³⁾⁽²⁾	4.95% Senior Notes due January 2025⁽³⁾⁽²⁾	896		(7)			(1)		888		4.95% Senior Notes due January 2025⁽³⁾⁽²⁾	864		(5)			(1)		858
7.50% Senior Notes due April 2026⁽³⁾		639		(7)			—		632
7.75% Senior Notes due October 2027⁽³⁾		492		(5)			—		487
7.50% Senior Notes due April 2026											7.50% Senior Notes due April 2026	621		(6)			—		615
7.75% Senior Notes due October 2027											7.75% Senior Notes due October 2027	453		(5)			—		448
Total long-term debt	Total long-term debt	$	2,240	$	(20)		$	(1)	$	2,219	Total long-term debt	$	2,297	$	(17)		$	(1)	$	2,279

Total debt		$	2,292	$	(20)		$	(1)	$	2,271

		December 31, 2018																	December 31, 2019
(in millions)	(in millions)	Debt Instrument		Unamortized Issuance Expense			Unamortized Debt Discount		Total		(in millions)	Debt Instrument		Unamortized Issuance Expense			Unamortized Debt Discount		Total
Long-term debt:	Long-term debt:										Long-term debt:
Variable rate (3.920% at December 31, 2018) 2018 term loan facility, due April 2023		$	—	$	—	⁽²⁾	$	—	$	—
4.05% Senior Notes due January 2020⁽¹⁾		52		—			—		52
Variable rate (4.310% at December 31, 2019) 2018 term loan facility due April 2024											Variable rate (4.310% at December 31, 2019) 2018 term loan facility due April 2024	$	34	$	—	⁽¹⁾	$	—	$	34
4.10% Senior Notes due March 2022	4.10% Senior Notes due March 2022	213		(1)			—		212		4.10% Senior Notes due March 2022	213		(1)			—		212
4.95% Senior Notes due January 2025⁽¹⁾		927		(7)			(1)		919
4.95% Senior Notes due January 2025⁽²⁾											4.95% Senior Notes due January 2025⁽²⁾	892		(5)			(1)		886
7.50% Senior Notes due April 2026	7.50% Senior Notes due April 2026	650		(8)			—		642		7.50% Senior Notes due April 2026	639		(7)			—		632
7.75% Senior Notes due October 2027	7.75% Senior Notes due October 2027	500		(7)			—		493		7.75% Senior Notes due October 2027	484		(6)			—		478
Total long-term debt	Total long-term debt	$	2,342	$	(23)		$	(1)	$	2,318	Total long-term debt	$	2,262	$	(19)		$	(1)	$	2,242

(1)In February and June 2016, Moody’s and S&P downgraded certain senior notes, increasing the interest rates by 175 basis points effective July 2016. As a result of the downgrades, interest rates increased to 5.80% for theAt March 31, 2020 Notes and 6.70% for the 2025 Notes. S&P and Moody’s upgraded certain senior notes in April and May 2018, respectively. As a result of these upgrades, interest rates decreased to 5.30% for the 2020 Notes and 6.20% for the 2025 Notes effective July 2018. The first coupon payment to the bondholders at the lower interest rate was paid in January 2019.

~~(2)At September 30, 2019~~ and December 31, ~~2018,~~2019, unamortized issuance expense of $9$10 million and ~~$12~~$11 million, respectively, associated with the 2018 ~~revolving~~ credit facility is(as defined below) was classified as other long-term assets on the consolidated balance sheets.

~~(3)~~Table of Contents~~During~~

(2)At March 31, 2020 and December 31, 2019, respectively, the ~~third quarter of 2019,~~interest rate was 6.20% for the ~~Company purchased $31 million in~~ 2025 Notes, ~~$11 million~~reflecting a net downgrade in ~~2026 Notes and $8 million in 2027 Notes for $43 million in cash, reducing~~ the Company’s ~~outstanding debt by $50 million.~~bond ratings since the initial offering. This ~~resulted~~rate has been in ~~a gain~~effect since January 2019. On April 7, 2020, S&P downgraded the Company’s bond rating to BB-, which has the effect of increasing the interest rate on ~~early extinguishment of debt of $7 million for~~ the ~~three and nine months ended September 30, 2019.~~2025 Notes to 6.45%. The first coupon payment to the bondholders at the higher interest rate will be paid in January 2021.

Credit Facilities

2018 Revolving Credit Facility

In April 2018, the Company replaced its ~~2016~~ credit facility ~~(which consisted of a $1,191 million secured term loan and an unsecured $743 million revolving credit facility)~~that was entered into in 2016 with a new revolving credit facility (the “2018 credit facility”)~~. Concurrent~~ with ~~the closing~~a group of ~~the 2018 credit facility agreement on~~banks that, as amended, has a maturity date of April 26, 2018, the Company repaid the $1,191 million secured term loan balance and recognized a loss on early debt extinguishment of $8 million on the consolidated income statement related to the unamortized issuance expense. In addition, approximately $4 million of unamortized issuance expense associated with the closed $743 million revolving credit facility was carried forward into the unamortized issuance expenses of the 2018 credit facility.

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2024. The 2018 credit facility has an aggregate maximum revolving credit amount of $3.5 billion ~~with a current aggregate commitment of $2.0 billion~~ and, at March 31, 2020, had a borrowing base ~~(limit on availability) that~~of $2.1 billion with aggregate bank commitments of $2.0 billion. The Company may utilize the credit facility in the form of loans and letters of credit. The borrowing base is ~~redetermined each~~subject to redetermination at least twice a year, in April and October. On April 13, 2020, the banks participating in the 2018 credit facility redetermined the borrowing base to be $1.8 billion, which also changed the aggregate commitments to that amount. The 2018 credit facility is secured by substantially all of the assets owned by the Company and its subsidiaries. The permitted lien provisions in the senior note indentures currently limit liens securing indebtedness to the greater of $2.0 billion ~~and~~or 25% of adjusted consolidated net tangible assets. On October 8, 2019, the Company entered into an amendment to the 2018 credit facility that, among other things, established the October 2019 borrowing base at $2.1 billion and extended the maturity date to April 2024.

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 ranges from 1.50% to 2.50% based on the Company’s utilization of the ~~borrowing base under 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 ranges from 0.50% to 1.50% based on the Company’s utilization of ~~the borrowing base under~~ 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 (i) with respect to each fiscal quarter ending during the period from June 30, 2018 through March 31, 2019, 4.50 to 1.00, (ii) with respect to each fiscal quarter ending during the period from June 30, 2019 through March 31, 2020, 4.25 to 1.00, and (iii) 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 ~~agreement,~~facility, excludes the effects of interest expense, depreciation, depletion and amortization, income tax, any non-cash impacts from impairments, certain non-cash hedging activities, stock-based compensation expense, non-cash gains or losses on asset sales, unamortized issuance cost, unamortized debt discount and certain restructuring costs.

The 2018 credit facility contains customary events of default that include, among other things, the failure to comply with the financial covenants described above, non-payment of principal, interest or fees, violation of covenants, inaccuracy of representations and warranties, bankruptcy and insolvency events, material judgments and cross-defaults to material indebtedness. If an event of default occurs and is continuing, all amounts outstanding under the 2018 credit facility may become immediately due and payable.

As of ~~September 30, 2019,~~March 31, 2020, the Company was in compliance with all of the covenants contained in the credit agreement governing the 2018 credit facility. Beginning late in the first quarter of 2020, decreased transportation, manufacturing and general economic activity levels prompted by COVID-19 and related governmental and societal actions reduced the demand for

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oil-based products such as gasoline, jet fuel and other refined products, as well as NGLs. Reduced demand, along with geopolitical events such as the disagreements between the Organization of Petroleum Exporting Countries (“OPEC”) and Russia on production levels, have caused a significant decline in commodity pricing since the beginning of 2020. Additionally, space to store oil and condensate production is reaching or may reach capacity in some areas, which has prompted purchasers of oil and condensate to reduce future purchase levels and, in some cases, to claim force majeure for purchases already contracted. Consequently, during the second half of April 2020, the Company received notices from two companies asserting force majeure and curtailing approximately 3,200 gross barrels per day of condensate. To the extent that this decreased demand for the Company’s commodities continues or storage for its production is not available, Southwestern expects to reduce production from or completely shut in portions of its currently producing wells. If the current market conditions persist or deteriorate further, the Company would proactively continue to adjust its activities and plans. Absent any actions taken by Southwestern, and under these conditions or if they worsen, current modeling indicates that the Company would not be in compliance with its Net Leverage Ratio covenant under the 2018 credit facility in late 2020. Under such circumstances, Southwestern would seek waivers or a modification of the ~~credit agreement.~~covenant package from the lenders in advance of any covenant non-compliance. Additionally, the Company has other mitigating options including but not limited to the monetization of derivative asset positions, the reduction or elimination of non-essential expenditures or the sale of non-core assets.

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. ~~See~~ ~~Note 19~~ ~~for the Company’s Condensed Consolidated Financial Information, presented in accordance with Rule 3-10 of Regulation S-X.~~

As of ~~September 30, 2019,~~March 31, 2020, the Company had $172 million in letters of credit and 0$149 million borrowings outstanding under the 2018 ~~revolving~~ credit facility.

~~Table~~ As of ~~Contents~~

April 28, 2020, the Company had been requested to post an additional $150 million in letters of credit related to firm transportation. The Company currently does not anticipate being required to supply a materially greater amount of letters of credit under its existing contracts.

Senior Notes

In January 2015, the Company completed a public offering of ~~$850 million aggregate principal amount of its 4.05% senior notes due 2020 (the “2020 Notes”) and~~ $1.0 billion aggregate principal amount of its 4.95% senior notes due 2025 (the “2025 Notes” ~~together with the 2020 Notes, the “Notes”~~). The interest ~~rates~~rate on the 2025 Notes ~~are~~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. ~~In February and June 2016, Moody’s and~~At March 31, 2020, the interest rate for the 2025 Notes was 6.20%, reflecting a net downgrade in the Company’s bond ratings since the initial offering. This rate has been in effect since January 2019. On April 7, 2020, S&P downgraded the ~~Notes,~~Company’s bond rating to BB- which had the effect of increasing the interest ~~rates by 175 basis points effective July 2016. As a result of these downgrades, interest rates increased to 5.80% for the 2020 Notes and 6.70% for~~rate on the 2025 ~~Notes.~~Notes to 6.45%. The first coupon payment to the bondholders at the higher interest rate will be paid in January 2021. In the event of future downgrades, the coupons for this series of notes ~~are~~have been capped at ~~6.05% and~~ 6.95%, respectively. The first coupon payment to the bondholders at the higher interest rates was paid in January 2017. S&P and Moody’s upgraded the Notes in April and May 2018, respectively. As a result of these upgrades, interest rates decreased to 5.30% for the 2020 Notes and 6.20% for the 2025 Notes effective July 2018. The first coupon payment to the bondholders at the lower interest rates was paid in January 2019..

In the ~~third~~first quarter of ~~2019,~~2020, the Company repurchased ~~$31~~$3 million of its 4.10% Senior Notes due 2022, $28 million of its 4.95% Senior Notes due 2025, ~~$11~~$18 million of its 7.50% Senior Notes due ~~2025~~2026 and $8$31 million of its 7.75% Senior Notes due ~~2026~~2027 for ~~$43~~$52 million, and recognized a $7$28 million gain on the extinguishment of debt.

~~(13)~~(11) COMMITMENTS AND CONTINGENCIES

Operating Commitments and Contingencies

As of ~~September 30, 2019,~~March 31, 2020, 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 ~~$8.2~~$7.6 billion, ~~$752~~$411 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 ~~$323 million~~$1.1 billion of that amount. As of ~~September 30, 2019,~~March 31, 2020, 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	$	7,442	$	681	$	1,272	$	1,075	$	1,528	$	2,886	Infrastructure currently in service	$	7,199	$	753	$	1,339	$	1,098	$	1,524	$	2,485
Pending regulatory approval and/or construction ⁽¹⁾	Pending regulatory approval and/or construction ⁽¹⁾	752		19		73		75		139		446		Pending regulatory approval and/or construction ⁽¹⁾	411		1		17		23		74		296
Total transportation charges	Total transportation charges	$	8,194	$	700	$	1,345	$	1,150	$	1,667	$	3,332	Total transportation charges	$	7,610	$	754	$	1,356	$	1,121	$	1,598	$	2,781

(1)Based on estimated in-service dates as of ~~September 30, 2019.~~March 31, 2020.

In December 2018, the Company closed the Fayetteville Shale ~~sale. The Company~~sale and retained certain contractual commitments related to firm transportation, with the buyer obligated to pay the transportation provider directly for these charges. As of ~~September 30, 2019,~~March 31,

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2020, approximately ~~$135~~$81 million of these contractual commitments remain of which the Company will reimburse the buyer for certain of these potential obligations up to approximately ~~$70~~$45 million through December 2020 depending on the buyer’s actual use, and has recorded a ~~$57~~$36 million liability for the estimated future payments, down from ~~$88~~$46 million recorded at December 31, ~~2018.~~2019.

In the first quarter of 2019, the Company agreed to purchase firm transportation with pipelines in the Appalachian Basin starting in 2021 and running through 2032 totaling $357 million in total contractual commitments, which is presented in the table above; the seller has agreed to reimburse $133 million of these commitments.

In ~~July 2019,~~February 2020, the Company ~~terminated~~was notified that the proposed Constitution pipeline project was cancelled and that the Company was released from a firm transportation agreement with its ~~existing lease agreement and entered into a new lease agreement for a smaller portion of~~sponsor. Prior to its cancellation, the ~~headquarters office building, resulting in a~~Company had contractual ~~commitment~~commitments totaling ~~$87~~$512 million over the next ~~ten~~17 years ~~as of September 30, 2019.~~related to the Constitution pipeline project.

Environmental Risk

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

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Litigation

The Company is subject to various litigation, claims and proceedings, ~~that~~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 ~~such items~~litigation, claims and proceedings when a liability is both probable and the amount can be reasonably estimated. As of ~~September 30, 2019,~~March 31, 2020, the Company does not currently have any material amounts accrued related to litigation matters. 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.

~~As of September 30, 2019, all certified~~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 ~~actions~~action in the 61st District Court in Harris County, Texas, against the Company, ~~regarding royalty payments in Arkansas have been resolved favorably to~~certain of its former officers and current and former directors and the ~~Company or settled. Some actions filed~~underwriters on behalf of ~~mineral interest owners who opted out~~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 ~~class actions remain pending, but~~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, which remains pending. The Company carries insurance for the claims asserted against it and the officer and director defendants, and the carrier has accepted coverage. The Company denies all allegations and intends to continue to defend this case vigorously. The Company does not expect ~~these cases~~this case to have a material ~~impact~~adverse effect on ~~its financial position,~~the results of operations, financial position or cash ~~flows.~~flows of the Company after taking insurance into account. Additionally, it is not possible at this time to estimate the amount of any additional loss, or range of loss, that is reasonably possible.

Indemnifications

The Company has provided certain indemnifications to various third parties, including in relation to asset and entity dispositions, securities offerings and other ~~financings.~~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 material liabilities have been recognized in connection with these indemnifications.

~~(14)~~

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(12) INCOME TAXES

The Company’s effective tax rate was approximately ~~18% and 0%~~(36)% for the three months ended ~~September 30, 2019 and 2018, respectively, and (105)% and 0% for the nine months ended September 30, 2019 and 2018, respectively.~~March 31, 2020. The change in the effective tax rate for the three ~~and nine~~ months ended ~~September 30, 2019 was primarily~~March 31, 2020 related to the ~~effect~~effects of ~~releasing the~~recording a valuation ~~allowances previously recorded~~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 ~~the~~ current and forecasted business economics of the oil and gas industry.

~~For~~Due to significant pricing declines and the ~~year~~material write-down of the carrying value of the Company’s natural gas and oil properties in the three months ended ~~December~~March 31, ~~2018,~~2020, the Company ~~maintained a full valuation allowance against its deferred tax assets based on its conclusion, considering all available evidence (both positive and negative),~~concluded that it was more likely than not that these deferred tax assets will not be realized and recorded a discrete tax expense in the period of $408 million for the increase in its valuation allowance. The net change in valuation allowance is reflected as a component of income tax expense. The Company also has 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 ~~assets would not~~asset considered realizable, however, could be ~~realized. A significant item~~adjusted based on changes in subjective estimates of future taxable income or if objective negative evidence ~~considered~~is no longer present.

