SOUTHWESTERN ENERGY CO - Quarter Report: 2020 June (Form 10-Q)

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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q

(Mark One)

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

Exchange Act of 1934

For the quarterly period ended June 30, 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)

(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 July 28, 2020
Common Stock, Par Value $0.01						542,234,903

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SOUTHWESTERN ENERGY COMPANY

INDEX TO FORM 10-Q

FOR THE QUARTERLY PERIOD ENDED JUNE 30, 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			8
		Note 1. Basis of Presentation	8
		Note 2. Restructuring Charges	8
		Note 3. Revenue Recognition	9
		Note 4. Cash and Cash Equivalents	11
		Note 5. Natural Gas and Oil Properties	11
		Note 6. Earnings per Share	12
		Note 7. Derivatives and Risk Management	13
		Note 8. Reclassifications From Accumulated Other Comprehensive Income (Loss)	20
		Note 9. Fair Value Measurements	20
		Note 10. Debt	22
		Note 1 1 . Commitments and Contingencies	24
		Note 1 2 . Income Taxes	25
		Note 1 3 . Pension Plan and Other Postretirement Benefits	26
		Note 14. Long-Term Incentive Compensation	26
		Note 1 5 . Segment Information	30
		Note 1 6 . New Accounting Pronouncements	31
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations			32
	Results of Operations			34
	Liquidity and Capital Resources			42
Item 3.	Quantitative and Qualitative Disclosures About Market Risk			47
Item 4.	Controls and Procedures			48

PART II – OTHER INFORMATION

Item 1.	Legal Proceedings			48
Item 1A.	Risk Factors			48
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds			48
Item 3.	Defaults Upon Senior Securities			48
Item 4.	Mine Safety Disclosures			48
Item 5.	Other Information			48
Item 6.	Exhibits			49

CAUTIONARY STATEMENT ABOUT FORWARD-LOOKING STATEMENTS

All statements, other than historical fact or present financial information, may be deemed to be forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). All statements that address activities, outcomes and other matters that should or may occur in the future, including, without limitation, statements regarding the financial position, business strategy, production and reserve growth and other plans and objectives for our future operations, are forward-looking statements. Although we believe the expectations expressed in such forward-looking statements are based on reasonable assumptions, such statements 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 regional basis differentials and the impact of reduced demand for our production and products in which our production is a component due to governmental and societal actions taken in response to the COVID-19 pandemic;

•our ability to fund our planned capital investments;

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

•the extent to which lower commodity prices impact our ability to service or refinance our existing debt;

•the impact of volatility in the financial markets or other global economic factors, including the impact of COVID-19;

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

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

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

•our ability to realize the expected benefits from acquisitions;

•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 June 30,						For the six months ended June 30,
(in millions, except share/per share amounts)	2020		2019		2020		2019
Operating Revenues:
Gas sales	$	164	$	275	$	412	$	705
Oil sales	19		47		71		86
NGL sales	40		58		90		139
Marketing	187		287		426		725
Other	—		—		3		2
	410		667		1,002		1,657
Operating Costs and Expenses:
Marketing purchases	201		293		449		734
Operating expenses	182		169		375		334
General and administrative expenses	32		40		58		77
Loss on sale of operating assets	—		3		—		3
Restructuring charges	2		2		12		5
Depreciation, depletion and amortization	84		115		197		227
Impairments	655		6		2,134		6
Taxes, other than income taxes	10		17		23		36
	1,166		645		3,248		1,422
Operating Income (Loss)	(756)		22		(2,246)		235
Interest Expense:
Interest on debt	40		41		80		83
Other interest charges	3		2		5		3
Interest capitalized	(21)		(28)		(44)		(57)
	22		15		41		29

Gain (Loss) on Derivatives	(109)		152		230		120
Gain on Early Extinguishment of Debt	7		—		35		—
Other Income (Loss), Net	—		(6)		1		(5)

Income (Loss) Before Income Taxes	(880)		153		(2,021)		321
Provision (Benefit) for Income Taxes:
Current	—		—		(2)		—
Deferred	—		15		408		(411)
	—		15		406		(411)
Net Income (Loss)	$	(880)	$	138	$	(2,427)	$	732


Earnings (Loss) Per Common Share:
Basic	$	(1.63)	$	0.26	$	(4.49)	$	1.36
Diluted	$	(1.63)	$	0.26	$	(4.49)	$	1.35

Weighted Average Common Shares Outstanding:
Basic	541,079,192		539,005,941		540,693,841		539,362,984
Diluted	541,079,192		539,947,053		540,693,841		540,624,742

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 June 30,						For the six months ended June 30,
(in millions)	2020		2019		2020		2019
Net income (loss)	$	(880)	$	138	$	(2,427)	$	732

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

Comprehensive income (loss)	$	(880)	$	142	$	(2,427)	$	736

(1)Tax benefits for the three months ended June 30, 2020 were immaterial. Net of $1 million in tax benefits for the six months ended June 30, 2020 and the three and six months ended June 30, 2019, respectively. In 2019, primarily related to settlement of pension assets.

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

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SOUTHWESTERN ENERGY COMPANY AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(Unaudited)


	June 30, 2020		December 31, 2019

ASSETS	(in millions)
Current assets:
Cash and cash equivalents	$	10	$	5
Accounts receivable, net	250		345
Derivative assets	466		278
Other current assets	44		51
Total current assets	770		679
Natural gas and oil properties, using the full cost method, including $1,423 million as of June 30, 2020 and $1,506 million as of December 31, 2019 excluded from amortization	25,739		25,250

Other	512		520
Less: Accumulated depreciation, depletion and amortization	(22,825)		(20,503)
Total property and equipment, net	3,426		5,267
Operating lease assets	153		159
Deferred tax assets	—		407
Other long-term assets	206		205
Total long-term assets	359		771
TOTAL ASSETS	$	4,555	$	6,717
LIABILITIES AND EQUITY
Current liabilities:

Accounts payable	$	426	$	525
Taxes payable	48		59
Interest payable	48		51

Derivative liabilities	282		125
Current operating lease liabilities	34		34
Other current liabilities	37		54
Total current liabilities	875		848
Long-term debt	2,440		2,242
Long-term operating lease liabilities	113		119
Pension and other postretirement liabilities	37		43
Other long-term liabilities	267		219
Total long-term liabilities	2,857		2,623
Commitments and contingencies (Note 11)
Equity:
Common stock, $0.01 par value; 1,250,000,000 shares authorized; issued 586,593,540 shares as of June 30, 2020 and 585,555,923 shares as of December 31, 2019	6		6

Additional paid-in capital	4,730		4,726
Accumulated deficit	(3,678)		(1,251)
Accumulated other comprehensive loss	(33)		(33)
Common stock in treasury, 44,353,224 shares as of June 30, 2020 and December 31, 2019	(202)		(202)
Total equity	823		3,246
TOTAL LIABILITIES AND EQUITY	$	4,555	$	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 six months ended June 30,
(in millions)	2020		2019
Cash Flows From Operating Activities:
Net income (loss)	$	(2,427)	$	732
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization	197		227
Amortization of debt issuance costs	4		2
Impairments	2,134		6
Deferred income taxes	408		(411)
Gain on derivatives, unsettled	(17)		(96)
Stock-based compensation	2		4
Gain on early extinguishment of debt	(35)		—
Loss on sale of assets	—		3
Other	—		10
Change in assets and liabilities:
Accounts receivable	94		221
Accounts payable	(121)		(129)
Taxes payable	(11)		(6)
Interest payable	(1)		1
Inventories	6		4
Other assets and liabilities	21		(25)
Net cash provided by operating activities	254		543

Cash Flows From Investing Activities:
Capital investments	(472)		(586)
Proceeds from sale of property and equipment	2		26

Net cash used in investing activities	(470)		(560)

Cash Flows From Financing Activities:

Payments on long-term debt	(72)		—
Payments on revolving credit facility	(919)		—
Borrowings under revolving credit facility	1,221		—
Change in bank drafts outstanding	(8)		(7)


Purchase of treasury stock	—		(21)

Cash paid for tax withholding	(1)		(1)

Net cash provided by (used in) financing activities	221		(29)

Increase (decrease) in cash and cash equivalents	5		(46)
Cash and cash equivalents at beginning of year	5		201
Cash and cash equivalents at end of period	$	10	$	155

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

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SOUTHWESTERN ENERGY COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY

(Unaudited)


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

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

Issuance of restricted stock	12,397	—		—		—		—		—	—			—
Cancellation of restricted stock	(167,130)	—		—		—		—		—	—			—
Restricted units granted	1,005,976	—		1		—		—		—	—			1


Tax withholding – stock compensation	(383,731)	—		—		—		—		—	—			—
Balance at March 31, 2020	586,023,435	$	6	$	4,728	$	(2,798)	$	(33)	44,353,224	$	(202)		$	1,701
Comprehensive loss:
Net loss	—	—		—		(880)		—		—	—			(880)
Other comprehensive income	—	—		—		—		—		—	—			—
Total comprehensive loss	—	—		—		—		—		—	—			(880)
Stock-based compensation	—	—		1		—		—		—	—			1
Issuance of restricted stock	222,489	—		—		—		—		—	—			—
Cancellation of restricted stock	(1,079,515)	—		—		—		—		—	—			—
Restricted units granted	1,649,294	—		2		—		—		—	—			2
Tax withholding – stock compensation	(222,163)	—		(1)		—		—		—	—			(1)
Balance at June 30, 2020	586,593,540	$	6	$	4,730	$	(3,678)	$	(33)	44,353,224	$	(202)		$	823


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

	(in millions, except share amounts)
Balance at December 31, 2018	585,407,107	$	6	$	4,715	$	(2,142)	$	(36)	39,092,537	$	(181)		$	2,362
Comprehensive income:
Net income	—	—		—		594		—		—	—			594
Other comprehensive income	—	—		—		—		—		—	—			—
Total comprehensive income	—	—		—		—		—		—	—			594
Stock-based compensation	—	—		3		—		—		—	—			3

Issuance of restricted stock	8,798	—		—		—		—		—	—			—
Cancellation of restricted stock	(128,324)	—		—		—		—		—	—			—
Treasury stock	—	—		—		—		—		5,260,687	(21)			(21)
Performance units vested	535,802	—		—		—		—		—	—			—
Tax withholding – stock compensation	(274,657)	—		(1)		—		—		—	—			(1)
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

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

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SOUTHWESTERN ENERGY COMPANY AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

(1) BASIS OF PRESENTATION

Southwestern Energy Company (including its subsidiaries, collectively “Southwestern” or the “Company”) is an independent energy company engaged in natural gas, oil and NGL exploration, development and production (“E&P”). The Company is also focused on creating and capturing additional value through its marketing business (“Marketing”), which was previously referred to as “Midstream” when it included the operation of gathering systems. Southwestern conducts most of its business through subsidiaries and operates principally in two segments: E&P and 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 “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 activities through vertical integration.

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

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, 2019 (“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 2019 Annual Report.

(2) RESTRUCTURING CHARGES

On February 4, 2020, the Company notified employees of a workforce reduction plan as a result of a strategic realignment of the Company’s 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 payment depending on length of service and, if applicable, the current value of unvested long-term incentive awards that were forfeited. These costs were recognized as restructuring charges for the three and six months ended June 30, 2020, and a liability of approximately $1 million has been accrued as of June 30, 2020 related to future payments associated with the February 2020 restructuring.

In December 2018, the Company closed 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 (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 equity awards that were forfeited. The Company also incurred charges related to office consolidation. A portion of these costs along with the aforementioned severance costs were recognized as restructuring charges in the first quarter of 2019.

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The following table presents a summary of the restructuring charges included in Operating Income (Loss) for the three and six months ended June 30, 2020 and 2019:


	For the three months ended June 30,						For the six months ended June 30,
(in millions)	2020		2019		2020		2019
Severance (including payroll taxes)	$	2	$	1	$	12	$	3
Office consolidation	—		1		—		2

Total restructuring charges⁽¹⁾	$	2	$	2	$	12	$	5

(1)Total restructuring charges were $2 million and $12 million for the Company’s E&P segment for the three and six months ended June 30, 2020, respectively, and $2 million and $5 million for the three and six months ended June 30, 2019, respectively.

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


(in millions)
Liability at December 31, 2019	$	2
Additions	12
Distributions	(13)
Liability at June 30, 2020	$	1

(3) REVENUE RECOGNITION

Revenues from Contracts with Customers

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

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

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

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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		Marketing		Intersegment Revenues		Total
Three months ended June 30, 2020
Gas sales	$	155	$	—	$	9	$	164
Oil sales	16		—		3		19
NGL sales	40		—		—		40
Marketing	—		389		(202)		187

Total	$	211	$	389	$	(190)	$	410

Three months ended June 30, 2019
Gas sales	$	267	$	—	$	8	$	275
Oil sales	46		—		1		47
NGL sales	58		—		—		58
Marketing	—		626		(339)		287

Total	$	371	$	626	$	(330)	$	667


(in millions)	E&P		Marketing		Intersegment Revenues		Total
Six months ended June 30, 2020
Gas sales	$	394	$	—	$	18	$	412
Oil sales	68		—		3		71
NGL sales	90		—		—		90
Marketing	—		937		(511)		426
Other ⁽¹⁾	3		—		—		3
Total	$	555	$	937	$	(490)	$	1,002

Six months ended June 30, 2019
Gas sales	$	688	$	—	$	17	$	705
Oil sales	85		—		1		86
NGL sales	139		—		—		139
Marketing	—		1,566		(841)		725
Other ⁽²⁾	1		1		—		2
Total	$	913	$	1,567	$	(823)	$	1,657

(1)For the six months ended June 30, 2020, other E&P revenues consists primarily of gains on purchaser imbalances associated with certain NGLs.

(2)For the six months ended June 30, 2019, other E&P revenues consists primarily of water sales to third-party operators, and other 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.


	For the three months ended June 30,						For the six months ended June 30,
(in millions)	2020		2019		2020		2019
Northeast Appalachia	$	117	$	217	$	312	$	565
Southwest Appalachia	94		153		243		346
Other	—		1		—		2
Total	$	211	$	371	$	555	$	913

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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)	June 30, 2020		December 31, 2019
Receivables from contracts with customers	$	183	$	284
Other accounts receivable	67		61
Total accounts receivable	$	250	$	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 six months ended June 30, 2020 and 2019. The Company has no contract assets or contract liabilities associated with its revenues from contracts with customers.

(4) CASH AND CASH EQUIVALENTS

The following table presents a summary of cash and cash equivalents as of June 30, 2020 and December 31, 2019:


(in millions)	June 30, 2020		December 31, 2019
Cash	$	7	$	5
Marketable securities ⁽¹⁾	3		—

Total	$	10	$	5

(1)Consists of government stable value money market funds.

(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 June 30, 2020. Prices used to calculate the ceiling value of reserves were as follows:


	June 30, 2020		June 30, 2019
Natural gas (per MMBtu)	$	2.07	$	3.02
Oil (per Bbl)	$	47.17	$	61.39
NGLs (per Bbl)	$	8.87	$	16.35

Using the average quoted prices above, adjusted for market differentials, the Company’s net book value of its United States natural gas and oil properties exceeded the ceiling by $650 million at June 30, 2020, resulting in a non-cash ceiling test impairment. In the first quarter of 2020, the Company’s net book value of its United States natural gas and oil properties exceeded the ceiling by approximately $1.48 billion and resulted 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. Given the decline in commodity prices in late 2019 and the first half of 2020, the Company expects that an additional non-cash impairment of its assets will likely occur in the third quarter of 2020 and perhaps later.