The Company’s effective tax rate was approximately (254)% for the ~~cumulative pre-tax loss incurred over~~three months ended March 31, 2019. The effective tax rate for the ~~three-year period~~three months ended ~~December~~March 31, ~~2018,~~2019 was primarily ~~due to impairments~~the effect of ~~proved natural gas and oil properties recognized in 2015 and 2016.~~releasing the valuation allowances previously recorded against the Company’s deferred tax assets. As of the first quarter of 2019, the Company had sustained and projected to sustain a three-year cumulative level of profitability. Based on this factor and other positive evidence ~~including forecasted income,~~available at the time, the Company concluded that it was more likely than not that the deferred tax assets would be realized and determined $522 million of the valuation allowance ~~will~~would be ~~released. For the nine months ended September 30,~~released during 2019, ~~the Company recorded~~of which $426 million was released on a discrete ~~tax benefit~~basis in the first quarter of $399 million, with the remainder being recognized through current period activity. The Company expects to retain a valuation allowance of $87 million related to net operating losses in jurisdictions in which it no longer operates.2019.

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~~(15)~~(13) 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. Net periodic pension costs include the following components for the three ~~and nine~~ months ended ~~September 30, 2019~~March 31, 2020 and ~~2018:~~2019:

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) 2019 2018 2019 2018
Service cost General and administrative expenses $ 1 $ 2 $ 5 $ 8
Interest cost Other Income (Loss), Net 2 1 4 4
Expected return on plan assets Other Income (Loss), Net (1) (2) (4) (6)
Amortization of prior service cost Other Income (Loss), Net — — — —
Amortization of net loss Other Income (Loss), Net — 1 1 1
Settlement loss Other Income (Loss), Net 1 — 5 —
Net periodic benefit cost $ 3 $ 2 $ 11 $ 7

The Company recognized a $5 million non-cash settlement loss related to $19 million of lump sum payments from the pension plan for the nine months ended September 30, 2019 for employees who were terminated primarily as a result of the Fayetteville Shale sale.



	Consolidated Statements of Operations Classification of Net Periodic Benefit Cost	For the three months ended March 31,
(in millions)				2020			2019
Service cost	General and administrative expenses	$	2		$	2
Interest cost	Other Income (Loss), Net	1			1
Expected return on plan assets	Other Income (Loss), Net	(1)			(2)
Amortization of prior service cost	Other Income (Loss), Net	—			—
Amortization of net loss	Other Income (Loss), Net	—			1

Net periodic benefit cost		$	2		$	2

The Company’s other postretirement benefit plan had a net periodic benefit cost of $1 million and less than $1 million for the three months ended ~~September 30,~~March 31, 2020 and 2019, ~~and 2018 and a net periodic benefit cost of $1 million and $2 million for the nine months ended September 30, 2019 and 2018,~~ respectively.

As of ~~September 30, 2019,~~March 31, 2020, the Company has contributed ~~$12~~$5 million to the pension and other postretirement benefit plans and ~~does not expect~~expects to ~~further~~ contribute an additional $7 million to its pension plan during the remainder of ~~2019.~~2020. The Company recognized liabilities of ~~$26~~$27 million and $13 million related to its pension and other postretirement benefits, respectively, as of ~~September 30, 2019,~~March 31, 2020, compared to liabilities of ~~$34~~$30 million and $13 million as of December 31, ~~2018,~~2019, respectively.

The Company maintains a non-qualified deferred compensation supplemental retirement savings plan (“Non-Qualified Plan”) for certain key employees who may elect to defer and contribute a portion of their compensation, as permitted by the Non-Qualified Plan. Shares of the Company’s common stock purchased under the terms of the Non-Qualified Plan are included in treasury stock and totaled 3,632 shares and 5,115 shares ~~and 10,653 shares~~ at ~~September 30, 2019~~March 31, 2020 and December 31, ~~2018,~~2019, respectively.

~~(16) STOCK-BASED~~

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(14) LONG-TERM INCENTIVE COMPENSATION

The Company’s long-term incentive compensation plans consist of a combination of stock-based awards that derive their value directly or indirectly from the Company’s common stock price, and cash-based awards that are fixed in amount but subject to meeting annual performance thresholds. In March 2020, the Company ~~recognized the following amounts in total employee stock-based compensation costs~~issued its first long-term fixed cash-based awards. The resulting impact to general and administrative expenses as well as capitalized expenses was immaterial for the ~~three and nine months ended September 30, 2019 and 2018:~~first quarter of 2020.

For the three months ended September 30, For the nine months ended September 30,
(in millions) 2019 2018 2019 2018
Stock-based compensation cost – expensed $ 1 $ 7 $ 12 $ 20
Stock-based compensation cost – capitalized 1 3 7 10

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 ~~and capitalized 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. ~~A portion of this general and administrative expense is capitalized into natural gas and oil properties, included in property and equipment.~~ 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, or restricted stock units, or performance cash awards to employees and directors which generally vest over four 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.

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In ~~December 2018,~~February 2020, the Company ~~closed the sale~~notified employees of a workforce reduction plan as a result of a strategic realignment of the equity in certain of its subsidiaries that owned and operated its Fayetteville Shale E&P and related midstream gathering assets in Arkansas. As part of this transaction, most employees associated with those assets became employeesCompany’s organizational structure. This reduction was substantially complete by the end of the ~~buyer although the employment~~first quarter of ~~some was terminated. All affected~~2020. Affected employees were offered a severance package which, ~~included a one-time cash payment depending on length of service and,~~ if applicable, included the current value of ~~a portion of equity~~unvested long-term incentive awards that were forfeited. ~~Stock-based~~

The Company recognized the following amounts in total employee stock-based compensation costs ~~recognized prior to the cancellation as either general and administrative expense or capitalized expense were reversed and the severance payments were subsequently recognized as restructuring charges~~ for the ~~year ended December 31, 2018 and the nine~~three months ended ~~September 30, 2019 on~~March 31, 2020 and 2019:


	For the three months ended March 31,
(in millions)	2020			2019
Stock-based compensation cost – expensed	$	—	⁽¹⁾	$	7
Stock-based compensation cost – capitalized	—		⁽¹⁾	4

(1)For the ~~consolidated statements~~three months ended March 31, 2020, a decrease in the value of ~~operations.~~liability-based awards approximately offset the amounts expensed and capitalized for equity-based awards.

Equity-Classified Awards

The Company recognized the following amounts in employee equity-classified stock-based compensation costs for the three ~~and nine~~ months ended ~~September 30, 2019~~March 31, 2020 and ~~2018:~~2019:


		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)	2019		2018		2019		2018		(in millions)	2020		2019
Equity-classified awards – expensed	Equity-classified awards – expensed	$	2	$	3	$	6	$	12	Equity-classified awards – expensed	$	1	$	2
Equity-classified awards – capitalized	Equity-classified awards – capitalized	1		2		3		6		Equity-classified awards – capitalized	—		1

As of ~~September 30, 2019,~~March 31, 2020, there was $9$4 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 ~~1.1~~0.9 years.

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Equity-Classified Stock Options

The following table summarizes equity-classified stock option activity for the ~~nine~~three months ended ~~September 30, 2019~~March 31, 2020 and provides information for options outstanding and options exercisable as of ~~September 30, 2019:~~March 31, 2020:


		Number of Options	Weighted Average Exercise Price			Number of Options	Weighted Average Exercise Price
		(in thousands)				(in thousands)
Outstanding at December 31, 2018		5,178	$	17.06
Outstanding at December 31, 2019					Outstanding at December 31, 2019	4,635	$	15.26
Granted	Granted	—	$	—	Granted	—	$	—
Exercised	Exercised	—	$	—	Exercised	—	$	—
Forfeited or expired	Forfeited or expired	(76)	$	19.38	Forfeited or expired	(62)	$	15.11
Outstanding at September 30, 2019		5,102	$	17.02
Exercisable at September 30, 2019		4,680	$	17.85
Outstanding at March 31, 2020					Outstanding at March 31, 2020	4,573	$	15.27
Exercisable at March 31, 2020					Exercisable at March 31, 2020	4,478	$	15.48

Equity-Classified Restricted Stock

The following table summarizes equity-classified restricted stock activity for the ~~nine~~three months ended ~~September 30, 2019~~March 31, 2020 and provides information for unvested shares as of ~~September 30, 2019:~~March 31, 2020:

Number
of Shares Weighted Average
Fair Value
(in thousands)
Unvested shares at December 31, 2018 2,717 $ 7.91
Granted 477 $ 3.09
Vested (1,101) $ 7.02
Forfeited (210) $ 8.38
Unvested shares at September 30, 2019 1,883 $ 7.17

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	Number of Shares	Weighted Average Fair Value
	(in thousands)
Unvested shares at December 31, 2019	1,480	$	7.00
Granted	12	$	2.42
Vested	(522)	$	7.75
Forfeited	(167)	$	8.59
Unvested shares at March 31, 2020	803	$	6.11

Equity-Classified Performance Units

The following table summarizes equity-classified performance unit activity for the ~~nine~~three months ended ~~September 30, 2019~~March 31, 2020 and provides information for unvested units as of ~~September 30, 2019.~~March 31, 2020. The performance unit awards granted in ~~2017~~2018 include a market condition based exclusively on the ~~fair value of the~~ Total Shareholder Return (“TSR”), aswith their fair value calculated by a Monte Carlo model. The total fair value of the performance units is amortized to compensation expense on a straight line basis over the vesting period of the award. The grant date fair value is calculated using the closing price of the Company’s common stock at the grant date.


		Number of Shares ⁽¹⁾	Weighted Average Fair Value			Number of Units ⁽¹⁾	Weighted Average Fair Value
		(in thousands)				(in thousands)
Unvested units at December 31, 2018		598	$	10.01
Unvested units at December 31, 2019					Unvested units at December 31, 2019	178	$	10.47
Granted	Granted	—	$	—	Granted	—	$	—
Vested	Vested	(371)	$	9.73	Vested	(178)	$	10.47
Forfeited	Forfeited	(30)	$	10.47	Forfeited	—	$	—
Unvested units at September 30, 2019		197	$	10.47
Unvested units at March 31, 2020					Unvested units at March 31, 2020	—	$	—

(1)The actual payout of shares may range from a minimum of 0zero shares to a maximum of 2two shares per unit contingent upon TSR. The performance units have a three-year vesting term and the actual disbursement of shares, if any, is determined during the first quarter following the end of the three-year vesting period.

Liability-Classified Awards

The Company recognized the following amounts in employee liability-classified stock-based compensation costs for the three ~~and nine~~ months ended ~~September 30, 2019:~~March 31, 2020:


		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)	2019		2018		2019		2018		(in millions)	2020		2019
Liability-classified stock-based compensation cost – expensed	Liability-classified stock-based compensation cost – expensed	$	(1)	$	4	$	6	$	8	Liability-classified stock-based compensation cost – expensed	$	(1)	$	5
Liability-classified stock-based compensation cost – capitalized	Liability-classified stock-based compensation cost – capitalized	—		1		4		4		Liability-classified stock-based compensation cost – capitalized	—		3

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Liability-Classified Restricted Stock Units

In the first quarter of ~~2019 and~~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 Company has accounted for these as liability-classified awards, and accordingly changes in the market value of the instruments will be recorded to general and administrative expense and capitalized expense over the vesting period of the award. As of ~~September 30, 2019,~~March 31, 2020, there was ~~$22~~$26 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 3.0 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 shares at December 31, 2018		8,202	$	3.41
Unvested units at December 31, 2019					Unvested units at December 31, 2019	12,992	$	2.42
Granted	Granted	8,659	$	4.34	Granted	6,172	$	1.41
Vested	Vested	(2,624)	$	4.09	Vested	(3,852)	$	1.38
Forfeited	Forfeited	(1,000)	$	2.51	Forfeited	(1,464)	$	1.67
Unvested units at September 30, 2019		13,237	$	1.93
Unvested units at March 31, 2020					Unvested units at March 31, 2020	13,848	$	1.69

Liability-Classified Performance Units

In ~~2019 and~~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 a performance ~~condition~~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. The fair values of the ~~two~~ market conditions are calculated by Monte Carlo models on a quarterly basis. As of ~~September 30, 2019,~~March 31, 2020, there was $7$15 million of total unrecognized compensation cost related to liability-classified performance units. This cost is expected to be

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recognized over a weighted-average period of ~~2.2~~2.6 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 Shares	Weighted Average Fair Value			Number of Units	Weighted Average Fair Value
		(in thousands)				(in thousands)
Unvested shares at December 31, 2018		2,803	$	3.41
Unvested units at December 31, 2019					Unvested units at December 31, 2019	5,142	$	2.42
Granted	Granted	2,757	$	4.34	Granted	6,172	$	1.41
Vested	Vested	—	$	—	Vested	—	$	—
Forfeited	Forfeited	(119)	$	4.65	Forfeited	—	$	—
Unvested units at September 30, 2019		5,441	$	1.93
Unvested units at March 31, 2020					Unvested units at March 31, 2020	11,314	$	1.69

Cash-Based Compensation

Performance Cash Awards

In 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 2020 include a performance condition determined annually by the Company. In 2020, 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, 2020, there was $19 million of total unrecognized compensation cost related to performance cash awards. This cost is expected to be recognized over a weighted average 3.9 years. The final value of the performance cash awards is contingent upon the Company’s actual performance against these performance measures.

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	Number of Units	Weighted Average Fair Value
	(in thousands)
Unvested units at 12/31/2019	—	$	—
Granted	20,044	$	1.00
Vested	—	$	—
Forfeited	(135)	$	1.00
Unvested units at March 31, 2020	19,909	$	1.00

~~(17)~~(15) 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 ~~Midstream~~Marketing segment generates revenue through the marketing of both Company and third-party produced natural gas and liquids volumes.

Prior to December 2018, the Midstream segment included the Company’s natural gas gathering business associated with its Fayetteville Shale assets. With the closing of the Fayetteville Shale sale in December 2018, the Company’s marketing business comprises substantially all of the Company’s Midstream segment.

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 ~~2018~~2019 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).~~income. 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 Midstream Other Total
Three months ended September 30, 2019 (in millions)
Revenues from external customers $ 357 $ 279 $ — $ 636
Intersegment revenues (9) 313 — 304
Depreciation, depletion and amortization expense 123 2 — 125
Impairments — 2 — 2
Operating loss (21)
⁽¹⁾
(8) — (29)
Interest expense ⁽²⁾
17 — — 17
Gain on derivatives 100 — — 100
Gain on extinguishment of debt — — 7 7
Other income (loss), net (4) — 2 (2)
Provision for income taxes ⁽²⁾
10 — — 10
Assets 6,099
⁽³⁾
272 227
⁽⁴⁾
6,598
Capital investments⁽⁵⁾
239 — 1 240

Three months ended September 30, 2018
Revenues from external customers $ 639 $ 312 $ — $ 951
Intersegment revenues (6) 600 — 594
Depreciation, depletion and amortization expense 140 11 — 151
Impairments 15 145 1 161
Operating income(loss) ⁽⁶⁾
175
⁽¹⁾
(108) (1) 66
Interest expense ⁽²⁾
29 — — 29
Loss on derivatives (65) — — (65)
Other loss, net — (1) — (1)
Assets 5,732
⁽³⁾
1,115
⁽⁷⁾
211
⁽⁴⁾
7,058
Capital investments ⁽⁵⁾
295 — 3 298

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

Nine months ended September 30, 2019		(in millions)
Three months ended March 31, 2020													Three months ended March 31, 2020	(in millions)
Revenues from external customers	Revenues from external customers	$	1,288		$	1,005		$	—		$	2,293	Revenues from external customers	$	353		$	239	$	—		$	592
Intersegment revenues	Intersegment revenues	(27)			1,154			—			1,127		Intersegment revenues	(9)			309		—			300
Depreciation, depletion and amortization expense	Depreciation, depletion and amortization expense	345			7			—			352		Depreciation, depletion and amortization expense	111			2		—			113
Impairments	Impairments	6			2			—			8		Impairments	1,479			—		—			1,479
Operating income (loss)	Operating income (loss)	219		⁽¹⁾	(13)			—			206		Operating income (loss)	(1,486)		⁽¹⁾	(4)		—			(1,490)
Interest expense⁽²⁾	Interest expense⁽²⁾	46			—			—			46		Interest expense⁽²⁾	19			—		—			19
Gain on derivatives	Gain on derivatives	220			—			—			220		Gain on derivatives	339			—		—			339
Gain on early extinguishment of debt	Gain on early extinguishment of debt	—			—			7			7		Gain on early extinguishment of debt	—			—		28			28
Other income (loss), net		(8)			—			1			(7)
Other income, net													Other income, net	1			—		—			1
Provision for income taxes ⁽²⁾													Provision for income taxes ⁽²⁾	406			—		—			406
Assets													Assets	4,900		⁽³⁾	214		161		⁽⁴⁾	5,275
Capital investments⁽⁵⁾													Capital investments⁽⁵⁾	237			—		—			237

Three months ended March 31, 2019													Three months ended March 31, 2019
Revenues from external customers													Revenues from external customers	$	551		$	439	$	—		$	990
Intersegment revenues													Intersegment revenues	(9)			502		—			493
Depreciation, depletion and amortization expense													Depreciation, depletion and amortization expense	110			2		—			112

Operating income													Operating income	210		⁽¹⁾	3		—			213
Interest expense⁽²⁾													Interest expense⁽²⁾	14			—		—			14
Loss on derivatives													Loss on derivatives	(32)			—		—			(32)

Other income, net													Other income, net	1			—		—			1
Benefit from income taxes ⁽²⁾	Benefit from income taxes ⁽²⁾	(401)			—			—			(401)		Benefit from income taxes⁽²⁾	(426)			—		—			(426)
Assets	Assets	6,099		⁽³⁾	272			227		⁽⁴⁾	6,598		Assets	5,562		⁽³⁾	342		542		⁽⁴⁾	6,446
Capital investments⁽⁵⁾	Capital investments⁽⁵⁾	931			—			2			933		Capital investments⁽⁵⁾	325			—		—			325

Nine months ended September 30, 2018
Revenues from external customers		$	1,809		$	878		$	—		$	2,687
Intersegment revenues		(19)			1,727			—			1,708
Depreciation, depletion and amortization expense		383			43			—			426
Impairments		15			155		⁽⁸⁾	1			171
Operating income (loss) ⁽⁶⁾		510		⁽¹⁾	(64)		⁽⁹⁾	(1)			445
Interest expense⁽²⁾		100			—			—			100
Loss on derivatives		(108)			—			—			(108)
Loss on early extinguishment of debt		—			—			(8)			(8)
Other income (loss), net		3			(2)			—			1

Assets		5,732		⁽³⁾	1,115		⁽⁷⁾	211		⁽⁴⁾	7,058
Capital investments⁽⁵⁾		1,025			9			5			1,039

(1)Operating income for the E&P segment includes $4$10 million and $2$3 million of restructuring charges for the three months ended ~~September 30,~~March 31, 2020 and 2019, ~~and 2018, respectively, and $9 million and $18 million of restructuring charges for the nine months ended September 30, 2019 and 2018,~~ respectively.