For the three and six months ended June 30, 2020, the Company recognized a $5 million impairment related to other non-core assets not included in natural gas and oil properties.

The Company’s net book value of its United States natural gas and oil properties did not exceed the ceiling amount at June 30, 2019, and the Company had no derivative positions that were designated for hedge accounting as of June 30, 2019. In June 2019, the Company sold non-core acreage for $25 million. There was no production or proved reserves associated with this acreage.

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(6) EARNINGS PER SHARE

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

In the first quarter of 2019, the Company 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.

The following table presents the computation of earnings per share for the three and six months ended June 30, 2020 and 2019:


	For the three months ended June 30,						For the six months ended June 30,
(in millions, except share/per share amounts)	2020		2019		2020		2019
Net income (loss)	$	(880)	$	138	$	(2,427)	$	732

Number of common shares:
Weighted average outstanding	541,079,192		539,005,941		540,693,841		539,362,984
Issued upon assumed exercise of outstanding stock options	—		—		—		—
Effect of issuance of non-vested restricted common stock	—		311,732		—		481,948
Effect of issuance of non-vested restricted units	—		—		—		—
Effect of issuance of non-vested performance units	—		629,380		—		779,810
Weighted average and potential dilutive outstanding	541,079,192		539,947,053		540,693,841		540,624,742

Earnings per common share
Basic	$	(1.63)	$	0.26	$	(4.49)	$	1.36
Diluted	$	(1.63)	$	0.26	$	(4.49)	$	1.35

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


	For the three months ended June 30,			For the six months ended June 30,
	2020	2019	2020	2019
Unexercised stock options	4,548,735	5,114,763	4,566,648	5,121,663
Unvested share-based payment	902,615	1,773,074	1,024,867	1,822,346
Restricted stock units	2,631,727	—	2,983,352	—
Performance units	2,712,207	241,896	2,096,041	250,998
Total	10,795,284	7,129,733	10,670,908	7,195,007

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(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 June 30, 2020, the Company’s derivative financial instruments consisted of fixed price swaps, two-way costless collars, three-way costless collars, basis swaps and call options. The Company’s interest rate swaps expired in June 2020. A description of the Company’s derivative financial instruments is provided below:


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

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

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

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

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 were used to fix or float interest rates on existing or anticipated indebtedness. The purpose of these instruments was to manage the Company’s existing or anticipated exposure to unfavorable interest rate changes. The Company’s interest rate swaps expired in June 2020.

The Company contracts with counterparties for its derivative instruments that it believes are creditworthy at the time the transactions are entered into, and the Company actively monitors the credit ratings and credit default swap rates of these counterparties where applicable. However, there can be no assurance that a counterparty will be able to meet its obligations to the Company. The fair value of the Company’s derivative assets and liabilities includes a non-performance risk factor. See Note 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.

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


Financial Protection on Production
		Weighted Average Price per MMBtu
	Volume (Bcf)	Swaps		Sold Puts		Purchased Puts		Sold Calls		Basis Differential		Fair Value at June 30, 2020 (in millions)
Natural Gas
2020
Fixed price swaps	218	$	2.39	$	—	$	—	$	—	$	—	$	142	⁽¹⁾
Two-way costless collars	44	—		—		2.12		2.34		—		1
Three-way costless collars	59	—		2.18		2.57		2.96		—		—
Total	321											$	143
2021
Fixed price swaps	36	$	2.53	$	—	$	—	$	—	$	—	$	1
Two-way costless collars	55	—		—		2.34		2.76		—		(5)
Three-way costless collars	306	—		2.16		2.49		2.85		—		(44)
Total	397											$	(48)
2022
Two-way costless collars	29	$	—	$	—	$	2.10	$	2.83	$	—	$	(1)
Three-way costless collars	99	—		2.08		2.45		2.85		—		(8)
Total	128											$	(9)
2023

Three-way costless collars	9	$	—	$	2.16	$	2.59	$	3.36	$	—	$	—

Basis Swaps
2020	145	$	—	$	—	$	—	$	—	$	(0.44)	$	(11)
2021	150	—		—		—		—		(0.14)		10
2022	122	—		—		—		—		(0.46)		(7)
Total	417											$	(8)

(1)Includes $5 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 June 30, 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.

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	Volume (MBbls)	Weighted Average Strike Price per Bbl														Fair Value at June 30, 2020 (in millions)
				Swaps			Sold Puts			Purchased Puts			Sold Calls
Oil
2020
Fixed price swaps⁽¹⁾	1,107	$	72.54		$	—		$	—		$	—		$	36
Two-way costless collars	502	—			—			56.83			59.78			9
Three-way costless collars	895	—			43.54			52.57			57.55			6
Total	2,504													$	51
2021
Fixed price swaps	2,328	$	53.72		$	—		$	—		$	—		$	31
Three-way costless collars	1,445	—			43.52			53.25			58.14			8
Total	3,773													$	39
2022
Fixed price swaps	438	$	51.74		$	—		$	—		$	—		$	4
Three-way costless collars	666	—			42.50			53.20			58.00			3
Total	1,104													$	7

Ethane
2020
Fixed price swaps	5,230	$	8.61		$	—		$	—		$	—		$	4
2021
Fixed price swaps	5,889	$	7.12		$	—		$	—		$	—		$	(3)
2022
Fixed price swaps	136	$	7.35		$	—		$	—		$	—		$	—

Propane
2020
Fixed price swaps	2,748	$	23.01		$	—		$	—		$	—		$	10
Two-way costless collars	184	—			—			25.20			29.40			1
Total	2,932													$	11
2021
Fixed price swaps	4,298	$	19.99		$	—		$	—		$	—		$	6
2022
Fixed price swaps	105	$	19.43		$	—		$	—		$	—		$	—

(1)Includes 790 MBbls of purchased fixed price oil swaps at $36.64 per barrel with a fair value of $2 million and 1,897 MBbls of sold fixed price oil swaps at $57.60 per barrel with a fair value of $34 million.


Other Derivative Contracts
	Volume (Bcf)	Weighted Average Strike Price per MMBtu		Fair Value at June 30, 2020 (in millions)





Call Options – Natural Gas (Net)
2020	17	$	3.03	$	(1)
2021	57	3.15		(9)
2022	58	3.00		(9)
2023	17	2.84		(3)
2024	9	3.00		(2)
Total	158			$	(24)

໿


	Volume (MBbls)	Weighted Average Strike Price per Bbl		Fair Value at June 30, 2020 (in millions)
Call Options – Oil
2021	226	$	60.00	$	—

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	Volume (Bcf)	Weighted Average Strike Price per MMBtu								Fair Value at June 30, 2020 (in millions)
				Swaps			Basis Differential
Storage ⁽¹⁾
2020
Purchased fixed price swaps	2	$	2.00		$	—		$	(1)
Purchased basis swaps	1	—			(0.58)			—
Sold fixed price swaps	2	1.99			—			1
Sold basis swaps	1	—			(0.51)			—
Total	6							$	—
2021
Purchased fixed price swaps	1	$	2.04		$	—		$	—
Sold fixed price swaps	2	2.49			—			—
Sold basis swaps	1	—			(0.38)			—
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 and sold at a later date.


Purchased Fixed Price Swaps – Marketing (Natural Gas) ⁽¹⁾	Volume (Bcf)	Weighted Average Strike Price per MMBtu		Fair Value at June 30, 2020 (in millions)
2020	5	$	2.35	$	(2)
2021	6	2.44		1
Total	11			$	(1)

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

At June 30, 2020, the net fair value of the Company’s financial instruments related to commodities was a $168 million asset and included a net increase of $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 June 30, 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 was 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 had a notional amount of $170 million and expired in June 2020. Changes in the fair value of the interest rate swaps were included in gain (loss) on derivatives on the consolidated statements of operations.

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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 June 30, 2020 and December 31, 2019:


Derivative Assets
		Fair Value
(in millions)	Balance Sheet Classification	June 30, 2020			December 31, 2019
Derivatives not designated as hedging instruments:

Purchased fixed price swaps – natural gas	Derivative assets	$	1		$	—
Purchased fixed price swaps – oil	Derivative assets	4			—
Fixed price swaps – natural gas	Derivative assets	144		⁽¹⁾	77		⁽¹⁾
Fixed price swaps – oil	Derivative assets	48			4
Fixed price swaps – ethane	Derivative assets	5			11
Fixed price swaps – propane	Derivative assets	14			21
Two-way costless collars – natural gas	Derivative assets	16			10
Two-way costless collars – oil	Derivative assets	13			5
Two-way costless collars – propane	Derivative assets	1			2
Three-way costless collars – natural gas	Derivative assets	175			126
Three-way costless collars – oil	Derivative assets	24			3
Basis swaps – natural gas	Derivative assets	15			17
Purchased call options – natural gas	Derivative assets	5			1
Fixed price swaps – natural gas storage	Derivative assets	1			1

Fixed price swaps – natural gas	Other long-term assets	—			7
Fixed price swaps – oil	Other long-term assets	21			1

Fixed price swaps – propane	Other long-term assets	5			3
Two-way costless collars – natural gas	Other long-term assets	10			4


Three-way costless collars – natural gas	Other long-term assets	71			74
Three-way costless collars – oil	Other long-term assets	21			7
Basis swaps – natural gas	Other long-term assets	8			15
Purchased call options – natural gas	Other long-term assets	2			2
Total derivative assets		$	604		$	391

(1) Includes $5 million and $9 million at June 30, 2020 and December 31, 2019, respectively, 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. 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	June 30, 2020		December 31, 2019
Derivatives not designated as hedging instruments:
Purchased fixed price swaps – natural gas	Derivative liabilities	$	2	$	1
Purchased fixed price swaps – oil	Derivative liabilities	2		—
Fixed price swaps – natural gas	Derivative liabilities	—		1
Fixed price swaps – oil	Derivative liabilities	—		6
Fixed price swaps – ethane	Derivative liabilities	3		—
Fixed price swaps – propane	Derivative liabilities	2		—
Two-way costless collars – natural gas	Derivative liabilities	18		4
Two-way costless collars – oil	Derivative liabilities	4		5
Three-way costless collars – natural gas	Derivative liabilities	206		84
Three-way costless collars – oil	Derivative liabilities	13		4
Basis swaps – natural gas	Derivative liabilities	19		17
Sold call options – natural gas	Derivative liabilities	12		3

Purchased fixed price swaps – natural gas storage	Derivative liabilities	1		—
Fixed price swaps – natural gas	Other long-term liabilities	1		—
Fixed price swaps – oil	Other long-term liabilities	—		2
Fixed price swaps – ethane	Other long-term liabilities	1		—
Fixed price swaps – propane	Other long-term liabilities	1		—
Two-way costless collars – natural gas	Other long-term liabilities	13		4

Three-way costless collars – natural gas	Other long-term liabilities	92		72
Three-way costless collars – oil	Other long-term liabilities	15		8
Basis swap – natural gas	Other long-term liabilities	12		9
Sold call options – natural gas	Other long-term liabilities	19		15
Sold call options – oil	Other long-term liabilities	—		1
Total derivative liabilities		$	436	$	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 six months ended June 30, 2020 and 2019:


Unsettled Gain (Loss) on Derivatives Recognized in Earnings

Derivative Instrument	Consolidated Statement of Operations Classification of Gain (Loss) on Derivatives, Unsettled	For the three months ended June 30,									For the six months ended June 30,
							2020			2019			2020			2019

		(in millions)
Purchased fixed price swaps – natural gas	Gain (Loss) on Derivatives	$	1		$	—		$	—		$	—
Purchased fixed price swaps – oil	Gain (Loss) on Derivatives	7			1			2			5
Fixed price swaps – natural gas	Gain (Loss) on Derivatives	(39)			57			64			55
Fixed price swaps – oil	Gain (Loss) on Derivatives	(46)			5			72			(8)
Fixed price swaps – ethane	Gain (Loss) on Derivatives	(22)			—			(10)			7
Fixed price swaps – propane	Gain (Loss) on Derivatives	(44)			13			(8)			9
Two-way costless collars – natural gas	Gain (Loss) on Derivatives	(7)			10			(11)			9
Two-way costless collars – oil	Gain (Loss) on Derivatives	(10)			4			9			(3)
Two-way costless collars – propane	Gain (Loss) on Derivatives	(3)			2			(1)			2
Three-way costless collars – natural gas	Gain (Loss) on Derivatives	(45)			22			(96)			24
Three-way costless collars – oil	Gain (Loss) on Derivatives	(6)			1			19			1
Basis swaps – natural gas	Gain (Loss) on Derivatives	(13)			4			(14)			(6)
Purchased call options – natural gas	Gain (Loss) on Derivatives	3			(2)			4			(2)
Sold call options – natural gas	Gain (Loss) on Derivatives	(7)			4			(13)			6
Sold call options – oil	Gain (Loss) on Derivatives	—			—			1			—
Purchased fixed price swap – natural gas storage	Gain (Loss) on Derivatives	—			—			(1)			—
Fixed price swap – natural gas storage	Gain (Loss) on Derivatives	1			(1)			—			(1)
Interest rate swaps	Gain (Loss) on Derivatives	1			(2)			—			(2)
Total gain (loss) on unsettled derivatives					$	(229)		$	118		$	17		$	96

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

Derivative Instrument	Consolidated Statement of Operations Classification of Gain (Loss) on Derivatives, Settled	For the three months ended June 30,									For the six months ended June 30,
							2020			2019			2020			2019

		(in millions)
Purchased fixed price swaps – natural gas	Gain (Loss) on Derivatives	$	(1)		$	—		$	(2)		$	—
Purchased fixed price swaps – oil	Gain (Loss) on Derivatives	(4)			(1)			(4)			(2)
Purchased fixed price swaps – ethane	Gain (Loss) on Derivatives	1			—			1			—
Fixed price swaps – natural gas	Gain (Loss) on Derivatives	84		⁽²⁾	14			89		⁽²⁾	8
Fixed price swaps – oil	Gain (Loss) on Derivatives	22			2			31			4
Fixed price swaps – ethane	Gain (Loss) on Derivatives	1			5			7			6
Fixed price swaps – propane	Gain (Loss) on Derivatives	7			7			17			9
Two-way costless collars – natural gas	Gain (Loss) on Derivatives	—			3			6			2
Two-way costless collars – oil	Gain (Loss) on Derivatives	6			1			9			2
Two-way costless collars – propane	Gain (Loss) on Derivatives	1			—			2			—
Three-way costless collars – natural gas	Gain (Loss) on Derivatives	7			8			43			4
Three-way costless collars – oil	Gain (Loss) on Derivatives	3			—			4			—
Basis swaps – natural gas	Gain (Loss) on Derivatives	(7)			(4)			9			(8)

Sold call options – natural gas	Gain (Loss) on Derivatives	—			(1)			—			(1)

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

Total gain on settled derivatives					$	120		$	34		$	213		$	24

Total gain (loss) on derivatives					$	(109)		$	152		$	230		$	120

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

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

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

In the first half of 2020, changes in accumulated other comprehensive income were related to the Company’s pension and other postretirement benefits. The following tables detail the components of accumulated other comprehensive income and the related tax effects for the six months ended June 30, 2020:


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

Details about Accumulated Other Comprehensive Income

Affected Line Item in the Consolidated Statement of Operations

Amount Reclassified from Accumulated Other Comprehensive Income

For the six months ended
June 30, 2020

(in millions)

Pension and other postretirement:

Amortization of prior service cost and net gain⁽¹⁾

Other Income (Loss), Net

(1)

Provision (Benefit) for Income Taxes

(1)

Net Income (Loss)

—

Total reclassifications for the period

Net Income (Loss)

—

(1) See Note 13 for additional details regarding the Company’s pension and other postretirement benefit plans.