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

(3)E&P assets includes office, technology, water infrastructure, drilling rigs and other ancillary equipment not directly related to natural gas and oil properties. ~~This~~For the three months ended March 31, 2019, this also includes deferred tax assets which are an allocation of corporate amounts as they are incurred at the corporate level. ~~At September~~

30 ~~2018, E&P assets included $106 million~~

Table of ~~assets held for sale.~~Contents

(4)Other assets represent corporate assets not allocated to segments and assets for non-reportable segments. At ~~September 30,~~March 31, 2020 and 2019, ~~and 2018,~~ other assets included approximately ~~$29~~$5 million and $9$366 million, respectively, in cash and cash equivalents, ~~$61~~$32 million and ~~$89~~$68 million, respectively, in income taxes receivable, ~~$31~~$23 million and ~~$69~~$56 million, respectively, in property, plant and equipment, $9$10 million and ~~$12~~$10 million, respectively, in unamortized debt expense, $7$9 million and ~~$12~~$10 million, respectively, in prepayments, ~~and $7~~$5 million and $8$7 million, respectively, in a non-qualified retirement ~~plan. Additionally, the September 30, 2019 asset balance includes $84~~plan and $77 million and $25 million in right-of-use lease ~~assets.~~assets, respectively.

(5)Capital investments include ~~decreases~~increases of ~~$53~~$8 million and ~~$31~~$66 million for the three months ended ~~September 30,~~March 31, 2020 and 2019, ~~and 2018, respectively, and increases of $52 million and $21 million for the nine months ended September 30, 2019 and 2018,~~ respectively, relating to the change in accrued expenditures between years.

~~(6)Includes the impact of Fayetteville Shale-related E&P and Midstream operations which were divested on December 3, 2018.~~

~~(7)Midstream assets includes $738 million of assets held for sale at September 30, 2018.~~

~~(8)Includes a $10 million impairment related to certain non-core gathering assets.~~

~~(9)~~Operating loss for the Midstream segment includes a $10 million impairment related to certain non-core gathering assets and $2 million related to restructuring charges for the nine months ended September 30, 2018.

Included in intersegment revenues of the Midstream segment are $313 million and $559 million for the three months ended September 30, 2019 and 2018, respectively, and $1,154 million and $1,598 million for the nine months ended September 30, 2019 and 2018, respectively, for marketing of the Company’s E&P sales. Corporate assets include cash and cash equivalents, furniture and fixtures and other assets. Corporate general and administrative costs, depreciation expense and taxes, other than income taxes, are allocated to the segments.

~~Table of Contents~~

~~(18)~~(17) NEW ACCOUNTING PRONOUNCEMENTS

~~New Accounting Standards Implemented~~Recently Adopted

In ~~February 2016,~~August 2018, the FASB issued Accounting Standards Update No. ~~2016-02, Leases (Topic 842)~~2018-13, Fair Value Measurement (ASC 820): Disclosure Framework – Changes to the Disclosure Requirements for Fair Value Measurements (“~~Update 2016-02”~~ASU 2018-13”), which ~~seeks to increase transparency and comparability among organizations by, among other things, recognizing lease assets and lease liabilities~~modifies the disclosure requirements on the balance sheet for leases classified as operating leases under previous GAAP and disclosing key information about leasing arrangements. The codification was amended through additional ASUs. For public entities, Update 2016-02fair value measurements. ASU 2018-13 became effective for public business entities for annual and interim periods in fiscal years beginning after December 15, 2018, including interim periods within those fiscal years. The Company adopted ASC 842 with an effective date of January 1, 2019 using the modified retrospective approach for all leases that existed at the date of initial application. The Company elected to apply the transition as of the beginning of the period of adoption. For leases that existed at the period2019. As a result of adoption, on January 1, 2019, the incremental borrowing rate as of the application date was used to calculate the present value of remaining lease payments. Upon adoption of ASC 842, the Company recognized a discounted right-of-use asset and corresponding lease liability with opening balances of approximately $105 million as of January 1, 2019. The adoption of thethis standard did not ~~materially change~~have a material impact on the Company’s consolidated ~~statement of operations or its consolidated statement of cash flows. Please refer to~~ ~~Note 4 – “Leases”~~ ~~for full disclosure.~~

~~New Accounting Standards Not Yet Implemented~~financial statements.

In June 2016, the FASB issued Accounting Standards Update No. 2016-13, Financial Instruments - Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments (“Update 2016-13”). Update 2016-13 ~~replaces~~replaced the incurred loss model with an expected loss model, which is referred to as the current expected credit loss (“CECL”) model. The CECL model is applicable to the measurement of credit losses on financial assets measured at amortized cost, including but not limited to trade receivables. For public business entities, the new standard became effective for annual reporting periods beginning after December 15, 2019, including interim periods within that reporting period.

From an evaluation of the Company’s ~~current~~existing credit portfolio, which includes trade receivables from commodity sales, joint interest billings due from partners and other receivables and cash equivalents, historical credit losses have been de ~~minimis.~~minimis and are expected to remain so in the future assuming no substantial changes to the business or creditworthiness of our business partners. Update 2016-13 did not have a significant impact on the Company’s consolidated financial statements or related control environment upon adoption on January 1, 2020.

Issued but Not Yet Adopted

In August 2018, the FASB issued ASU 2018-14, Disclosure Framework – Changes to the Disclosure Requirements for Defined Benefit Plans (“ASU 2018-14”). This ASU amends, adds and removes certain disclosure requirements under FASB ASC Topic 715 – Compensation-Retirement Benefits. The ~~Company believes that its expected future credit losses~~guidance in ASU 2018-14 is effective for fiscal years beginning after December 15, 2020, with early adoption permitted. This ASU will ~~not be significant,~~result in expanded disclosures within the Company’s interim and ~~therefore Southwestern does not believe~~annual footnote disclosures, however, the adoption of ~~the standard will~~ASU 2018-14 is not expected to have a material impact on ~~its~~the Company’s consolidated financial statements. The Company will continue to monitor changes in its credit portfolio as evaluation progresses. For public business entities, the new standard is effective for annual reporting periods beginning after December 15, 2019, including interim periods within that reporting period.

~~(19)CONDENSED CONSOLIDATING FINANCIAL INFORMATION~~

In April, 2018, the Company entered into the 2018 credit facility. Pursuant to requirements under the indentures governing the Company’s senior notes, each 100% owned subsidiary that became a guarantor of the 2018 credit facility also became a guarantor of each of the Company’s 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 the Company’s operating units which are accounted for on a consolidated basis do not guarantee the 2018 credit facility and senior notes (“Non-Guarantor Subsidiaries”). See ~~Note 12 – Debt~~ for additional information on the Company’s 2018 credit facility and senior notes. At the closing of the Fayetteville Shale sale in December 2018, its subsidiaries being sold were released from these guarantees. See ~~Note 2~~ ~~for additional information on the divestiture of the Company’s Fayetteville Shale-related subsidiaries.~~

The following financial information reflects consolidating financial information of Southwestern Energy Company (the parent and issuer company), its Guarantor Subsidiaries on a combined basis and the Non-Guarantor Subsidiaries on a combined basis, prepared on the equity basis of accounting. The information is presented in accordance with the requirements of Rule 3-10 under the SEC’s Regulation S-X. The financial information may not necessarily be indicative of results of operations, cash flows or financial position had the Guarantor Subsidiaries operated as independent entities.

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~~CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS~~

~~(Unaudited)~~

(in millions) Parent Guarantors Non-Guarantors Eliminations Consolidated
Three months ended September 30, 2019
Operating Revenues:
Gas sales $ — $ 238 $ — $ — $ 238
Oil sales — 67 — — 67
NGL sales — 52 — — 52
Marketing — 279 — — 279
— 636 — — 636
Operating Costs and Expenses:
Marketing purchases — 288 — — 288
Operating expenses — 189 — — 189
General and administrative expenses — 42 — — 42
Restructuring charges — 4 — — 4
Depreciation, depletion and amortization — 124 1 — 125
Impairments — 2 — — 2
Taxes, other than income taxes — 15 — — 15
— 664 1 — 665
Operating Loss — (28) (1) — (29)
Interest Expense, Net 17 — — — 17
Gain on Derivatives — 100 — — 100
Gain on Early Extinguishment of Debt 7 — — — 7
Other Loss, Net — (2) — — (2)
Equity in Earnings of Subsidiaries 59 (1) — (58) —
Income (Loss) Before Income Taxes 49 69 (1) (58) 59
Provision for Income Taxes — 10 — — 10
Net Income (Loss) $ 49 $ 59 $ (1) $ (58) $ 49
Net Income (Loss) $ 49 $ 59 $ (1) $ (58) $ 49
Other Comprehensive Income 1 — — — 1
Comprehensive Income (Loss) $ 50 $ 59 $ (1) $ (58) $ 50

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~~CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS~~

~~(Unaudited)~~

(in millions) Parent Guarantors Non-Guarantors Eliminations Consolidated
Three months ended September 30, 2018
Operating Revenues:
Gas sales $ — $ 465 $ — $ — $ 465
Oil sales — 62 — — 62
NGL sales — 112 — — 112
Marketing — 287 — — 287
Gas gathering — 25 — — 25
— 951 — — 951
Operating Costs and Expenses:
Marketing purchases — 288 — — 288
Operating expenses — 206 — — 206
General and administrative expenses — 51 — — 51
Restructuring charges — 2 — — 2
Depreciation, depletion and amortization — 151 — — 151
Impairments — 161 — — 161
Taxes, other than income taxes — 26 — — 26
— 885 — — 885
Operating Income — 66 — — 66
Interest Expense, Net 29 — — — 29
Loss on Derivatives — (65) — — (65)
Other Loss, Net — (1) — — (1)
Equity in Earnings of Subsidiaries — — — — —
Loss Before Income Taxes (29) — — — (29)
Provision for Income Taxes — — — — —
Net Loss $ (29) $ — $ — $ — $ (29)
Net Loss $ (29) $ — $ — $ — $ (29)
Other Comprehensive Income 4 — — — 4
Comprehensive Loss $ (25) $ — $ — $ — $ (25)

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~~CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS~~

~~(Unaudited)~~

(in millions) Parent Guarantors Non-Guarantors Eliminations Consolidated
Nine months ended September 30, 2019
Operating Revenues:
Gas sales $ — $ 943 $ — $ — $ 943
Oil sales — 153 — — 153
NGL sales — 191 — — 191
Marketing — 1,004 — — 1,004
Other — 2 — — 2
— 2,293 — — 2,293
Operating Costs and Expenses:
Marketing purchases — 1,022 — — 1,022
Operating expenses — 523 — — 523
General and administrative expenses — 119 — — 119
Loss on sale of operating assets — 3 — — 3
Restructuring charges — 9 — — 9
Depreciation, depletion and amortization — 351 1 — 352
Impairments — 8 — — 8
Taxes, other than income taxes — 51 — — 51
— 2,086 1 — 2,087
Operating Income (Loss) — 207 (1) — 206
Interest Expense, Net 46 — — — 46
Gain on Derivatives — 220 — — 220
Gain on Early Extinguishment of Debt 7 — — — 7
Other Loss, Net — (7) — — (7)
Equity in Earnings of Subsidiaries 820 (1) — (819) —
Income (Loss) Before Income Taxes 781 419 (1) (819) 380
Benefit from Income Taxes — (401) — — (401)
Net Income (Loss) $ 781 $ 820 $ (1) $ (819) $ 781
Net Income (Loss) $ 781 $ 820 $ (1) $ (819) $ 781
Other Comprehensive Income 5 — — — 5
Comprehensive Income (Loss) $ 786 $ 820 $ (1) $ (819) $ 786

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~~CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS~~

~~(Unaudited)~~

(in millions) Parent Guarantors Non-Guarantors Eliminations Consolidated
Nine months ended September 30, 2018
Operating Revenues:
Gas sales $ — $ 1,412 $ — $ — $ 1,412
Oil sales — 141 — — 141
NGL sales — 252 — — 252
Marketing — 805 — — 805
Gas gathering — 73 — — 73
Other — 4 — — 4
— 2,687 — — 2,687
Operating Costs and Expenses:
Marketing purchases — 808 — — 808
Operating expenses — 588 — — 588
General and administrative expenses — 165 — — 165
Restructuring charges — 20 — — 20
Depreciation, depletion and amortization — 426 — — 426
Impairments — 171 — — 171
Taxes, other than income taxes — 64 — — 64
— 2,242 — — 2,242
Operating Income — 445 — — 445
Interest Expense, Net 100 — — — 100
Loss on Derivatives — (108) — — (108)
Loss on Early Extinguishment of Debt (8) — — — (8)
Other Income, Net — 1 — — 1
Equity in Earnings of Subsidiaries 338 — — (338) —
Income (Loss) Before Income Taxes 230 338 — (338) 230
Provision for Income Taxes — — — — —
Net Income (Loss) $ 230 $ 338 $ — $ (338) $ 230
Participating securities – mandatory convertible preferred stock 1 — — — 1
Net Income (Loss) Attributable to Common Stock $ 229 $ 338 $ — $ (338) $ 229
Net Income (Loss) $ 230 $ 338 $ — $ (338) $ 230
Other Comprehensive Income 4 — — — 4
Comprehensive Income (Loss) $ 234 $ 338 $ — $ (338) $ 234

~~Table of Contents~~

~~CONDENSED CONSOLIDATED BALANCE SHEETS~~

~~(Unaudited)~~

(in millions) Parent Guarantors Non-Guarantors Eliminations Consolidated
September 30, 2019
ASSETS
Cash and cash equivalents $ 29 $ — $ — $ — $ 29
Accounts receivable, net — 323 — — 323
Other current assets 6 275 — — 281
Total current assets 35 598 — — 633
Intercompany receivables 7,957 — — (7,957) —
Natural gas and oil properties, using the full cost method — 25,006 54 — 25,060
Other 179 314 29 — 522
Less: Accumulated depreciation, depletion and amortization (149) (20,176) (58) — (20,383)
Total property and equipment, net 30 5,144 25 — 5,199
Investments in subsidiaries (equity method) — 23 — (23) —
Other long-term assets 99 667 — — 766
TOTAL ASSETS $ 8,121 $ 6,432 $ 25 $ (7,980) $ 6,598
LIABILITIES AND EQUITY
Current portion of long-term debt $ 52 $ — $ — $ — $ 52
Accounts payable 77 462 — — 539
Other current liabilities 130 159 — — 289
Total current liabilities 259 621 — — 880
Intercompany payables — 7,955 2 (7,957) —
Long-term debt 2,219 — — — 2,219
Pension and other postretirement liabilities 39 — — — 39
Other long-term liabilities 87 238 — — 325
Negative carrying amount of subsidiaries, net 2,382 — — (2,382) —
Total long-term liabilities 4,727 238 — (2,382) 2,583
Commitments and contingencies
Total equity (accumulated deficit) 3,135 (2,382) 23 2,359 3,135
TOTAL LIABILITIES AND EQUITY $ 8,121 $ 6,432 $ 25 $ (7,980) $ 6,598