(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 June 30, 2020 and December 31, 2019 were as follows:


	June 30, 2020									December 31, 2019
(in millions)	Carrying Amount			Fair Value			Carrying Amount			Fair Value
Cash and cash equivalents	$	10		$	10		$	5		$	5
2018 revolving credit facility due April 2024	336			336			34			34
Senior notes⁽¹⁾	2,121			1,866			2,228			2,085
Derivative instruments, net	168		⁽²⁾	168		⁽²⁾	155		⁽²⁾	155		⁽²⁾

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

(2)Includes $5 million and $9 million in premiums paid as of June 30, 2020 and December 31, 2019, respectively, 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 are based on the market value of the Company’s publicly traded debt as determined based on the market prices of the Company’s senior notes. The fair value of the Company’s 4.10% Senior Notes due March 2022 is considered to be a Level 2 measurement on the fair value hierarchy. The fair values of the Company’s

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

Derivative Instruments: The Company measures the fair value of its derivative instruments based upon a pricing model that utilizes market-based inputs, including, but not limited to, the contractual price of the underlying position, current market prices, natural gas and liquids forward curves, discount rates such as the LIBOR curve for a similar duration of each outstanding position, volatility factors and non-performance risk. Non-performance risk considers the effect of the Company’s credit standing on the fair value of derivative liabilities and the effect of counterparty credit standing on the fair value of derivative assets. Both inputs to the model are based on published credit default swap rates and the duration of each outstanding derivative position. As of June 30, 2020, the impact of non-performance risk on the fair value of the Company’s net derivative asset position was a net increase of $1 million.

The Company has classified its derivative instruments into levels depending upon the data utilized to determine their fair values. The Company’s fixed price swaps (Level 2) are estimated using third-party discounted cash flow calculations using the New York Mercantile Exchange (“NYMEX”) futures index for natural gas and oil derivatives and Oil Price Information Service (“OPIS”) for ethane and propane derivatives. The Company utilized 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 June 30, 2020 were 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. 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:


	June 30, 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	$	—	$	5	$	—	$	5
Fixed price swaps ⁽¹⁾	—		237		—		237
Two-way costless collars	—		40		—		40
Three-way costless collars	—		291		—		291
Basis swaps	—		23		—		23
Purchased call options	—		7		—		7
Fixed price swaps - storage	—		1		—		1

Liabilities
Purchased fixed price swaps	—		(4)		—		(4)
Fixed price swaps	—		(8)		—		(8)
Two-way costless collars	—		(35)		—		(35)
Three-way costless collars	—		(326)		—		(326)
Basis swaps	—		(31)		—		(31)
Sold call options	—		(31)		—		(31)
Purchased fixed price swaps – storage	—		(1)		—		(1)

Total⁽²⁾	$	—	$	168	$	—	$	168

(2)Includes a net fair value increase of $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.

The fair values of Level 3 derivative instruments are estimated using proprietary valuation models that utilize both market observable and unobservable parameters. Level 3 instruments consist of net derivatives valued using pricing models incorporating assumptions that, in the Company’s judgment, reflect reasonable assumptions a marketplace participant would use. There were no Level 3 derivatives in the second quarters of 2020 and 2019.

(10) DEBT

The components of debt as of June 30, 2020 and December 31, 2019 consisted of the following:


	June 30, 2020
(in millions)	Debt Instrument		Unamortized Issuance Expense			Unamortized Debt Discount		Total




Long-term debt:
Variable rate (1.860% at June 30, 2020) 2018 revolving credit facility due April 2024	$	336	$	—	⁽¹⁾	$	—	$	336
4.10% Senior Notes due March 2022	207		(1)			—		206
4.95% Senior Notes due January 2025⁽²⁾	856		(4)			(1)		851
7.50% Senior Notes due April 2026	618		(6)			—		612
7.75% Senior Notes due October 2027	440		(5)			—		435
Total long-term debt	$	2,457	$	(16)		$	(1)	$	2,440



	December 31, 2019
(in millions)	Debt Instrument		Unamortized Issuance Expense			Unamortized Debt Discount		Total
Long-term debt:
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	213		(1)			—		212
4.95% Senior Notes due January 2025⁽²⁾	892		(5)			(1)		886
7.50% Senior Notes due April 2026	639		(7)			—		632
7.75% Senior Notes due October 2027	484		(6)			—		478
Total long-term debt	$	2,262	$	(19)		$	(1)	$	2,242

(1)At June 30, 2020 and December 31, 2019, unamortized issuance expense of $10 million and $11 million, respectively, associated with the 2018 credit facility (as defined below) was classified as other long-term assets on the consolidated balance sheets.

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(2)At June 30, 2020 and December 31, 2019, the interest rate was 6.20% for the 2025 Notes, 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 Company’s 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 paid in January 2021.

Credit Facilities

2018 Revolving Credit Facility

In April 2018, the Company replaced its credit facility that was entered into in 2016 with a new revolving credit facility (the “2018 credit facility”) with a group of banks that, as amended, has a maturity date of April 2024. The 2018 credit facility has an aggregate maximum revolving credit amount of $3.5 billion and, in April 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 borrowing base is subject to redetermination at least twice a year, in April and October, and is secured by substantially all of the assets owned by the Company and its subsidiaries. The permitted lien provisions in the senior note indentures currently limit liens securing indebtedness to the greater of $2.0 billion or 25% of adjusted consolidated net tangible assets.

The Company may utilize the 2018 credit facility in the form of loans and letters of credit. Loans under the 2018 credit facility are subject to varying rates of interest based on whether the loan is a Eurodollar loan or an alternate base rate loan. Eurodollar loans bear interest at the Eurodollar rate, which is adjusted LIBOR for such interest period plus the applicable margin (as those terms are defined in the 2018 credit facility documentation). The applicable margin for Eurodollar loans under the 2018 credit facility ranges from 1.50% to 2.50% based on the Company’s utilization of the 2018 credit facility. Alternate base rate loans bear interest at the alternate base rate plus the applicable margin. The applicable margin for alternate base rate loans under the 2018 credit facility ranges from 0.50% to 1.50% based on the Company’s utilization of the 2018 credit facility.

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

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

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

•restrictions on mergers and asset dispositions;

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

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

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

2.Maximum total net leverage ratio of no greater than (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 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 June 30, 2020, the Company was in compliance with all of the covenants contained in the credit agreement governing the 2018 credit facility. As a result of improving market conditions as evidenced by oil and NGL pricing and management actions, the Company’s current modeling no longer indicates that Southwestern will be in non-compliance with any covenants under the 2018 credit facility in late 2020.

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

As of June 30, 2020, the Company had $209 million in letters of credit and $336 million borrowings outstanding under the 2018 credit facility. The Company currently does not anticipate being required to supply a materially greater amount of letters of credit under its existing contracts.

The Company’s exposure to the anticipated transition from LIBOR in late 2021 is limited to the 2018 credit facility. Upon announcement by the administrator of LIBOR identifying a specific date for LIBOR cessation, the credit agreement governing the 2018 credit facility will be amended to reference an alternative rate as established by JP Morgan, as Administrative Agent, and the Company. The alternative rate will be based on the prevailing market convention and is expected to be the Secured Overnight Financing Rate (“SOFR”).

Senior Notes

In January 2015, the Company completed a public offering of $1.0 billion aggregate principal amount of its 4.95% senior notes due 2025 (the “2025 Notes”). The interest rate on the 2025 Notes is determined based upon the public bond ratings from Moody’s and S&P. Downgrades on the 2025 Notes from either rating agency increase interest costs by 25 basis points per downgrade level and upgrades decrease interest costs by 25 basis points per upgrade level, up to the stated coupon rate, on the following semi-annual bond interest payment. At June 30, 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 Company’s bond rating to BB-, which had 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 paid in January 2021. In the event of future downgrades, the coupons for this series of notes have been capped at 6.95%.

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

(11) COMMITMENTS AND CONTINGENCIES

Operating Commitments and Contingencies

As of June 30, 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 $7.3 billion, $402 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 $1.0 billion of that amount. As of June 30, 2020, future payments under non-cancelable firm transportation and gathering agreements were as follows:


	Payments Due by Period
(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	$	6,947	$	667	$	1,323	$	1,091	$	1,462	$	2,404
Pending regulatory approval and/or construction ⁽¹⁾	402		2		17		22		65		296
Total transportation charges	$	7,349	$	669	$	1,340	$	1,113	$	1,527	$	2,700

(1)Based on estimated in-service dates as of June 30, 2020.

In December 2018, the Company closed the Fayetteville Shale 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 June 30, 2020, approximately $54 million of these contractual commitments remain of which the Company will reimburse the buyer for certain of these potential obligations up to approximately $27 million through December 2020 depending on the buyer’s actual use, and has recorded a $21 million liability for the estimated future payments, down from $46 million recorded at December 31, 2019.

In the first quarter of 2019, the Company agreed to acquire firm transportation contracts 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 releasing shipper has agreed to reimburse $133 million of these commitments.

In February 2020, the Company was notified that the proposed Constitution pipeline project was cancelled and that the Company was released from a firm transportation agreement with its sponsor. Prior to its cancellation, the Company had contractual commitments totaling $512 million over the next 17 years related to the Constitution pipeline project.

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Environmental Risk

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

Litigation

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

St. Lucie County Fire District Firefighters’ Pension Trust

On October 17, 2016, the St. Lucie County Fire District Firefighters’ Pension Trust filed a putative class action in the 61st District Court in Harris County, Texas, against the Company, certain of its former officers and current and former directors and the underwriters on behalf of itself and others that purchased certain depositary shares from the Company’s January 2015 equity offering, alleging material misstatements and omissions in the registration statement for that offering. The Company removed the case to federal court, but after a decision by the United States Supreme Court in an unrelated case that these types of cases are not subject to removal, the federal court remanded the case to the Texas state court. The Texas trial court denied the Company’s motion to dismiss, and in February 2020, the court of appeals declined to exercise discretion to reverse the trial court’s decision. The Company filed a petition to review the trial court’s decision with the Texas Supreme Court, and the Court requested a response from the plaintiff. The 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 this case to have a material adverse effect on the results of operations, financial position or cash 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, 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. No material liabilities have been recognized in connection with these indemnifications.

(12) INCOME TAXES

The Company’s effective tax rate was approximately 0% and (20)% for the three and six months ended June 30, 2020, respectively. The change in the effective tax rate for the six months ended June 30, 2020 related to the effects of recording a valuation allowance against the Company’s U.S. deferred tax assets. A valuation allowance for deferred tax assets, including net operating losses, is recognized when it is more likely than not that some or all of the benefit from the deferred tax assets will not be realized. To assess that likelihood, the Company uses estimates and judgment regarding future taxable income, and considers the tax consequences in the jurisdiction where such taxable income is generated, to determine whether a valuation allowance is required. Such evidence can include current financial position, results of operations, both actual and forecasted, the reversal of deferred tax liabilities and tax planning strategies as well as current and forecasted business economics of the oil and gas industry.

Due to significant pricing declines and the material write-down of the carrying value of the Company’s natural gas and oil properties in addition to other negative evidence, the Company concluded that it was more likely than not that these deferred tax

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assets will not be realized and recorded a discrete tax expense of $408 million for the increase in its valuation allowance in the first quarter of 2020. 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 asset considered realizable, however, could be adjusted based on changes in subjective estimates of future taxable income or if objective negative evidence is no longer present.

The Company’s effective tax rate was approximately 10% and (128)% for the three and six months ended June 30, 2019, respectively. The effective tax rate for the six months ended June 30, 2019 was primarily the effect of 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 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 would be released during 2019, of which $411 million was released on a discrete basis in the first half of 2019.

(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 six months ended June 30, 2020 and 2019:



	Consolidated Statements of Operations Classification of Net Periodic Benefit Cost	For the three months ended June 30,									For the six months ended June 30,
(in millions)				2020			2019			2020			2019
Service cost	General and administrative expenses	$	2		$	2		$	4		$	4
Interest cost	Other Income (Loss), Net	1			1			2			2
Expected return on plan assets	Other Income (Loss), Net	(2)			(1)			(3)			(3)
Amortization of prior service cost	Other Income (Loss), Net	—			—			—			—
Amortization of net loss	Other Income (Loss), Net	—			—			—			1
Settlement loss	Other Income (Loss), Net	—			4			—			4
Net periodic benefit cost		$	1		$	6		$	3		$	8

The Company’s other postretirement benefit plan had a net periodic benefit cost of less than $1 million for the three months ended June 30, 2020 and 2019, respectively, and $1 million and $1 million for the six months ended June 30, 2020 and 2019, respectively.

As of June 30, 2020, the Company has contributed $9 million to the pension and other postretirement benefit plans and expects to contribute an additional $3 million to its pension plan during the remainder of 2020. The Company recognized liabilities of $24 million and $14 million related to its pension and other postretirement benefits, respectively, as of June 30, 2020, compared to liabilities of $30 million and $13 million as of December 31, 2019, respectively.

In the first half of 2019, the Company recognized a $4 million non-cash settlement loss related to $16 million of lump-sum payments from the pension plan for employees who were terminated as a result of the Fayetteville Shale sale.

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 at June 30, 2020 and December 31, 2019, respectively.

(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 issued its first long-term fixed cash-based awards.

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

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administrative expense on a straight-line basis over the vesting period of the award. A portion of this general and administrative expense is capitalized into natural gas and oil properties, included in property and equipment. The fair value of a liability-classified award is determined on a quarterly basis beginning at the grant date until final vesting. Changes in the fair value of liability-classified awards are recorded to general and administrative expense and capitalized expense over the vesting period of the award. Generally, stock options granted to employees and directors vest ratably over three years from the grant date and expire seven years from the date of grant. The Company issues shares of restricted stock, restricted stock units or performance cash awards to employees and directors which generally vest over four years. Restricted stock, restricted stock units, performance cash awards and stock options granted to participants under the 2013 Incentive Plan, as amended and restated, immediately vest upon death, disability or retirement (subject to a minimum of three years of service). The Company issues performance unit awards to employees which historically have vested at or over three years.

In February 2020, the Company notified employees of a workforce reduction plan as a result of a strategic realignment of the Company’s organizational structure. This reduction was substantially complete by the end of the first quarter of 2020. Affected employees were offered a severance package which, if applicable, included the current value of unvested long-term incentive awards that were forfeited.

The Company recognized the following amounts in total employee stock-based compensation costs for the three and six months ended June 30, 2020 and 2019:


	For the three months ended June 30,						For the six months ended June 30,
(in millions)	2020		2019		2020		2019
Stock-based compensation cost – expensed	$	6	$	4	$	6	$	11
Stock-based compensation cost – capitalized	1		2		1		6

Equity-Classified Awards

The Company recognized the following amounts in employee equity-classified stock-based compensation costs for the three and six months ended June 30, 2020 and 2019:


	For the three months ended June 30,						For the six months ended June 30,
(in millions)	2020		2019		2020		2019
Equity-classified awards – expensed	$	1	$	2	$	2	$	4
Equity-classified awards – capitalized	—		1		—		2

As of June 30, 2020, there was $3 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 0.7 years.