~~Table of Contents~~

~~CONDENSED CONSOLIDATED BALANCE SHEETS~~

~~(Unaudited)~~

(in millions) Parent Guarantors Non-Guarantors Eliminations Consolidated
December 31, 2018
ASSETS
Cash and cash equivalents $ 201 $ — $ — $ — $ 201
Accounts receivable, net 4 577 — — 581
Other current assets 8 166 — — 174
Total current assets 213 743 — — 956
Intercompany receivables 7,932 — — (7,932) —
Natural gas and oil properties, using the full cost method — 24,128 52 — 24,180
Other 197 301 27 — 525
Less: Accumulated depreciation, depletion and amortization (154) (19,840) (55) — (20,049)
Total property and equipment, net 43 4,589 24 — 4,656
Investments in subsidiaries (equity method) — 24 — (24) —
Other long-term assets 19 166 — — 185
TOTAL ASSETS $ 8,207 $ 5,522 $ 24 $ (7,956) $ 5,797
LIABILITIES AND EQUITY
Accounts payable $ 113 $ 496 $ — $ — $ 609
Other current liabilities 115 122 — — 237
Total current liabilities 228 618 — — 846
Intercompany payables — 7,932 — (7,932) —
Long-term debt 2,318 — — — 2,318
Pension and other postretirement liabilities 46 — — — 46
Other long-term liabilities 54 171 — — 225
Negative carrying amount of subsidiaries, net 3,199 — — (3,199) —
Total long-term liabilities 5,617 171 — (3,199) 2,589
Commitments and contingencies
Total equity (accumulated deficit) 2,362 (3,199) 24 3,175 2,362
TOTAL LIABILITIES AND EQUITY $ 8,207 $ 5,522 $ 24 $ (7,956) $ 5,797

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~~CONDENSED CONSOLIDATED STATEMENT OF CASH FLOWS~~

~~(Unaudited)~~

(in millions) Parent Guarantors Non-Guarantors Eliminations Consolidated
Nine months ended September 30, 2019
Net cash provided by (used in) operating activities $ 1,154 $ 404 $ — $ (819) $ 739
Investing activities:
Capital investments — (875) (2) — (877)
Proceeds from sale of property and equipment — 42 — — 42
Net cash used in investing activities — (833) (2) — (835)
Financing activities:
Intercompany activities (1,250) 429 2 819 —
Payments on long-term debt (43) — — — (43)
Change in bank drafts outstanding (11) — — — (11)
Purchase of treasury stock (21) — — — (21)
Cash paid for tax withholding (1) — — — (1)
Net cash provided by (used in) financing activities (1,326) 429 2 819 (76)
Decrease in cash and cash equivalents (172) — — — (172)
Cash and cash equivalents at beginning of year 201 — — — 201
Cash and cash equivalents at end of period $ 29 $ — $ — $ — $ 29

Nine months ended September 30, 2018
Net cash provided by (used in) operating activities $ 57 $ 1,396 $ — $ (482) $ 971
Investing activities:
Capital investments (12) (996) — — (1,008)
Proceeds from sale of property and equipment — 9 — 9
Other 4 — — — 4
Net cash used in investing activities (8) (987) — — (995)
Financing activities:
Intercompany activities (71) (411) — 482 —
Payments on long-term debt (1,191) — — — (1,191)
Payments on revolving credit facility (1,122) — — — (1,122)
Borrowings under revolving credit facility 1,482 — — — 1,482
Change in bank drafts outstanding 10 — — — 10
Debt issuance costs (9) — — — (9)
Purchase of treasury stock (25) — — — (25)
Preferred stock dividend (27) — — — (27)
Cash paid for tax withholding (1) — — — (1)
Net cash provided by (used in) financing activities (954) (411) — 482 (883)
Decrease in cash and cash equivalents (905) (2) — — (907)
Cash and cash equivalents at beginning of year 914 2 — — 916
Cash and cash equivalents at end of period $ 9 $ — $ — $ — $ 9

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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 ~~2018~~2019 Annual Report and analyzes the changes in the results of operations between the three ~~and nine~~ month periods ended ~~September 30, 2019~~March 31, 2020 and ~~2018.~~2019. 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 ~~2018~~2019 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, in Item 1A, “Risk Factors” in Part I and elsewhere in our ~~2018~~2019 Annual Report, and Item 1A, “Risk Factors” in Part II in this Quarterly Report and any other quarterly report on Form 10-Q filed during the fiscal year. 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 ~~natural gas liquids (“NGL”)~~NGL 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 ~~refer~~call “Marketing” but previously referred to as ~~“Midstream.”~~“Midstream” when it included the operations of gathering systems. We conduct most of our businesses through subsidiaries, and we currently operate exclusively in the lower 48 United States. ~~Our historical financial and operating results include the Fayetteville Shale E&P and related midstream gathering businesses, which were sold in early December 2018.~~

E&P. Our primary business is the exploration for and production of natural gas, oil and NGLs, with our ongoing operations focused on the development of unconventional natural gas reservoirs located in Pennsylvania and West Virginia. Our operations in northeast Pennsylvania, 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 and southwest Pennsylvania, which we refer to as “Southwest Appalachia,” are focused on the Marcellus Shale, the Utica and the Upper Devonian unconventional natural gas and oil reservoirs. Collectively, our properties in Pennsylvania and West Virginia are herein referred to as ~~the “Appalachian Basin.~~“Appalachia.” We also operate drilling rigs located in Pennsylvania and West Virginia, and we provide certain oilfield products and services, principally serving our E&P operations through vertical integration.

~~Midstream.~~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. ~~In December 2018, we divested almost all of our gathering assets as part of the Fayetteville Shale sale.~~

Recent Financial and Operating Results

Significant ~~third~~first quarter ~~2019~~2020 operating and financial results include:

Total Company

•Net ~~income attributable to common stock~~loss of ~~$49~~$1,547 million, or ~~$0.09~~($2.86) per diluted share, ~~increased 269%~~decreased compared to net ~~loss attributable to common stock~~income of ~~$29~~$594 million, or ~~($0.05)~~$1.10 per diluted share, for the same period in ~~2018.~~2019. The ~~increase~~decrease was primarily due to a ~~$165~~$1,479 million non-cash full cost ceiling test impairment and a $408 million tax valuation allowance, which were only partially offset by a $371 million positive impact of derivatives, including a ~~$94~~$103 million improvement in settled derivatives as compared to the same period in ~~2018, which was partially offset by decreased operating income and the divestiture of the Fayetteville Shale E&P and related midstream gathering assets on December 3, 2018.~~2019.

•Operating loss of ~~$29~~$1,490 million decreased ~~144%~~ compared to operating income of ~~$66~~$213 million for the same period in ~~2018~~2019 on a consolidated ~~basis. The decrease was~~basis primarily due to a $1,479 million non-cash full cost ceiling test impairment in the first quarter of 2020. Excluding the non-cash impairment, operating loss of $11 million decreased 105% compared to the same period in 2019 primarily due to lower margins associated with reduced commodity ~~prices and the divestiture of the Fayetteville Shale E&P and related midstream gathering assets in December 2018.~~prices.

•Net cash provided by operating activities of ~~$196~~$160 million decreased ~~36%~~64% from ~~$307~~$442 million for the same period in ~~2018~~2019 primarily due to the decrease in operating income net of depreciation, depletion and amortization and impairments, and a reduction in net cash flow associated with working capital, partially offset by the improvement in settled derivatives discussed above.

•Total capital investing of ~~$240~~$237 million decreased ~~19%~~27% from ~~$298~~$325 million for the same period in ~~2018.~~2019.

•We repurchased ~~$50~~$80 million in aggregate principal amount of our outstanding senior notes at a discount and recognized a gain on the extinguishment of debt of $7$28 million.

~~Table of Contents~~

E&P

•E&P segment operating loss of ~~$21~~$1,486 million decreased ~~112%~~ from an operating income of ~~$175~~$210 million for the same period in ~~2018.~~2019, primarily related to the non-cash impairment of $1,479 million in the first quarter of 2020.

•Total net production of ~~202~~201 Bcfe, which was comprised of 78% natural gas and 22% oil and NGLs. E&P segment production volumes of 252 Bcfe for the third quarter of 2018 included 65 Bcf of production related to our operations in the Fayetteville Shale, which was sold in December 2018. Excluding the impact of the production related to the sold Fayetteville Shale assets, our productionNGLs, increased 8%10% from ~~187~~182 Bcfe in the same period in ~~2018,~~2019, and our liquids production increased ~~19%~~17% over the same ~~period.~~period primarily associated with our oil production.

•Excluding the effect of derivatives, our realized natural gas price of ~~$1.45~~$1.53 per Mcf decreased ~~32% from the same period in 2018,~~48%, our realized oil price of ~~$46.54~~$36.72 per ~~Bbl~~barrel decreased ~~24% from the same period in 2018~~19% and our realized NGL price of ~~$8.89~~$8.16 per ~~Bbl~~barrel decreased ~~59% from~~44% as compared to the same period in ~~2018.~~2019. Our total weighted average realized price excluding the effect of derivatives of ~~$1.72~~$1.69 per Mcfe decreased ~~31%~~43% from the same period in ~~2018.~~2019.

•E&P segment invested ~~$239~~$237 million in capital; drilling 2438 wells, completing 3022 wells and placing 3412 wells to sales.

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Outlook

We expect to continue to exercise capital discipline ~~through a fully-funded 2019~~in our 2020 capital investment program, and we ~~expect to apply the same principles in 2020. We~~ remain committed to our focus on optimizing our portfolio by concentrating our efforts on our highest return investment opportunities, looking for ways to ~~maximize margins and~~ optimize our cost structure and maximize margins in each core area of our business and further developing our knowledge of our asset base.

Lower natural gas, oil and NGL prices ~~presents~~present challenges to our industry and our Company, as do changes in laws, regulations and investor sentiment and other key factors described in “Risk Factors” in our ~~2018~~2019 Annual Report. During the first quarter of 2020, the economic impact of the COVID-19 pandemic and related governmental and societal measures (discussed below), along with the disagreements between OPEC and Russia on production levels, have caused oil prices to decrease 66% since the beginning of 2020. In ~~2019,~~the first quarter of 2020, gains on settled derivatives ~~have~~ offset ~~the majority~~a large portion of the impact of the recent decline in prices, and as of April 28, 2020, we currently have derivative positions in place for ~~portions~~81% of our expected remaining 2020 ~~and 2021 production at prices above current market levels.~~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 and Note 9 7 - Derivatives and Risk Management, in the consolidated financial statements included in this Quarterly Report for further details.

The Impact of COVID-19 on Our Business

During the first quarter of 2020, 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. In early March 2020, we instituted additional health measures at our facilities and banned nonessential travel. In mid-March, in advance of state and local governments restricting business operations and imposing “stay at home” directives in Pennsylvania, West Virginia and Texas (where our operations and offices are located) we notified employees that those whose work does not require a physical presence should work from home. Almost all employees working at our sites today are engaged in the physical drilling, completion and operation of wells, and we have instituted additional measures designed to prevent the possible spread of the virus, including social distancing and appropriate personal protective equipment (PPE). The Cybersecurity and Infrastructure Security Agency in 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.

Although prices for oil dropped substantially during March 2020, by early in the first quarter we had protected the price of 99% of our expected 2020 oil production through derivatives. During the first quarter, natural gas prices were not impacted as severely as oil prices, and as of March 31, 2020, we have protected the price of approximately 87% of expected remaining 2020 gas production through derivatives. However, as decreased transportation, manufacturing and general economic activity levels prompted by COVID-19 and related governmental and societal actions have reduced the demand for oil-based products such as gasoline, jet fuel and other refined products, as well as NGLs, space to store oil and condensate production is reaching or may reach capacity in some areas, which is prompting purchasers of oil and condensate to reduce future purchase levels and, in some cases, to claim force majeure for purchases already contracted. Further, although the reduced production of natural gas associated with oil wells has dampened the effect of lower natural gas demand, the demand for natural gas and liquefied natural gas to be exported has fallen. These situations may lead to production greater than storage capacity later in the year, depending on weather and other seasonal factors. In addition, commodity pricing challenges may cause our production costs to exceed the revenues associated with such production. To the extent that this decreased demand for our commodities continues and our margins are not at acceptable levels or storage for our production is not available, we may have to reduce production from or completely shut in portions of our currently producing wells. The inability to sell our production or the decision to potentially reduce or shut in our production could materially and adversely affect our operating results and our ability to comply with the financial covenants under our 2018 credit facility.

There is uncertainty around the extent and duration of the disruption. 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 highly uncertain and cannot be predicted, including, but not limited to, the duration and spread of the outbreak, its severity, 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. Therefore, while we expect this matter will likely disrupt our operations, the degree of the 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, ~~loss~~gain on early extinguishment of debt and income ~~tax expense~~taxes are discussed on a consolidated basis.

E&P

~~The 2018 information in the table below includes the financial results from E&P assets in the Fayetteville Shale that were sold in December 2018.~~


		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)	2019		2018		2019		2018		(in millions)	2020		2019
Revenues	Revenues	$	348	$	633	$	1,261	$	1,790	Revenues	$	344	$	542
Operating costs and expenses(1)	Operating costs and expenses(1)	369		458		1,042		1,280		Operating costs and expenses(1)	1,830		332
Operating income		$	(21)	$	175	$	219	$	510
Operating income (loss)										Operating income (loss)	$	(1,486)	$	210

Gain on derivatives, settled ⁽¹⁾⁽²⁾	Gain on derivatives, settled ⁽¹⁾⁽²⁾	$	88	$	(6)	$	112	$	5	Gain on derivatives, settled ⁽¹⁾⁽²⁾	$	93	$	(10)

(1)Includes $1,479 million related to non-cash full cost ceiling test impairment for the three months ended March 31, 2020.

(2)Represents the gain on settled commodity ~~derivatives.~~derivatives and is not included in operating income (loss).

Operating Income (Loss)

•Operating income (loss) for the E&P segment operating income for the third quarter of 2018 included $23 million related to our operations in the Fayetteville Shale, which was sold in December 2018. Excluding amounts relating to the Fayetteville Shale, E&P segment operating income decreased ~~$173~~$1,696 million for the three months ended ~~September 30, 2019,~~March 31, 2020, compared to the same period in ~~2018,~~2019, primarily due to ~~lower margins associated with decreased commodity pricing.~~

~~Table of Contents~~

•~~Operating income for the E&P segment included $74~~a $1,479 million ~~related to our operations in the Fayetteville Shale for the nine months ended September 30, 2018.~~non-cash full cost ceiling test impairment. Excluding the ~~amounts related to~~impact of the ~~Fayetteville Shale,~~impairment, operating income ~~for the E&P segment~~(loss) decreased $217 million ~~for the nine months ended September 30, 2019,~~ compared to the same period in ~~2018,~~2019 primarily due to lower margins associated with decreased commodity pricing.

Revenues

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

Three months ended September 30,
(in millions except percentages) Natural
Gas Oil NGLs Total
2018 sales revenues $ 460 $ 61 $ 112 $ 633
Changes associated with the Fayetteville Shale sale⁽¹⁾
(140) — — (140)
2018 sales revenues, net of Fayetteville Shale revenues 320 61 112 493
Changes associated with prices (107) (21) (75) (203)
Changes associated with production volumes 17 26 15 58
2019 sales revenues $ 230 $ 66 $ 52 $ 348
Increase (decrease) from 2018, net of Fayetteville Shale revenues (28) % 8 % (54) % (29) %


	Three months ended March 31,
(in millions except percentages)	Natural Gas			Oil			NGLs			Total
2019 sales revenues ⁽¹⁾	$	421		$	39		$	81		$	541
Changes associated with prices	(221)			(12)			(39)			(272)
Changes associated with production volumes	39			25			8			72
2020 sales revenues ⁽²⁾	$	239		$	52		$	50		$	341
Increase (decrease) from 2019	(43)		%	33		%	(38)		%	(37)		%

(1)~~This amount represents the revenues associated with the Fayetteville Shale assets, which were sold on December 3, 2018. There were no Fayetteville Shale revenues in 2019.~~

Nine months ended September 30,
(in millions except percentages) Natural
Gas Oil NGLs Total
2018 sales revenues ⁽¹⁾
$ 1,395 $ 139 $ 252 $ 1,786
Changes associated with the Fayetteville Shale sale⁽²⁾
(431) — — (431)
2018 sales revenues, net of Fayetteville Shale revenues 964 139 252 1,355
Changes associated with prices (128) (40) (109) (277)
Changes associated with production volumes 82 52 48 182
2019 sales revenues ⁽³⁾
$ 918 $ 151 $ 191 $ 1,260
Increase (decrease) from 2018, net of Fayetteville Shale revenues (5) % 9 % (24) % (7) %

~~(1)Excludes $4 million in other operating revenues for the nine months ended September 30, 2018 related to third-party water sales.~~

~~(2)This amount represents the revenues associated with the Fayetteville Shale assets, which were sold on December 3, 2018. There were no Fayetteville Shale revenues in 2019.~~

~~(3)~~Excludes $1 million in other operating revenues for the ~~nine~~three months ended ~~September 30,~~March 31, 2019 primarily related to third-party water sales.

(2)Excludes $3 million in other operating revenues for the three months ended March 31, 2020 primarily related to gains on purchaser imbalances associated with certain NGLs.

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Production Volumes


		For the three months ended September 30,					Increase/(Decrease)			For the nine months ended September 30,				Increase/(Decrease)									For the three months ended March 31,		Increase/(Decrease)
Production volumes:	Production volumes:	2019		2018					2019			2018				Production volumes:			2020			2019		Increase/(Decrease)
Natural Gas (Bcf)	Natural Gas (Bcf)														Natural Gas (Bcf)
Northeast Appalachia	Northeast Appalachia	118		121		(2)%	343			341			1%		Northeast Appalachia		114			112			2%
Southwest Appalachia	Southwest Appalachia	40		29		38%	106			73			45%		Southwest Appalachia		42			31			35%
Fayetteville Shale ⁽¹⁾		—		65		(100)%	—			199			(100)%

Total	Total	158		215		(27)%	449			613			(27)%		Total		156			143			9%

Oil (MBbls)	Oil (MBbls)														Oil (MBbls)
Southwest Appalachia	Southwest Appalachia	1,413		989		43%	3,193			2,290			39%		Southwest Appalachia		1,395			849			64%
Other	Other	6		9		(33)%	17			44			(61)%		Other		4			5			(20)%
Total	Total	1,419		998		42%	3,210			2,334			38%		Total		1,399			854			64%

NGL (MBbls)	NGL (MBbls)														NGL (MBbls)
Southwest Appalachia	Southwest Appalachia	5,908		5,180		14%	17,003			14,248			19%		Southwest Appalachia		6,127			5,602			9%
Other	Other	3		1		200%	8			24			(67)%		Other		1			1			—%
Total	Total	5,911		5,181		14%	17,011			14,272			19%		Total		6,128			5,603			9%

Production volumes by area: (Bcfe)	Production volumes by area: (Bcfe)														Production volumes by area: (Bcfe)
Northeast Appalachia⁽²⁾		118		121		(2)%	343			341			1%
Southwest Appalachia⁽²⁾		84		66		27%	227			172			32%
Fayetteville Shale ⁽¹⁾		—		65		(100)%	—			199			(100)%
Northeast Appalachia															Northeast Appalachia		114			112			2%
Southwest Appalachia⁽¹⁾															Southwest Appalachia⁽¹⁾		87			70			24%

Total	Total	202		252		(20)%	570			712			(20)%		Total		201			182			10%

Production percentage: (Bcfe)	Production percentage: (Bcfe)														Production percentage: (Bcfe)
Natural gas	Natural gas	78	%	86	%		79	%		86	%				Natural gas		78	%		79	%
Oil	Oil	4	%	2	%		3	%		2	%				Oil		4	%		3	%
NGL	NGL	18	%	12	%		18	%		12	%				NGL		18	%		18	%
Total		100	%	100	%		100	%		100	%

(1)~~The Fayetteville Shale assets were sold on December 3, 2018.~~

~~(2)~~Approximately ~~201~~87 Bcfe and ~~569~~69 Bcfe for the three ~~and nine~~ months ended ~~September 30,~~March 31, 2020 and March 31, 2019, respectively, ~~and approximately 186 Bcfe and 511 Bcfe for the three and nine months ended September 30, 2018, respectively, was~~were produced from the Marcellus Shale formation.

•E&P segment production volumes for the third quarter of 2018 included 65 Bcf of production related to our operations in the Fayetteville Shale, which was sold in December 2018. Excluding this amount, productionProduction volumes for our E&P segment increased by 1519 Bcfe for the three months ended ~~September 30, 2019,~~March 31, 2020 compared to the same period in ~~2018,~~2019, primarily due to a ~~27%~~24% increase in production volumes ~~from Southwest Appalachia.~~

•~~E&P segment production volumes for the nine months ended September 30, 2018 included 199 Bcf of production related to our operations~~ in the Fayetteville Shale, which was sold in December 2018. Excluding this amount, production volumes for our E&P segment increased by 57 Bcfe for the nine months ended September 30, 2019 compared to the same period in 2018, primarily due to a 32% increase in production volumes from Southwest Appalachia.

•Oil and NGL production increased ~~42%~~64% and ~~14%~~9%, respectively, for the three months ended ~~September 30, 2019,~~March 31, 2020, compared to the same period in ~~2018, reflecting our shifting commodity production mix towards liquids.~~2019.

•~~Oil and NGL production increased 38% and 19%, respectively, for the nine months ended September 30, 2019, compared to the same period in 2018.~~

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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 cannot control or 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 in order to maintain appropriate liquidity and financial flexibility.

For the three months ended September 30, Increase/(Decrease) For the nine months ended September 30, Increase/(Decrease)
2019 2018 2019 2018
Natural Gas Price:
NYMEX Henry Hub Price ($/MMBtu) ⁽¹⁾
$ 2.23 $ 2.90 (23)% $ 2.67 $ 2.90 (8)%
Discount to NYMEX ⁽²⁾
(0.78) (0.76) 3% (0.63) (0.62) 2%
Average realized gas price, excluding derivatives ($/Mcf)
$ 1.45 $ 2.14 (32)% $ 2.04 $ 2.28 (11)%
Loss on settled financial basis derivatives ($/Mcf)
(0.01) (0.03) (0.02) (0.04)
Gain on settled commodity derivatives ($/Mcf)
0.43 0.05 0.18 0.07
Average realized gas price, including derivatives ($/Mcf)
$ 1.87 $ 2.16 (13)% $ 2.20 $ 2.31 (5)%

Oil Price:
WTI oil price ($/Bbl)
$ 56.45 $ 69.50 (19)% $ 57.06 $ 66.75 (15)%
Discount to WTI (9.91) (8.30) 19% (9.92) (7.24) 37%
Average oil price, excluding derivatives ($/Bbl)
$ 46.54 $ 61.20 (24)% $ 47.14 $ 59.51 (21)%
Gain (loss) on settled derivatives ($/Bbl)
3.13 (1.24) 2.60 (0.82)
Average oil price, including derivatives ($/Bbl)
$ 49.67 $ 59.96 (17)% $ 49.74 $ 58.69 (15)%

NGL Price:
Average net realized NGL price, excluding derivatives ($/Bbl)
$ 8.89 $ 21.60 (59)% $ 11.24 $ 17.65 (36)%
Gain (loss) on settled derivatives ($/Bbl)
3.04 (2.17) 1.94 (0.90)
Average net realized NGL price, including derivatives ($/Bbl)
$ 11.93 $ 19.43 (39)% $ 13.18 $ 16.75 (21)%
Percentage of WTI, excluding derivatives 16 % 31 % 20 % 26 %

Total Weighted Average Realized Price:
Excluding derivatives ($/Mcfe)
$ 1.72 $ 2.51 (31)% $ 2.21 $ 2.51 (12)%
Including derivatives ($/Mcfe)
$ 2.16 $ 2.48 (13)% $ 2.41 $ 2.51 (4)%

Table of Contents


	For the three months ended March 31,							Increase/(Decrease)
	2020			2019
Natural Gas Price:
NYMEX Henry Hub Price ($/MMBtu) ⁽¹⁾	$	1.95		$	3.15		(38)%
Discount to NYMEX ⁽²⁾	(0.42)			(0.20)			(110)%
Average realized gas price, excluding derivatives ($/Mcf)	$	1.53		$	2.95		(48)%
Gain (loss) on settled financial basis derivatives ($/Mcf)	0.10			(0.03)
Gain (loss) on settled commodity derivatives ($/Mcf)	0.31			(0.08)
Average realized gas price, including derivatives ($/Mcf)	$	1.94		$	2.84		(32)%

Oil Price:
WTI oil price ($/Bbl)	$	46.17		$	54.90		(16)%
Discount to WTI	(9.45)			(9.42)			—%
Average oil price, excluding derivatives ($/Bbl)	$	36.72		$	45.48		(19)%
Gain on settled derivatives ($/Bbl)	9.25			2.34
Average oil price, including derivatives ($/Bbl)	$	45.97		$	47.82		(4)%

NGL Price:
Average realized NGL price, excluding derivatives ($/Bbl)	$	8.16		$	14.45		(44)%
Gain on settled derivatives ($/Bbl)	2.62			0.60
Average realized NGL price, including derivatives ($/Bbl)	$	10.78		$	15.05		(28)%
Percentage of WTI, excluding derivatives	18		%	26		%

Total Weighted Average Realized Price:
Excluding derivatives ($/Mcfe)	$	1.69		$	2.98		(43)%
Including derivatives ($/Mcfe)	$	2.16		$	2.92		(26)%

(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 hedges.

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, transportation and fuel charges.

We regularly enter into various ~~hedging~~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 9 7 to the consolidated financial statements, included in this Quarterly Report.

~~Table of Contents~~

The table below presents the amount of our future production in which the basis is protected as of ~~September 30, 2019:~~March 31, 2020:


		Volume (Bcf)	Basis Differential			Volume (Bcf)	Basis Differential
Basis Swaps – Natural Gas	Basis Swaps – Natural Gas				Basis Swaps – Natural Gas
2019		35	$	(0.40)
2020	2020	141	(0.31)		2020	199	$	(0.44)
2021	2021	65	(0.48)		2021	103	(0.03)
2022	2022	45	(0.50)		2022	88	(0.48)
Total	Total	286			Total	390

Physical NYMEX Sales Arrangements – Natural Gas	Physical NYMEX Sales Arrangements – Natural Gas				Physical NYMEX Sales Arrangements – Natural Gas
2019		81	$	(0.07)
2020	2020	143	(0.06)		2020	178	$	(0.28)
2021					2021	94	(0.29)
Total	Total	224			Total	272

Table of Contents

In addition to protecting basis, the table below presents the amount of our future production in which price is financially protected as of ~~September 30, 2019:~~March 31, 2020:


		Remaining 2019	Full Year 2020	Full Year 2021	Full Year 2022		Remaining 2020	Full Year 2021	Full Year 2022
Natural gas (Bcf)	Natural gas (Bcf)	111	360	134	23	Natural gas (Bcf)	438	330	120
Oil (MBbls)	Oil (MBbls)	1,152	2,837	730	—	Oil (MBbls)	4,383	3,773	1,104
Ethane (MBbls)						Ethane (MBbls)	6,952	3,017	—
Propane (MBbls)	Propane (MBbls)	1,116	3,294	456	—	Propane (MBbls)	4,324	2,460	—
Ethane (MBbls)		2,194	3,843	—	—
Total financial protection on future production (Bcfe)	Total financial protection on future production (Bcfe)	138	420	141	23	Total financial protection on future production (Bcfe)	532	386	127

We refer you to Note 9 7 of the consolidated financial statements included in this Quarterly Report for additional details about our derivative instruments.

Operating Costs and Expenses


		For the three months ended September 30,						Increase/(Decrease)			For the nine months ended September 30,				Increase/(Decrease)									For the three months ended March 31,		Increase/(Decrease)
(in millions except percentages)	(in millions except percentages)	2019			2018					2019			2018				(in millions except percentages)			2020			2019		Increase/(Decrease)
Lease operating expenses	Lease operating expenses	$	189		$	232	(19)%	$	524		$	660		(21)%		Lease operating expenses		$	194		$	166		17%
General & administrative expenses	General & administrative expenses	39		⁽¹⁾	44		(11)%	108		⁽¹⁾	145		⁽²⁾	(26)%		General & administrative expenses		23			34			(32)%

Restructuring charges	Restructuring charges	4			2		100%	9			18			(50)%		Restructuring charges		10			3			233%
Taxes, other than income taxes	Taxes, other than income taxes	14			25		(44)%	50			59			(15)%		Taxes, other than income taxes		13			19			(32)%
Full cost pool amortization	Full cost pool amortization	123			131		(6)%	328			356			(8)%		Full cost pool amortization		106			103			3%
Non-full cost pool DD&A	Non-full cost pool DD&A	—			9		(100)%	17			27			(37)%		Non-full cost pool DD&A		5			7			(29)%
Impairments	Impairments	—			15		(100)%	6			15			(60)%		Impairments		1,479			—			100%
Total operating costs	Total operating costs	$	369		$	458	(19)%	$	1,042		$	1,280		(19)%		Total operating costs		$	1,830		$	332		451%

~~(1)~~Includes a $6 million residual value guarantee short-fall payment to the previous lessor of our headquarters building and $3 million of legal settlement charges for the three and nine months ended September 30, 2019.

~~(2)Includes $8 million of legal settlement charges for the nine months ended September 30, 2018.~~


		For the three months ended September 30,						Increase/			For the nine months ended September 30,					Increase/							For the three months ended March 31,	Increase/
Average unit costs per Mcfe:	Average unit costs per Mcfe:	2019			2018		(Decrease)	2019			2018			(Decrease)	Average unit costs per Mcfe:		2020			2019			(Decrease)
Lease operating expenses ⁽¹⁾	Lease operating expenses ⁽¹⁾	$	0.94		$	0.92	2%	$	0.92		$	0.93		(1)%	Lease operating expenses ⁽¹⁾		$	0.96		$	0.90		7%
General & administrative expenses⁽²⁾	General & administrative expenses⁽²⁾	$	0.15	⁽³⁾	$	0.18	(17)%	$	0.17	⁽³⁾	$	0.19	⁽⁴⁾	(11)%	General & administrative expenses⁽²⁾		$	0.11	⁽²⁾	$	0.19	⁽³⁾	(42)%
Taxes, other than income taxes	Taxes, other than income taxes	$	0.08		$	0.09	(11)%	$	0.09		$	0.08	⁽⁵⁾	13%	Taxes, other than income taxes		$	0.07		$	0.10		(30)%
Full cost pool amortization	Full cost pool amortization	$	0.58		$	0.52	12%	$	0.57		$	0.50		14%	Full cost pool amortization		$	0.53		$	0.57		(7)%

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

(2)Excludes a $10 million in restructuring ~~charges.~~charges for the three months ended March 31, 2020.

(3)Excludes ~~a $6 million residual value guarantee short-fall payment to the previous lessor of our headquarters building and~~ $3 ~~million of legal settlement charges for the three and nine months ended September 30, 2019.~~

~~(4)Excludes $17 million of restructuring charges and $8 million of legal settlement charges for the nine months ended September 30, 2018.~~

~~(5)Excludes $1~~ million of restructuring charges for the ~~nine~~three months ended ~~September 30, 2018.~~March 31, 2019.

~~Table of Contents~~

~~Lease~~ Operating Costs and Expenses


	For the three months ended March 31,					Increase/(Decrease)
(in millions except percentages)	2020		2019
Lease operating expenses	$	194	$	166	17%
General & administrative expenses	23		34		(32)%

Restructuring charges	10		3		233%
Taxes, other than income taxes	13		19		(32)%
Full cost pool amortization	106		103		3%
Non-full cost pool DD&A	5		7		(29)%
Impairments	1,479		—		100%
Total operating costs	$	1,830	$	332	451%

•


	For the three months ended March 31,							Increase/
Average unit costs per Mcfe:	2020			2019			(Decrease)
Lease operating expenses ⁽¹⁾	$	0.96		$	0.90		7%
General & administrative expenses	$	0.11	⁽²⁾	$	0.19	⁽³⁾	(42)%
Taxes, other than income taxes	$	0.07		$	0.10		(30)%
Full cost pool amortization	$	0.53		$	0.57		(7)%

(1)~~Lease operating expenses per Mcfe increased $0.02~~Includes post-production costs such as gathering, processing, fractionation and compression.

(2)Excludes a $10 million in restructuring charges for the three months ended September 30, 2019, compared to the same period of 2018, as a $0.04 per Mcfe increase primarily related to increased compression charges and a shift towards liquids production, which includes processing fees, was partially offset by a $0.02 per Mcfe decrease associated with the Fayetteville Shale sale.March 31, 2020.

•(3)Lease operating expenses per Mcfe decreased $0.01 for the nine months ended September 30, 2019, compared to the same period of 2018, as a $0.02 per Mcfe decrease associated with the Fayetteville Shale sale was partially offset by a $0.01 per Mcfe increase primarily related to a shift towards liquids production, which includes processing fees.