Equity-Classified Stock Options

The following table summarizes equity-classified stock option activity for the six months ended June 30, 2020 and provides information for options outstanding and options exercisable as of June 30, 2020:


	Number of Options	Weighted Average Exercise Price
	(in thousands)
Outstanding at December 31, 2019	4,635	$	15.26
Granted	—	$	—
Exercised	—	$	—
Forfeited or expired	(157)	$	9.15
Outstanding at June 30, 2020	4,478	$	15.48
Exercisable at June 30, 2020	4,478	$	15.48

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Equity-Classified Restricted Stock

The following table summarizes equity-classified restricted stock activity for the six months ended June 30, 2020 and provides information for unvested shares as of June 30, 2020:


	Number of Shares	Weighted Average Fair Value
	(in thousands)
Unvested shares at December 31, 2019	1,480	$	7.00
Granted	507	$	2.88
Vested	(1,003)	$	5.49
Forfeited	(241)	$	7.69
Unvested shares at June 30, 2020	743	$	6.00

Equity-Classified Performance Units

The following table summarizes equity-classified performance unit activity for the six months ended June 30, 2020 and provides information for unvested units as of June 30, 2020. The performance unit awards granted in 2018 include a market condition based exclusively on the Total Shareholder Return (“TSR”), with 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 Units ⁽¹⁾	Weighted Average Fair Value
	(in thousands)
Unvested units at December 31, 2019	178	$	10.47
Granted	—	$	—
Vested	(178)	$	10.47
Forfeited	—	$	—
Unvested units at June 30, 2020	—	$	—

(1)The actual payout of shares may range from a minimum of zero shares to a maximum of two 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 six months ended June 30, 2020:


	For the three months ended June 30,						For the six months ended June 30,
(in millions)	2020		2019		2020		2019
Liability-classified stock-based compensation cost – expensed	$	5	$	2	$	4	$	7
Liability-classified stock-based compensation cost – capitalized	1		1		1		4

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Liability-Classified Restricted Stock Units

In the first quarter of each year beginning with 2018, the Company granted restricted stock units that vest over a period of four years and are payable in either cash or shares at the option of the Compensation Committee of the Company’s Board of Directors. The Company has accounted for these as liability-classified awards, and accordingly changes in the market value of the instruments will be recorded to general and administrative expense and capitalized expense over the vesting period of the award. As of June 30, 2020, there was $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 2.8 years. The amount of unrecognized compensation cost for liability-classified awards will fluctuate over time as they are marked to market.


	Number of Units	Weighted Average Fair Value
	(in thousands)
Unvested units at December 31, 2019	12,992	$	2.42
Granted	6,172	$	1.41
Vested	(3,946)	$	1.42
Forfeited	(2,829)	$	1.56
Unvested units at June 30, 2020	12,389	$	2.56

Liability-Classified Performance Units

In each year beginning with 2018, the Company granted performance units that vest at the end of, or over, a three-year period and are payable in either cash or shares at the option of the Compensation Committee of the Company’s Board of Directors. The Company has accounted for these as liability-classified awards, and accordingly changes in the fair market value of the instruments will be recorded to general and administrative expense and capitalized expense over the vesting period of the awards. The performance unit awards granted in 2018 include a performance condition based on cash flow per debt-adjusted share and two market conditions, one based on absolute TSR and the other on relative TSR as compared to a group of the Company’s peers. The performance unit awards granted in 2019 include performance conditions based on return on average capital employed and two market conditions, one based on absolute TSR and the other on relative TSR. The performance units granted in 2020 include a performance condition based on return on average capital employed and a market condition based on relative TSR. The fair values of the market conditions are calculated by Monte Carlo models on a quarterly basis. As of June 30, 2020, there was $15 million of total unrecognized compensation cost related to liability-classified performance units. This cost is expected to be recognized over a weighted-average period of 2.3 years. The amount of unrecognized compensation cost for liability-classified awards will fluctuate over time as they are marked to market. The final value of the performance unit awards is contingent upon the Company’s actual performance against these performance measures.


	Number of Units	Weighted Average Fair Value
	(in thousands)
Unvested units at December 31, 2019	5,142	$	2.42
Granted	6,172	$	1.41
Vested	—	$	—
Forfeited	(2,124)	$	3.10
Unvested units at June 30, 2020	9,190	$	2.56

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 June 30, 2020, there was $18 million of total unrecognized compensation cost related to performance cash awards. This cost is expected to be recognized over a weighted average 3.7 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 December 31, 2019	—	$	—
Granted	20,044	$	1.00
Vested	—	$	—
Forfeited	(451)	$	1.00
Unvested units at June 30, 2020	19,593	$	1.00

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

Summarized financial information for the Company’s reportable segments is shown in the following table. The accounting policies of the segments are the same as those described in Note 1 of the Notes to Consolidated Financial Statements included in Item 8 of the 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. The “Other” column includes items not related to the Company’s reportable segments, including real estate and corporate items. Corporate general and administrative costs, depreciation expense and taxes, other than income taxes, are allocated to the segments.


	E&P			Marketing		Other			Total

	(in millions)
Three months ended June 30, 2020
Revenues from external customers	$	223		$	187	$	—		$	410
Intersegment revenues	(12)			202		—			190
Depreciation, depletion and amortization expense	81			3		—			84
Impairments	655			—		—			655
Operating loss	(748)		⁽¹⁾	(8)		—			(756)
Interest expense ⁽²⁾	22			—		—			22
Loss on derivatives	(109)			—		—			(109)
Gain on extinguishment of debt	—			—		7			7
Other income (loss), net	(1)			—		1			—
Provision for income taxes⁽²⁾	—			—		—			—
Assets	4,185		⁽³⁾	208		162		⁽⁴⁾	4,555
Capital investments ⁽⁵⁾	245			—		—			245

Three months ended June 30, 2019
Revenues from external customers	$	380		$	287	$	—		$	667
Intersegment revenues	(9)			339		—			330
Depreciation, depletion and amortization expense	112			3		—			115
Impairments	6			—		—			6
Operating income (loss)	30		⁽¹⁾	(8)		—			22
Interest expense ⁽²⁾	15			—		—			15
Gain on derivatives	152			—		—			152

Other loss, net	(5)			—		(1)			(6)
Provision for income taxes⁽²⁾	15			—		—			15
Assets	5,945		⁽³⁾	277		323		⁽⁴⁾	6,545
Capital investments ⁽⁵⁾	367			—		1			368

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	E&P			Marketing		Other			Total

Six months ended June 30, 2020	(in millions)
Revenues from external customers	$	576		$	426	$	—		$	1,002
Intersegment revenues	(21)			511		—			490
Depreciation, depletion and amortization expense	192			5		—			197
Impairments	2,134			—		—			2,134
Operating income (loss)	(2,234)		⁽¹⁾	(12)		—			(2,246)
Interest expense⁽²⁾	41			—		—			41
Gain on derivatives	230			—		—			230
Gain on early extinguishment of debt	—			—		35			35
Other income, net	—			—		1			1
Provision for income taxes ⁽²⁾	406			—		—			406
Assets	4,185		⁽³⁾	208		162		⁽⁴⁾	4,555
Capital investments⁽⁵⁾	482			—		—			482

Six months ended June 30, 2019
Revenues from external customers	$	931		$	726	$	—		$	1,657
Intersegment revenues	(18)			841		—			823
Depreciation, depletion and amortization expense	222			5		—			227
Impairments	6			—		—			6
Operating income (loss)	240		⁽¹⁾	(5)		—			235
Interest expense⁽²⁾	29			—		—			29
Gain on derivatives	120			—		—			120

Other loss, net	(4)			—		(1)			(5)
Benefit from income taxes⁽²⁾	(411)			—		—			(411)
Assets	5,945		⁽³⁾	277		323		⁽⁴⁾	6,545
Capital investments⁽⁵⁾	692			—		1			693

(1)Operating income for the E&P segment includes $2 million and $2 million of restructuring charges for the three months ended June 30, 2020 and 2019, respectively, and $12 million and $5 million of restructuring charges for the six months ended June 30, 2020 and 2019, 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. E&P assets also includes deferred tax assets which are an allocation of corporate amounts as they are incurred at the corporate level.