~~General and Administrative Expenses~~

•~~General and administrative expenses in the third quarter of 2019 included a $6 million residual value guarantee shortfall payment to the previous lessor of our headquarters building and~~Excludes $3 million in legal settlement charges. Excluding these amounts, general and administrative expenses decreased $14 million for the three months ended September 30, 2019, respectively, compared to the same period in 2018, primarily due to decreased personnel costs and the implementation of cost reduction initiatives.

•General and administrative expenses in the first three quarters of 2019 included a $6 million residual value guarantee shortfall payment to the previous lessor of our headquarters building and $3 million in legal settlement charges. The first three quarters of 2018 included $8 million in legal settlement charges. Excluding these amounts, general and administrative expenses decreased $38 million for the nine months ended September 30, 2019, compared to the same period of 2018, primarily due to decreased personnel costs and the implementation of cost reduction initiatives.

~~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, decreased $0.01 for the three months ended September 30, 2019, compared to the same period of 2018, primarily due to lower effective severance tax rates in Southwest Appalachia.

•~~Taxes, other than income taxes, per Mcfe increased $0.01 for the nine months ended September 30, 2019, compared to the same period of 2018, primarily due to an $8 million severance tax refund received in the second quarter of 2018.~~

~~Full Cost Pool Amortization~~

•Our full cost pool amortization rate increased $0.06 per Mcfe and $0.07 per Mcfe for the three and nine months ended September 30, 2019, respectively, as compared to the same periods of 2018. The average amortization rate increased primarily as a result of the impact of capital investment and the further evaluation of our unproved properties during the past twelve months and the impact of the Fayetteville Shale sale, which reduced our total natural gas reserves along with the carrying value of our full cost pool assets.

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

•Unevaluated costs excluded from amortization were $1.5 billion at September 30, 2019, compared to $1.8 billion at December 31, 2018. The unevaluated costs excluded from amortization decreased as the impact of $207 million of unevaluated capital invested during the period was more than offset by the evaluation of previously unevaluated properties totaling $444 million.

~~Impairments~~

•~~During the nine months ended September 30, 2019, we recognized a $6 million impairment to non-core gathering assets.~~

~~Table of Contents~~

•In accordance with accounting guidance for Property, Plant and Equipment, assets held for sale are measured at the lower of the carrying value or fair value less costs to sell. Because the assets outside of the full cost pool associated with the Fayetteville Shale sale met the criteria for held for sale accounting as of September 30, 2018, we determined the carrying value of certain non-full cost pool E&P assets exceeded the fair value less costs to sell. As a result, an impairment charge of $15 million was recorded during the three and nine months ended September 30, 2018.

~~Midstream~~

For the three months ended September 30, Increase/
(Decrease) For the nine months ended September 30, Increase/
(Decrease)
(in millions except percentages) 2019 2018 2019 2018
Marketing revenues $ 592 $ 846 (30)% $ 2,158 $ 2,403 (10)%
Gas gathering revenues —
⁽¹⁾
66 (100)% —
⁽¹⁾
202 (100)%
Other operating revenues — — —% 1 — 100%
Marketing purchases 592 833 (29)% 2,148 2,368 (9)%
Operating costs and expenses 6
⁽¹⁾
42

(86)% 19
⁽¹⁾
146
⁽²⁾
(87)%
Impairments 2 145
⁽⁵⁾
(99)% 2 155
⁽³⁾⁽⁵⁾
(99)%
Loss on sale of operating assets — — 100% 3 — 100%
Operating loss $ (8) $ (108) (93)% $ (13) $ (64) (80)%

Volumes marketed (Bcfe)
279
⁽⁴⁾
301 (7)% 823
⁽⁴⁾
855 (4)%
Volumes gathered (Bcf)
—
⁽¹⁾
103 (100)% —
⁽¹⁾
311 (100)%

Percent natural gas marketed from affiliated E&P operations 81 %
⁽⁴⁾
95 % 77 %
⁽⁴⁾
95 %
Affiliated E&P oil and NGL production marketed 73 % 65 % 74 % 67 %

~~(1)Reflects the sale of our Fayetteville Shale-related gathering business, which was sold in December 2018.~~

~~(2)Includes $2~~ million of restructuring charges for the ~~nine months ended September 30, 2018.~~

~~(3)Includes a $10 million impairment related to certain non-core gathering assets for the nine months ended September 30, 2018.~~

~~(4)Includes the effect of the purchase and sale of a portion of the production from the buyer of the Fayetteville Shale, which was sold in December 2018.~~

~~(5)Includes a $145 million impairment related to the gathering assets associated with the Fayetteville Shale sale in December 2018.~~

~~Operating Income~~

•Midstream operating loss for the third quarter of 2018 included a $114 million loss related to our gathering operations in the Fayetteville Shale, which were sold in December 2018. Excluding this amount, operating income decreased $14 million for the three months ended September 30, 2019, compared to the same period in 2018, primarily due to a $13 million decrease in the marketing margin and $2 million in impairments recorded in the third quarter of 2019, partially offset by a $1 million decrease in depreciation, depletion and amortization expense.March 31, 2019.

•Midstream operating income for the nine months ended September 30, 2018 included a $72 million loss related to our gathering operations in the Fayetteville Shale, which we sold in December 2018. Excluding this amount, operating income decreased $21 million for the nine months ended September 30, 2019, compared to the same period in 2018, primarily due to a $25 million decrease in the marketing margin, a $3 million loss on sale of operating assets and a $2 million increase in allocated corporate expenses, partially offset by an $8 million decrease in non-Fayetteville Shale impairments associated with non-core assets and a $1 million gain on the sale of gas in storage.

•The margin generated from marketing activities was immaterial for the three months ended September 30, 2019, $13 million for the three months ended September 30, 2018, and $10 million and $35 million for the nine months ended September 30, 2019 and 2018, respectively.

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 marketing purchase expenses.

~~Revenues~~

•Revenues from our marketing activities decreased $254 million for the three months ended September 30, 2019, compared to the same period in 2018, primarily due to a 7% decrease in volumes marketed and a 24% decrease in the price received for volumes marketed.

~~Table of Contents~~

•For the nine months ended September 30, 2019, revenues from our marketing activities decreased $245 million compared to the same period in 2018, primarily due to a 32 Bcfe decrease in the volumes marketed and a 7% decrease in the price received for volumes marketed.

Operating Costs and Expenses


	For the three months ended March 31,					Increase/(Decrease)
(in millions except percentages)	2020		2019
Lease operating expenses	$	194	$	166	17%
General & administrative expenses	23		34		(32)%

Restructuring charges	10		3		233%
Taxes, other than income taxes	13		19		(32)%
Full cost pool amortization	106		103		3%
Non-full cost pool DD&A	5		7		(29)%
Impairments	1,479		—		100%
Total operating costs	$	1,830	$	332	451%


	For the three months ended March 31,							Increase/
Average unit costs per Mcfe:	2020			2019			(Decrease)
Lease operating expenses ⁽¹⁾	$	0.96		$	0.90		7%
General & administrative expenses	$	0.11	⁽²⁾	$	0.19	⁽³⁾	(42)%
Taxes, other than income taxes	$	0.07		$	0.10		(30)%
Full cost pool amortization	$	0.53		$	0.57		(7)%

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

(2)Excludes a $10 million in restructuring charges for the three months ended March 31, 2020.

(3)Excludes $3 million of restructuring charges for the three months ended March 31, 2019.

Lease Operating Expenses

•Lease operating expenses per Mcfe increased $0.06 for the three months ended March 31, 2020, compared to the same period of 2019, due to a $0.04 per Mcfe increase related to a shift towards liquids production, which includes processing fees, and a $0.02 per Mcfe increase related to increased compression costs.

General and Administrative Expenses

•General and administrative expenses decreased $11 million for the three months ended March 31, 2020, compared to the same period of 2019, primarily due to decreased personnel costs and the implementation of cost reduction initiatives.

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 decreased $0.03 for the three months ended March 31, 2020, compared to the same period of 2019, primarily due to lower effective severance tax rates in Southwest Appalachia.

Table of Contents

Full Cost Pool Amortization

•Our full cost pool amortization rate decreased $0.04 per Mcfe for the three months ended March 31, 2020 as compared to the same period in 2019. The average amortization rate decreased primarily as a result of the impact of capital investment and the further evaluation of our unproved properties during the past twelve months.

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

•Unevaluated costs excluded from amortization were $1.4 billion at March 31, 2020, compared to $1.5 billion at December 31, 2019. The unevaluated costs excluded from amortization decreased as the impact of $15 million of unevaluated capital invested during the period was more than offset by the evaluation of previously unevaluated properties totaling $84 million.

Marketing


	For the three months ended March 31,							Increase/ (Decrease)
(in millions except percentages)	2020			2019
Marketing revenues	$	548		$	940		(42)%
Other operating revenues	—			1			(100)%
Marketing purchases	547			934			(41)%
Operating costs and expenses	5			5			—%

Gain on sale of operating assets	—			(1)			(100)%
Operating income (loss)	$	(4)		$	3		(233)%

Volumes marketed (Bcfe)	263			289			(9)%

Percent natural gas production marketed from affiliated E&P operations	87		%	69		%
Percent oil and NGL production marketed from affiliated E&P operations	77		%	75		%

Operating Income (Loss)

•Marketing operating income (loss) decreased $7 million for the three months ended March 31, 2020, compared to the same period in 2019, primarily due to a $5 million decrease in the marketing margin. In addition, marketing operating income for the first quarter of 2019 included a $1 million gain on the sale of operating assets and a $1 million gain on the sale of gas in storage.

•The margin generated from marketing activities was $1 million and $6 million for the three months ended March 31, 2020 and 2019, respectively. The decrease in marketing margin for the three months ended March 31, 2020, compared to the same period in 2019, reflects our efforts to optimize the cost of our transportation through the purchase and sale of third-party natural gas.

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 marketing 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, 2020, revenues from our marketing activities decreased $392 million compared to the same period in 2019, primarily due to a 26 Bcfe decrease in the volumes marketed and a 36% decrease in the price received for volumes marketed.

Operating Costs and Expenses

•Midstream operating costs and expenses for the third quarter of 2018 included $35 million related to our gathering operations in the Fayetteville Shale, which were sold in December 2018. Excluding this amount, operating costs and expenses decreased $1 million for the three months ended September 30, 2019, compared to the same period in 2018, primarily due to a $1 million decrease in depreciation, depletion and amortization expense.

•Midstream operating costs and expenses for the first three quarters of 2018 included $127 million related to our gathering operations in the Fayetteville Shale, which were sold in December 2018. Excluding this amount,Marketing operating costs and expenses remained flat for the ~~nine~~three months ended ~~September 30, 2019,~~March 31, 2020, compared to the same period in ~~2018.~~2019.

~~Impairments~~

•Table of Contents~~In the first three quarters of 2019, we recorded impairments of $2 million for non-core gathering assets.~~

•At September 30, 2018, we determined the carrying value of our gathering assets held for sale associated with the Fayetteville Shale sale exceeded the fair value less costs to sell. As a result, we recorded an impairment charge of $145 million in the third quarter of 2018. Additionally, in the second quarter of 2018, we recognized a $10 million impairment on unrelated non-core gathering assets.

Consolidated

Restructuring Charges

~~For the three months ended September 30, 2019, we recognized total restructuring charges~~In February 2020, employees were notified of $4 million, of which $3 million primarily related to office consolidation associated with the Fayetteville Shale sale, and $1 million was related to cash severance, including payroll taxes withheld. For the nine months ended September 30, 2019, we recognized total restructuring charges of $9 million, of which $5 million primarily related to office consolidation associated with the Fayetteville Shale sale, and $4 million was related to cash severance, including payroll taxes withheld.

~~On June 27, 2018, we announced~~ a workforce reduction plan ~~which resulted primarily from our previously announced study~~as a result of ~~structural, process and organizational changes to enhance shareholder value and continues with respect to other aspects~~a strategic realignment of our ~~business and activities.~~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 ~~a portion of equity~~unvested long-term incentive awards ~~to be~~that were forfeited. We recognized restructuring expense of ~~$2 million and $20~~$10 million for the three ~~and nine~~ months ended ~~September 30, 2018, of which $1 million and $18 million was~~March 31, 2020 related to cash severance, including payroll ~~taxes, respectively.~~taxes.

In the first quarter of 2019, we recognized $3 million in restructuring charges consisting of cash severance payments and office consolidation expenses related to the Fayetteville Shale sale, which closed in December 2018. We refer you to Note 2 to the consolidated financial statements included in this Quarterly Report for additional details about our restructuring charges.

Interest Expense


		For the three months ended September 30,					Increase/(Decrease)			For the nine months ended September 30,				Increase/(Decrease)									For the three months ended March 31,		Increase/(Decrease)
(in millions except percentages)	(in millions except percentages)	2019		2018					2019			2018				(in millions except percentages)			2020			2019		Increase/(Decrease)
Gross interest expense:	Gross interest expense:														Gross interest expense:
Senior notes	Senior notes	$	39	$	49	(20)%	$	117		$	150		(22)%		Senior notes		$	37		$	39		(5)%
Credit arrangements	Credit arrangements	2		7		(71)%	7			30			(77)%		Credit arrangements		3			3			—%
Amortization of debt costs	Amortization of debt costs	3		2		50%	6			6			—%		Amortization of debt costs		2			1			100%
Total gross interest expense	Total gross interest expense	44		58		(24)%	130			186			(30)%		Total gross interest expense		42			43			(2)%
Less: capitalization	Less: capitalization	(27)		(29)		(7)%	(84)			(86)			(2)%		Less: capitalization		(23)			(29)			(21)%
Net interest expense	Net interest expense	$	17	$	29	(41)%	$	46		$	100		(54)%		Net interest expense		$	19		$	14		36%

•Interest expense related to our senior notes decreased for the three ~~and nine~~ months ended ~~September 30, 2019,~~March 31, 2020, compared to the same ~~periods~~period of ~~2018,~~2019, as we repurchased ~~$900~~$80 million and $114 million of our outstanding senior notes in December 2018 with a portion of the proceeds from the Fayetteville Shale sale. Additionally, S&P and Moody’s upgraded our public bond ratings in April and May 2018, respectively, which lowered the interest rates associated with our Senior Notes dueduring 2020 and ~~2025 by 50 basis points, effective in July 2018.~~

~~Table of Contents~~

•~~Interest expense related to our credit arrangements decreased for the three and nine months ended September 30,~~ 2019, as compared to the same periods of 2018, primarily due to the extinguishment of our 2016 term loan and entering into our revolving credit facility in April 2018, which decreased our outstanding borrowing amount, and the repayment of our revolving credit facility borrowings with a portion of the net proceeds from the Fayetteville Shale sale in December 2018.respectively.

•Capitalized interest decreased for the three ~~and nine~~ months ended ~~September 30, 2019,~~March 31, 2020, compared to the same period in ~~2018,~~2019, due to the evaluation of natural gas and oil properties over the past twelve months.

•Capitalized interest ~~increased~~decreased as a percentage of gross interest expense for the three ~~and nine~~ months ended ~~September 30, 2019,~~March 31, 2020, compared to the same ~~periods~~period in ~~2018,~~2019, primarily related to a ~~smaller~~larger percentage decrease in our unevaluated natural gas and oil properties balance as compared to the ~~larger~~smaller percentage decrease in our gross interest expense over the same ~~period, in addition to an increase in our average cost of debt over the past twelve months.~~period.

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)	2019		2018		2019		2018		(in millions)	2020		2019
Gain (loss) on unsettled derivatives	Gain (loss) on unsettled derivatives	$	12	$	(59)	$	108	$	(113)	Gain (loss) on unsettled derivatives	$	246	$	(22)
Gain (loss) on settled derivatives	Gain (loss) on settled derivatives	88		(6)		112		5		Gain (loss) on settled derivatives	93		(10)
Gain (loss) on derivatives	Gain (loss) on derivatives	$	100	$	(65)	$	220	$	(108)	Gain (loss) on derivatives	$	339	$	(32)

We refer you to Note 9 7 to the consolidated financial statements included in this Quarterly Report for additional details about our gain (loss) on derivatives.

Gain/Loss on Early Extinguishment of Debt

For the three months ended ~~September 30, 2019,~~March 31, 2020, we recorded a gain on early extinguishment of debt of $7$28 million as a result of our repurchase of ~~$50~~$80 million in aggregate principal amount of our outstanding senior ~~notes.~~notes for $52 million. See Note 12 1 0 to the consolidated financial statements of this Quarterly Report for more information on our long-term debt.

Concurrent with the closing of the 2018 credit agreement on April 26, 2018, we repaid our $1,191 million 2016 secured term loan balance and recognized a loss on early debt extinguishment of $8 million on the unaudited consolidated statements of operations in the second quarter of 2018 related to the unamortized debt issuance expense.

Income Taxes


		For the three months ended September 30,									For the nine months ended September 30,										For the three months ended March 31,
(in millions except percentages)	(in millions except percentages)	2019			2018			2019			2018			(in millions except percentages)	2020			2019
Income tax (benefit) expense	Income tax (benefit) expense	$	10		$	—		$	(401)		$	—		Income tax (benefit) expense	$	406		$	(426)
Effective tax rate	Effective tax rate	18		%	0		%	(105)		%	0		%	Effective tax rate	(36)		%	(254)		%

Table of Contents

•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 as of March 31, 2019, we concluded that it was more likely than not that the deferred tax ~~assets~~asset would be realized and determined ~~$522~~that $426 million of the valuation allowance ~~will~~would be ~~released. For~~released as of March 31, 2019. However, due to commodity price declines during the ~~nine~~first quarter of 2020 and the write-down of the carrying value of our natural gas and oil properties for the three months ended ~~September 30, 2019,~~March 31, 2020, in addition to other negative evidence, we concluded that it was more likely than not that these deferred tax assets will not be realized and recorded a discrete tax ~~benefit~~expense in the period of ~~$399~~$408 million ~~with~~for the ~~remainder being recognized through current period activity.~~increase in our valuation allowance. The net change in valuation allowance is reflected as a component of income tax expense. We ~~expect~~also continue to retain a valuation allowance of $87 million related to net operating losses in jurisdictions in which we no longer operate.

•Our low effective tax rate in 2018 was the result of our recognition of a valuation allowance that reduced the deferred tax asset primarily related to our current net operating loss carryforward. 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 asset will not be realized.

New Accounting Standards Implemented in this Report

Refer to Note 181 6 to the consolidated financial statements of this Quarterly Report for a discussion of new accounting standards which have been implemented.

New Accounting Standards Not Yet Implemented in this Report

Refer to Note 181 6 to the consolidated financial statements of this Quarterly Report for a discussion of new accounting standards which have not yet been implemented.

~~Table of Contents~~

LIQUIDITY AND CAPITAL RESOURCES

We depend primarily on funds generated from our operations, our 2018 credit facility, our cash and cash equivalents balance ~~our revolving credit facility~~ and capital markets as our primary sources of liquidity. ~~Although we have financial flexibility with~~On April 13, 2020, the banks participating in our ~~cash balance and the ability to draw on our $2.0 billion revolving~~2018 credit facility ~~(less outstanding letters~~redetermined our borrowing base to be $1.8 billion, which also changed our aggregate commitments to that amount. As of ~~credit,~~April 28, 2020, we had $1.3 billion of total available liquidity, which ~~were approximately $172 million as of September 30, 2019),~~exceeds our currently modeled needs, and we ~~continue to be~~remain committed to our ~~capital discipline~~ strategy of ~~investing within~~capital discipline. We refer you to Note 10 to the consolidated financial statements included in this Quarterly Report and the section below under “Credit Arrangements and Financing Activities” for additional discussion of our cash flow from operations net of changes in working capital, supplemented by a portion of the net proceeds from the Fayetteville Shale sale realized in December 2018. We expect to apply the same principles in 2020.2018 credit facility and related covenant requirements.

Our cash flow from operating activities is highly dependent upon our ability to sell, and the sales prices that we receive for, our natural gas and liquids production. Natural gas, oil and NGL prices are subject to wide fluctuations and are driven by market supply and demand, which is impacted by many factors. See “The Impact of COVID-19 on Our Business” in the Overview section of Item 2 in Part I for additional discussion about current and potential future market conditions. The sales price we receive for our production is also influenced by our commodity hedging activities. Our derivative contracts allow us to ensure a certain level of cash flow to fund our operations. In ~~2019,~~the first quarter of 2020, gains on derivatives have offset ~~the majority~~a large portion of the impact of the recent decline in prices, and as of April 28, 2020, we currently have derivative positions in place for ~~portions~~81% of our expected remaining 2020 ~~and 2021~~ production, ~~at prices above current market levels.~~including 87% of our originally expected condensate 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~~”Risk” in Item 3 in Part I and Note 9 7, 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 partners could adversely impact our cash flows.

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

Table of Contents

Credit Arrangements and Financing Activities

OnIn April ~~26,~~ 2018, we replaced our ~~2016~~ credit facility entered into in 2016 with a new revolving credit ~~facility.~~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 ~~with a current aggregate commitment of $2.0 billion~~ and, at March 31, 2020, had a borrowing base ~~(limit on availability) that~~of $2.1 billion with aggregate bank commitments of $2.0 billion. The borrowing base is ~~redetermined each~~subject to redetermination at least twice a year, in April and ~~October.~~October, and is subject to change based primarily on drilling results, commodity prices, our future derivative position, the level of capital investing and operating costs. On April 13, 2020, the banks participating in our 2018 credit facility redetermined the borrowing base to be $1.8 billion, which also changed our aggregate commitments to that amount. The 2018 credit facility is secured by substantially all of our assets, including most of our subsidiaries. The permitted lien provisions in the senior note indentures currently limit liens securing indebtedness to the greater of $2.0 billion ~~and~~or 25% of adjusted consolidated net tangible assets. ~~On October 8, 2019, we entered into an amendment to~~We may utilize the 2018 credit facility ~~that, among other things, established~~in the ~~October 2019 borrowing base at $2.1 billion~~form of loans and ~~extended the maturity date to April 2024. The borrowing base is subject to change based primarily on drilling results, commodity prices, our future derivative position, the level~~letters of ~~capital investing and operating costs.~~credit. As of ~~September 30, 2019,~~March 31, 2020, we had no$149 borrowings outstanding on our 2018 credit facility and $172 million in outstanding letters of credit. As of April 28, 2020, we have been requested to post an additional $150 million in letters of credit related to firm transportation. We currently do not anticipate being required to supply a materially greater amount of letters of credit under our existing contracts.

As of ~~September 30, 2019,~~March 31, 2020, we were in compliance with all of the covenants of our revolving credit facility in all material respects. Our ability to comply with financial covenants in future periods depends, among other things, on the success of our development program and upon factors beyond our control, such as the market demand and prices for natural gas and liquids. Beginning late in the first quarter of 2020, decreased transportation, manufacturing and general economic activity levels prompted by COVID-19 and related governmental and societal actions reduced the demand for oil-based products such as gasoline, jet fuel and other refined products, as well as NGLs. Reduced demand, along with geopolitical events such as the disagreements between OPEC and Russia on production levels, have caused a significant decline in commodity pricing since the beginning of 2020. Additionally, space to store oil and condensate production is reaching or may reach capacity in some areas, which has prompted purchasers of oil and condensate to reduce future purchase levels and, in some cases, to claim force majeure for purchases already contracted. Consequently, during the second half of April 2020, we received notices from two companies asserting force majeure and curtailing approximately 3,200 gross barrels per day of our condensate. We are adjusting our 2020 capital investing program to take into account these changed conditions. To the extent that this decreased demand for our commodities continues or storage for our production is not available, we expect to reduce production from or completely shut in portions of our currently producing wells. If the current market conditions persist or deteriorate further, we would proactively continue to adjust our activities and plans. Absent any actions taken by the Company, and under these conditions or if they worsen, current modeling indicates that we would not be in compliance with our Net Leverage Ratio covenant under our 2018 credit facility in late 2020. Under such circumstances, we would seek waivers or a modification of the covenant package from the lenders in advance of any covenant non-compliance. Additionally, we have other mitigating options including but not limited to the monetization of derivative asset positions, the reduction or elimination of non-essential expenditures or the sale of non-core assets. We refer you to Note 121 0 of the consolidated financial statements included in this Quarterly Report for additional discussion of the covenant requirements of our 2018 credit facility. Although we do not anticipate any violations of the financial covenants, our ability to comply with these covenants is dependent upon the success of our exploration and development program and upon factors beyond our control, such as the market prices for natural gas and liquids.

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 121 0 to the consolidated financial statements included in this Quarterly Report for additional discussion of our revolving credit facility.

In the first quarter of 2020, we repurchased $3 million of our 4.10% Senior Notes due 2022, $28 million of our 4.95% Senior Notes due 2025, $18 million of our 7.50% Senior Notes due 2026 and $31 million of our 7.75% Senior Notes due 2027 for $52 million, and recognized a $28 million gain on the extinguishment of debt.

~~Table~~In the second half of ~~Contents~~

2019, we purchased $35 million of our 4.95% Senior Notes due 2025, $11 million of our 7.50% Senior Notes due 2026 and $16 million of our 7.75% Senior Notes due 2027, and recognized an $8 million gain on extinguishment of debt. Additionally, in December 2019, we retired the remaining $52 million outstanding principal amount of our 4.05% Senior Notes due 2020.

Because of the focused work on refinancing and repayment of our debt during ~~2017 and 2018,~~the last three years, only ~~$265~~$210 million ~~or 11%,~~ of our senior notes outstanding ~~debt balance~~ as of ~~September 30, 2019 will come~~March 31, 2020 is scheduled to become due prior to ~~2025, with $52 million of that coming due in the next year.~~2025.

At ~~September 30, 2019,~~April 28, 2020, we had a long-term issuer credit rating of Ba2 by Moody’s (affirmed on April 2, 2020), a long-term debt rating of BBBB- by S&P and a long-term issuer default rating of BB by Fitch Ratings. On April 7, 2020, S&P downgraded our bond rating to BB-, which has the effect of increasing the interest rate on the 2025 Notes to 6.45%. The first coupon payment to the bondholders at the higher interest rate will be January 2021. 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.

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Cash Flows


		For the nine months ended September 30,							For the three months ended March 31,
(in millions)	(in millions)	2019		2018		(in millions)	2020		2019
Net cash provided by operating activities	Net cash provided by operating activities	$	739	$	971	Net cash provided by operating activities	$	160	$	442
Net cash used in investing activities	Net cash used in investing activities	(835)		(995)		Net cash used in investing activities	(228)		(258)
Net cash used in financing activities		(76)		(883)
Net cash provided by (used in) financing activities						Net cash provided by (used in) financing activities	68		(19)

Cash Flow from Operating Activities


		For the nine months ended September 30,							For the three months ended March 31,
(in millions)	(in millions)	2019		2018		(in millions)	2020		2019
Net cash provided by operating activities	Net cash provided by operating activities	$	739	$	971	Net cash provided by operating activities	$	160	$	442
Less: Changes in working capital		(88)		2
Add back (subtract) changes in working capital						Add back (subtract) changes in working capital	21		(136)
Net cash provided by operating activities, net of changes in working capital	Net cash provided by operating activities, net of changes in working capital	$	651	$	973	Net cash provided by operating activities, net of changes in working capital	$	181	$	306

•Net cash provided by operating activities decreased ~~24%~~64%, or ~~$232~~$282 million, for the ~~nine~~three months ended ~~September 30, 2019,~~March 31, 2020, compared to the same period in ~~2018, primarily~~2019, due to a ~~$290 million decrease as a result of the December 2018 Fayetteville Shale sale and a $277~~$272 million decrease resulting from lower commodity ~~prices.~~prices, a $157 million decrease in working capital, a $19 million increase in operating costs and a $5 million increase in net interest costs. These decreases were partially offset by a ~~$182~~$103 million increase in our settled derivatives and a $72 million increase associated with increased ~~production, a $54 million increase as a result of reduced interest costs and a $90 million increase in working capital.~~production.

•Net cash generated from operating activities, net of changes in working capital, provided ~~70%~~76% of our cash requirements for capital investments for the ~~nine~~three months ended ~~September 30, 2019,~~March 31, 2020, compared to providing ~~93%~~94% of our cash requirements for capital investments for the same period in ~~2018.~~2019. While we front-load our capital programs into the earlier quarters in the year, we remain committed to our capital discipline ~~strategy of investing within our cash flow from operations, net of changes in working capital, supplemented by a portion of the net proceeds from the Fayetteville Shale sale.~~strategy.

Cash Flow from Investing Activities

•Total ~~E&P~~ capital investing decreased ~~$56~~$88 million for the three months ended ~~September 30, 2019,~~March 31, 2020, compared to the same period in ~~2018,~~2019, due to a ~~$49~~$75 million decrease in direct E&P capital investing and a $7$13 million decrease in capitalized interest and internal costs, as compared to the same period in ~~2018.~~2019.


	For the three months ended March 31,
(in millions)	2020		2019
Additions to properties and equipment	$	228	$	258
Adjustments for capital investments
Changes in capital accruals	8		66
Other ⁽¹⁾	1		1
Total capital investing	$	237	$	325

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

Capital Investing


	For the three months ended March 31,					Increase/(Decrease)
(in millions except percentages)	2020		2019
E&P capital investing	$	237	$	325	(27)%
Other capital investing⁽¹⁾	—		—		—%
Total capital investing	$	237	$	325	(27)%

(1)Other capital investing ~~decreased $94 million~~was immaterial for the ~~nine~~three months ended ~~September 30, 2019, compared to the same period in 2018, due to a $76 million decrease in direct E&P capital investing~~March 31, 2020 and ~~a $18 million decrease in capitalized interest and internal costs, as compared to the same period in 2018.~~ 2019.

For the nine months ended September 30,
(in millions) 2019 2018
Additions to properties and equipment $ 877 $ 1,008
Adjustments for capital investments
Changes in capital accruals 52 21
Other 4 10
Total capital investing $ 933 $ 1,039

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~~Capital Investing~~

For the three months ended September 30, Increase/(Decrease) For the nine months ended September 30, Increase/(Decrease)
(in millions except percentages) 2019 2018 2019 2018
E&P capital investing $ 239 $ 295 (19)% $ 931 $ 1,025 (9)%
Midstream capital investing⁽¹⁾
— — —% — 9 (100)%
Other capital investing 1 3 (67)% 2 5 (60)%
Total capital investing $ 240 $ 298 (19)% $ 933 $ 1,039 (10)%

~~(1)Our Midstream gathering business in the Fayetteville Shale was sold in December 2018.~~


		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)	2019		2018		2019		2018		(in millions)	2020		2019
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	$	176	$	200	$	711	$	766	Exploratory and development drilling, including workovers	$	190	$	251
Acquisitions of properties	Acquisitions of properties	9		10		32		46		Acquisitions of properties	6		7
Seismic expenditures	Seismic expenditures	—		1		2		3		Seismic expenditures	—		1
Water infrastructure project	Water infrastructure project	6		26		32		39		Water infrastructure project	1		15
Drilling rigs and other		3		6		14		13
Other										Other	4		2
Capitalized interest and expenses	Capitalized interest and expenses	45		52		140		158		Capitalized interest and expenses	36		49
Total E&P capital investments	Total E&P capital investments	$	239	$	295	$	931	$	1,025	Total E&P capital investments	$	237	$	325

E&P Capital Investments by Area:	E&P Capital Investments by Area:									E&P Capital Investments by Area:
Northeast Appalachia	Northeast Appalachia	$	74	$	100	$	306	$	360	Northeast Appalachia	$	86	$	106
Southwest Appalachia	Southwest Appalachia	154		156		575		578		Southwest Appalachia	146		198
Fayetteville Shale		—		5		—		30
New Ventures & other ⁽¹⁾		11		34		50		57
Other E&P ⁽¹⁾										Other E&P ⁽¹⁾	5		21
Total E&P capital investments	Total E&P capital investments	$	239	$	295	$	931	$	1,025	Total E&P capital investments	$	237	$	325

(1)Includes $6$1 million and ~~$32~~$15 million for the three ~~and nine~~ months ended ~~September 30,~~March 31, 2020 and 2019, respectively, ~~and $26 million and $39 million for the three and nine months ended September 30, 2018~~ related to our water infrastructure project.


		For the three months ended September 30,			For the nine months ended September 30,				For the three months ended March 31,
		2019	2018	2019	2018		2020	2019
Gross Operated Well Count Summary:	Gross Operated Well Count Summary:					Gross Operated Well Count Summary:
Drilled	Drilled	24	22	95	91	Drilled	38	30
Completed	Completed	30	23	101	108	Completed	22	31
Wells to sales	Wells to sales	34	35	89	113	Wells to sales	12	19

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


(in millions except percentages)	(in millions except percentages)	September 30, 2019			December 31, 2018			Increase/(Decrease)		(in millions except percentages)	March 31, 2020			December 31, 2019			Increase/(Decrease)
Debt ⁽¹⁾	Debt ⁽¹⁾	$	2,271		$	2,318		$	(47)	Debt ⁽¹⁾	$	2,279		$	2,242		$	37
Equity	Equity	3,135			2,362			773		Equity	1,701			3,246			(1,545)
Total debt to capitalization ratio	Total debt to capitalization ratio	42		%	50		%			Total debt to capitalization ratio	57		%	41		%

Debt ⁽¹⁾		$	2,271		$	2,318		$	(47)
Less: Cash and cash equivalents		29			201			(172)
Debt, net of cash and cash equivalents ⁽²⁾		$	2,242		$	2,117		$	125

(1)The ~~decrease~~increase in total debt as of ~~September 30, 2019,~~March 31, 2020, as compared to December 31, ~~2018,~~2019, primarily relates to the use of the 2018 credit facility to supplement our capital investing, which is front-loaded to the first half of the year, partially offset by the repurchase of ~~$50 million~~certain of our outstanding senior notes at a discount during the ~~third~~first quarter of ~~2019.~~2020.

~~(2)Debt, net~~In the first quarter of ~~cash~~2020, we repurchased $80 million in aggregate principal amount of our outstanding senior notes at a discount for $52 million, and ~~cash equivalents is~~recognized a ~~non-GAAP financial measure~~$28 million gain on the extinguishment of ~~a company’s ability to repay its debt if it was all due today.~~

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debt.

We refer you to Note 121 0 of the consolidated financial statements included in this Quarterly Report for additional discussion of our outstanding debt and credit facilities.

Working Capital

•We had ~~negative~~positive working capital of ~~$247~~$58 million at ~~September 30, 2019,~~March 31, 2020, a ~~$357~~$227 million ~~decrease~~increase from December 31, ~~2018,~~2019, as a ~~decrease of $258~~$206 million in accounts receivable, as compared to December 2018, related to the sale of the Fayetteville Shale production in December 2018 and lower commodity prices, a decrease of $172 million in cash and cash equivalents, a current liability of $35 million recorded in 2019 related to the implementation of the new lease accounting standard (Topic 842) and $52 million of our long-term debt, which matures in less than a year, being reclassified as a current liability in 2019 were only partially offset by positive ~~changes~~change in the current mark-to-market value of our derivative position, ~~and~~ a ~~$70~~$60 million decrease in accounts payable and a $7 million decrease in taxes payable, as compared to December 31, ~~2018.~~

•~~At December 31, 2018, we had positive working capital of $110~~2019, were only partially offset by a $53 million ~~primarily due to $201 million of cash and cash equivalents resulting from the net proceeds from the Fayetteville Shale sale and an increase~~decrease in accounts receivable, ~~primarily related to the increase in commodity pricing in December 2018,~~ as compared to December ~~2017.~~2019, related to lower commodity prices.

Off-Balance Sheet Arrangements

We may enter into off-balance sheet arrangements and transactions that can give rise to material off-balance sheet obligations. As of ~~September 30, 2019,~~March 31, 2020, our material off-balance sheet arrangements and transactions include operating service arrangements, ~~and~~ $172 million in letters of credit outstanding against our 2018 credit ~~facility.~~facility and $115 million in outstanding surety bonds. 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

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regarding off-balance sheet arrangements, we refer you to “Contractual Obligations and Contingent Liabilities and Commitments” in our ~~2018~~2019 Annual Report.

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 ~~2018~~2019 Annual Report.

Contingent Liabilities and Commitments

As of ~~September 30, 2019, our contractual obligations~~March 31, 2020, 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 totaled approximately ~~$8.2~~$7.6 billion, ~~$752~~$411 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 ~~$323 million.~~$1.1 billion. As of ~~September 30, 2019,~~March 31, 2020, 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	$	7,442	$	681	$	1,272	$	1,075	$	1,528	$	2,886	Infrastructure currently in service	$	7,199	$	753	$	1,339	$	1,098	$	1,524	$	2,485
Pending regulatory approval and/or construction ⁽¹⁾	Pending regulatory approval and/or construction ⁽¹⁾	752		19		73		75		139		446		Pending regulatory approval and/or construction ⁽¹⁾	411		1		17		23		74		296
Total transportation charges	Total transportation charges	$	8,194	$	700	$	1,345	$	1,150	$	1,667	$	3,332	Total transportation charges	$	7,610	$	754	$	1,356	$	1,121	$	1,598	$	2,781

(1)Based on the estimated in-service dates as of ~~September 30, 2019.~~March 31, 2020.

Included in the transportation charges above are ~~$108~~$81 million ~~(potentially due~~(due in less than one year) ~~and $27 million (potentially due in one to two years)~~ related to certain agreements that remain in the name of our marketing affiliate but are expected to be paid in full by Flywheel Energy Operating, LLC, the purchaser of the Fayetteville Shale assets. Of these amounts, we may be obligated to reimburse Flywheel Energy Operating, LLC for a portion of volumetric shortfalls during ~~2019 and~~ 2020 (up to ~~$70~~$45 million) under these transportation agreements and have currently recorded a ~~$57~~$36 million liability as of ~~September 30, 2019,~~March 31, 2020, down from ~~$88~~$46 million recorded at December 31, ~~2018.~~2019.

In the first quarter of 2019, we agreed to purchase firm transportation with pipelines in the Appalachian Basin starting in 2021 and running through 2032 totaling $357 million in total contractual commitments of which the seller has agreed to reimburse $133 million of these commitments.

~~During~~In February 2020, we were notified that the ~~second quarter of 2019,~~proposed Constitution pipeline project was cancelled and that we ~~executed an~~were released from a firm transportation agreement with its sponsor. Prior to ~~convey our purchase option in our headquarters office building~~its cancellation, we had contractual commitments totaling $512 million over the next 17 years related to ~~a third-party, which closed on~~ the ~~purchase of the building in July 2019. Concurrent with the closing of the building~~

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sale, we terminated our existing lease agreement and entered into a new 10-year lease agreement for a smaller portion of the headquarters office building in July 2019, resulting in an estimated annual savings of $7 million to $8 million.Constitution pipeline project.

Substantially all of our employees are covered by defined benefit and postretirement benefit plans. For the ~~nine~~three months ended ~~September 30, 2019,~~March 31, 2020, we have contributed ~~$12~~$5 million to the pension and postretirement benefit plans, and we ~~do not~~ expect to further contribute an additional $7 million to our pension plan during the remainder of ~~2019.~~2020. We recognized liabilities of ~~$39~~$40 million and ~~$47~~$43 million as of ~~September 30, 2019~~March 31, 2020 and December 31, ~~2018,~~2019, respectively, as a result of the underfunded status of our pension and other postretirement benefit plans. See Note 151 3 to the consolidated financial statements included in this Quarterly Report for additional discussion about our pension and other postretirement benefits.

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

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For further information, we refer you to “Litigation” and “Environmental Risk” in Note 131 1 to the consolidated financial statements included in Item I1 of Part I of this Quarterly Report.

Supplemental Guarantor Financial Information

As discussed in Note 1 0, 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 which 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.

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 Guarantors 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, basis swaps and interest rate swaps to reduce the volatility of earnings and cash flow due to fluctuations in the prices of natural gas, oil and certain NGLs along with interest rates. Our Board of Directors has approved risk management policies and procedures to utilize financial products for the reduction of defined commodity price risk. Utilization of financial products for the reduction of interest rate risks is also overseen by our Board of Directors. 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. NoHowever, at March 31, 2020, one purchaser accounted for 12% 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. As of December 31, 2019, no single purchaser accounted for greater than 10% of revenues as of September 30, 2019. At December 31, 2018, two subsidiaries of Royal Dutch Shell Plc in aggregate accounted for approximately 10.4% of the quarter’s total natural gas, oil and NGL sales.revenues. 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.

Interest Rate Risk

As of ~~September 30, 2019,~~March 31, 2020, we had approximately ~~$2.3~~$2.1 billion of outstanding senior notes with a weighted average interest rate of ~~6.68%~~6.70%, and nowe had $149 million in borrowings under our revolving credit facility. We currently have an interest rate swap in effect to mitigate a portion of our exposure to volatility in interest rates. At ~~September 30, 2019,~~March 31, 2020, we had a long-term issuer credit rating of Ba2 by Moody’s, a long-term debt rating of BB by S&P and a long-term issuer default rating of BB by Fitch Ratings. On April 7, 2020, S&P downgraded our bond rating to BB-, which has the effect of increasing the interest rate on our 2025 Notes to 6.45%. The first coupon payment to the bondholders at the higher interest rate will be paid in January 2021. 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.

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		Expected Maturity Date																																										Expected Maturity Date
($ in millions)	($ in millions)	2019			2020			2021			2022			2023				Thereafter			Total				($ in millions)	2021			2022			2023			2024			2025			Thereafter				Total
Fixed rate payments ⁽¹⁾	Fixed rate payments ⁽¹⁾	$	—		$	52		$	—		$	213		$	—			$	2,027		$	2,292			Fixed rate payments ⁽¹⁾	$	—		$	210		$	—		$	—		$	864		$	1,074			$	2,148
Weighted average interest rate	Weighted average interest rate	—		%	5.30		%	—		%	4.10		%	—		%		6.99		%	6.68		%		Weighted average interest rate	—		%	4.10		%	—		%	—		%	6.20		%	7.61		%		6.70		%

Variable rate payments ⁽¹⁾	Variable rate payments ⁽¹⁾	$	—		$	—		$	—		$	—		$	—		⁽¹⁾	$	—		$	—		⁽¹⁾	Variable rate payments ⁽¹⁾	$	—		$	—		$	—		$	149		$	—		$	—			$	149
Weighted average interest rate	Weighted average interest rate	—		%	—		%	—		%	—		%	3.42		%	⁽²⁾	—		%	3.42		%	⁽²⁾	Weighted average interest rate	—		%	—		%	—		%	2.12		%	—		%	—		%		2.12		%

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

~~(2)On October 8, 2019, we entered into an amendment to the 2018 credit facility, which extended the maturity date of the credit facility to April 2024.~~

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 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 7 and Note 9 of the consolidated financial statements included in this Quarterly Report for additional details about our derivative ~~instruments.~~instruments and their fair value.

ITEM 4. CONTROLS AND PROCEDURES

Disclosure Controls and Procedures

We have performed an evaluation under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of our disclosure controls and procedures, as defined in Rule 13a-15(e) and 15d-15(e) under the Exchange Act. Our disclosure controls and procedures are the controls and other procedures that we have designed to ensure that we record, process, accumulate and communicate information to our management, including our Chief Executive Officer and Chief Financial Officer, to allow timely decisions regarding required disclosures and submission within the time periods specified in the SEC’s rules and forms. All internal control systems, no matter how well designed, have inherent limitations. Therefore, even those determined to be effective can provide only a level of reasonable assurance with respect to financial statement preparation and presentation. Based on the evaluation, our management, including our Chief Executive Officer and Chief Financial Officer, concluded that our disclosure controls and procedures were effective as of ~~September 30, 2019~~March 31, 2020 at a reasonable assurance level.

Changes in Internal Control over Financial Reporting

There were no changes in our internal control over financial reporting (as defined in Rule 13a-15(f) and 15d-15(f) under the Exchange Act) that occurred during the quarter ended ~~September 30, 2019~~March 31, 2020 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

PART II - OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

Refer to “Litigation” and “Environmental Risk” in Note 131 1 to the consolidated financial statements included in Item 1 of Part I of this Quarterly Report for a discussion of the Company’s legal proceedings.

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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 ~~2018~~2019 Annual ~~Report.~~Report, except as set forth below.

The widespread outbreak of an illness, pandemic (such as COVID-19) or any other public health crisis may have material adverse effects on our financial position, results of operations or cash flows.

In December 2019, COVID-19 was reported to have surfaced in China. The spread of this virus has caused business disruptions beginning in January 2020, including disruptions in the oil and natural gas industry. In March 2020, the World Health Organization declared the outbreak of COVID-19 to be a pandemic, and the U.S. economy began to experience pronounced effects. The COVID-19 pandemic has negatively impacted the global economy, disrupted global supply chains, reduced global demand for oil and gas, and created significant volatility and disruption of financial and commodity markets. The extent of the impact of the COVID-19 pandemic on our operational and financial performance, including our ability to execute our business strategies and initiatives in the expected time frame, is uncertain and depends on various factors, including the demand for natural gas, oil, NGLs and other products derived from these commodities, the availability of personnel, equipment and services critical to our ability to operate our properties and the impact of potential governmental restrictions on travel, transports and operations. There is uncertainty around the extent and duration of the disruption. 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 highly uncertain and cannot be predicted, including, but not limited to, the duration and spread of the outbreak, its severity, 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. Therefore, while the Company expects this matter will likely disrupt its operations, the degree of the adverse financial impact cannot be reasonably estimated at this time.

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, is 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.

ITEM 5. OTHER INFORMATION

~~Not applicable.~~On April 28, 2020, the Board of Directors of the Company amended the Company’s bylaws (as so amended, the “Amended and Restated Bylaws”) to provide that litigation against the Company or its officers, directors, employees or agents under the federal Securities Act of 1933, as amended, must be brought in federal courts and modified existing provisions requiring various actions arising under Delaware law to be brought in Delaware courts. This description is qualified in its entirely by Section 7.5 of the Company’s Amended and Restated Bylaws, which are filed with this Quarterly Report as Exhibit 3.2.

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ITEM 6. EXHIBITS


(3.1)			Amended and Restated Certificate of Incorporation of Southwestern Energy Company. (Incorporated by reference to Exhibit 3.1 to the Registrant’s Current Report on Form 8-K filed May 24, 2010)
(3.2)*			Amended and Restated Bylaws of Southwestern Energy Company, as amended on April 28, 2020
(31.1)*			Certification of CEO filed pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
(31.2)*			Certification of CFO filed pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
(32.1)*			Certification of CEO furnished pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
(32.2)*			Certification of CFO furnished pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
(95.1)*			Mine Safety Disclosure
(101.INS)			Inline Interactive Data File Instance Document
(101.SCH)			Inline Interactive Data File Schema Document
(101.CAL)			Inline Interactive Data File Calculation Linkbase Document
(101.LAB)			Inline Interactive Data File Label Linkbase Document
(101.PRE)			Inline Interactive Data File Presentation Linkbase Document
(101.DEF)			Inline Interactive Data File Definition Linkbase Document
(104.1)			Cover Page Interactive Data File – the cover page from this Quarterly Report on Form 10-Q, formatted in inline XBRL (included within the Exhibit 101 attachments)

*Filed herewith

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:	~~October 24, 2019~~April 30, 2020	/s/ JULIAN M. BOTT
		Julian M. Bott Executive Vice President and Chief Financial Officer

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5948


(in millions)	Parent		Guarantors		Non-Guarantors		Eliminations		Consolidated
Three months ended September 30, 2019
Operating Revenues:
Gas sales	$	—	$	238	$	—	$	—	$	238
Oil sales	—		67		—		—		67
NGL sales	—		52		—		—		52
Marketing	—		279		—		—		279


	—		636		—		—		636
Operating Costs and Expenses:
Marketing purchases	—		288		—		—		288
Operating expenses	—		189		—		—		189
General and administrative expenses	—		42		—		—		42

Restructuring charges	—		4		—		—		4
Depreciation, depletion and amortization	—		124		1		—		125
Impairments	—		2		—		—		2
Taxes, other than income taxes	—		15		—		—		15
	—		664		1		—		665
Operating Loss	—		(28)		(1)		—		(29)
Interest Expense, Net	17		—		—		—		17
Gain on Derivatives	—		100		—		—		100
Gain on Early Extinguishment of Debt	7		—		—		—		7
Other Loss, Net	—		(2)		—		—		(2)
Equity in Earnings of Subsidiaries	59		(1)		—		(58)		—

Income (Loss) Before Income Taxes	49		69		(1)		(58)		59
Provision for Income Taxes	—		10		—		—		10
Net Income (Loss)	$	49	$	59	$	(1)	$	(58)	$	49

Net Income (Loss)	$	49	$	59	$	(1)	$	(58)	$	49
Other Comprehensive Income	1		—		—		—		1
Comprehensive Income (Loss)	$	50	$	59	$	(1)	$	(58)	$	50


	Three months ended September 30,
(in millions except percentages)	Natural Gas			Oil			NGLs			Total
2018 sales revenues	$	460		$	61		$	112		$	633
Changes associated with the Fayetteville Shale sale⁽¹⁾	(140)			—			—			(140)
2018 sales revenues, net of Fayetteville Shale revenues	320			61			112			493
Changes associated with prices	(107)			(21)			(75)			(203)
Changes associated with production volumes	17			26			15			58
2019 sales revenues	$	230		$	66		$	52		$	348
Increase (decrease) from 2018, net of Fayetteville Shale revenues	(28)		%	8		%	(54)		%	(29)		%


	Nine months ended September 30,
(in millions except percentages)	Natural Gas			Oil			NGLs			Total
2018 sales revenues ⁽¹⁾	$	1,395		$	139		$	252		$	1,786
Changes associated with the Fayetteville Shale sale⁽²⁾	(431)			—			—			(431)
2018 sales revenues, net of Fayetteville Shale revenues	964			139			252			1,355
Changes associated with prices	(128)			(40)			(109)			(277)
Changes associated with production volumes	82			52			48			182
2019 sales revenues ⁽³⁾	$	918		$	151		$	191		$	1,260
Increase (decrease) from 2018, net of Fayetteville Shale revenues	(5)		%	9		%	(24)		%	(7)		%