(4)Other assets represent corporate assets not allocated to segments and assets for non-reportable segments. At June 30, 2020 and 2019, other assets included approximately $10 million and $155 million, respectively, in cash and cash equivalents, $31 million and $68 million, respectively, in income taxes receivable, $21 million and $50 million, respectively, in property, plant and equipment, $10 million and $10 million, respectively, in unamortized debt expense, $5 million and $6 million, respectively, in a non-qualified retirement plan and $77 million and $29 million in right-of-use lease assets, respectively. Additionally, the June 30, 2020 other asset balance includes $7 million in prepayments and the June 30, 2020 and 2019 other asset balances includes $1 million and $5 million in other assets, respectively.

(5)Capital investments include an increase of $39 million for the three months ended June 30, 2019 and increases of $8 million and $105 million for the six months ended June 30, 2020 and 2019, respectively, relating to the change in accrued expenditures between years. There was no change in the capital accrual for the three months ended June 30, 2020.

(16) NEW ACCOUNTING PRONOUNCEMENTS

Recently Adopted

In August 2018, the FASB issued Accounting Standards Update No. 2018-13, Fair Value Measurement (ASC 820): Disclosure Framework – Changes to the Disclosure Requirements for Fair Value Measurements (“ASU 2018-13”), which modifies the disclosure requirements on fair value measurements. ASU 2018-13 became effective for public business entities for annual and interim periods in fiscal years beginning after December 15, 2019. As a result of adoption, this standard did not have a material impact on the Company’s consolidated 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 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.

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From an evaluation of the Company’s 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 and are expected to remain so in the future assuming no substantial changes to the business or creditworthiness of our business counterparties. 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 guidance in ASU 2018-14 is effective for fiscal years beginning after December 15, 2020, with early adoption permitted. This ASU will result in expanded disclosures within the Company’s interim and annual footnote disclosures, however, the adoption of ASU 2018-14 is not expected to have a material impact on the Company’s consolidated financial statements.

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 2019 Annual Report and analyzes the changes in the results of operations between the three and six month periods ended June 30, 2020 and 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 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 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.

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 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 call “Marketing” but previously referred to as “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.

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 “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 activities through vertical integration.

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

Recent Financial and Operating Results

Significant second quarter 2020 operating and financial results include:

Total Company

•Net loss of $880 million, or ($1.63) per diluted share, decreased compared to net income of $138 million, or $0.26 per diluted share, for the same period in 2019. The decrease was primarily due to a $650 million non-cash full cost ceiling test impairment, a $261 million negative impact of derivatives (which included an $86 million improvement in settled derivatives as compared to the same period in 2019) and lower margins associated with reduced commodity prices.

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•Operating loss of $756 million compared to operating income of $22 million for the same period in 2019 on a consolidated basis primarily due to a $650 million non-cash full cost ceiling test impairment in the second quarter of 2020. Excluding the non-cash impairment, operating loss of $106 million decreased $128 million compared to the same period in 2019 as lower margins associated with reduced commodity prices were only partially offset by increased natural gas and liquids production.

•Net cash provided by operating activities of $94 million decreased 7% from $101 million for the same period in 2019 as improvements in settled derivatives discussed above and working capital combined with higher production was more than offset by lower commodity prices and marketing margin along with a decrease in capitalized interest expense.

•Total capital investment of $245 million decreased 33% from $368 million for the same period in 2019.

•We repurchased $27 million in aggregate principal amount of our outstanding senior notes at a discount and recognized a gain on the extinguishment of debt of $7 million.

E&P

•E&P segment operating loss of $748 million decreased from operating income of $30 million for the same period in 2019, primarily related to the non-cash impairment of $650 million in the second quarter of 2020 and lower margins associated with reduced commodity prices.

•Total net production of 201 Bcfe, which was comprised of 79% natural gas and 21% oil and NGLs, increased 8% from 186 Bcfe in the same period in 2019, and our liquids production increased 12% over the same period primarily associated with our oil production.

•Excluding the effect of derivatives, our realized natural gas price of $0.98 per Mcf decreased 46%, our realized oil price of $15.69 per barrel decreased 68% and our realized NGL price of $6.43 per barrel decreased 39% as compared to the same period in 2019. Excluding the effect of derivatives, our total weighted average realized price of $1.05 per Mcfe decreased 47% from the same period in 2019.

•E&P segment invested $245 million in capital; drilling 30 wells, completing 31 wells and placing 31 wells to sales.

Outlook

We expect to continue to exercise capital discipline in our 2020 capital investment program, and we remain committed to our focus on optimizing our portfolio by concentrating our efforts on our highest return investment opportunities, looking for ways to 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 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 2019 Annual Report and our Quarterly Report on Form 10-Q for the quarter ended March 31, 2020. During the first half 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 36% since the beginning of 2020. In the first half of 2020, gains on settled derivatives offset a large portion of the impact of the recent decline in prices, and as of July 28, 2020, we currently have derivative positions in place for over 85% of our expected remaining 2020 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 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 half 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. Although we began a phased program of office-based employees returning in early June, we resumed work-from-home later in the month as local case numbers rose. 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

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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.

Beginning late in the first quarter and extending into the second 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 refined products such as gasoline, distillate and 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. Although prices for oil dropped substantially during the first half of 2020, by early in the first quarter we had protected the price of 99% of our expected 2020 oil production through derivatives. In addition, although natural gas prices were not impacted as severely as oil prices, as of June 30, 2020, we have protected the price of approximately 92% of expected remaining 2020 gas production through derivatives.

Late in the second quarter of 2020, certain states and local governments began the measured process of loosening restrictions, allowing businesses to reopen on a limited basis and lifting stay-at-home orders. In addition, OPEC and other countries instituted oil production curtailments. During this same period, oil and NGL prices have improved from historic lows in April due to lower industry-wide production levels and increased export demand, respectively. Further, although the reduced production of natural gas associated with oil wells dampened the effect of lower natural gas demand early in the second quarter, high global natural gas storage inventories and lower LNG demand for U.S. cargoes led to a natural gas price decline late in the second quarter. These situations have increased the risk of U.S. natural gas storage testing capacity constraints toward the end of the summer injection season unless weather and other demand factors are able to balance the excess supply. While we have added natural gas derivatives to mitigate these risks, 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 our currently producing wells. The inability to sell our production for acceptable margins or the decision to potentially reduce our production could materially and adversely affect our operating results.

There continues to be 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. We are continually adjusting our 2020 capital investment program to take into account these changed conditions. If depressed market conditions return, we would proactively continue to adjust our activities and plans. 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.

RESULTS OF OPERATIONS

The following discussion of our results of operations for our segments is presented before intersegment eliminations. We evaluate our segments as if they were stand-alone operations and accordingly discuss their results prior to any intersegment eliminations. Restructuring charges, interest expense, gain (loss) on derivatives, gain on early extinguishment of debt and income taxes are discussed on a consolidated basis.

E&P


	For the three months ended June 30,						For the six months ended June 30,
(in millions)	2020		2019		2020		2019
Revenues	$	211	$	371	$	555	$	913
Operating costs and expenses⁽¹⁾	959		341		2,789		673
Operating income (loss)	$	(748)	$	30	$	(2,234)	$	240

Gain on derivatives, settled ⁽²⁾	$	120	$	34	$	213	$	24

(1)Includes $650 million and $2,129 million related to non-cash full cost ceiling test impairments for the three and six months ended June 30, 2020, respectively, and $5 million related to the non-cash impairment of other non-core assets for the three and six months ended June 30, 2020, respectively.

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

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Operating Income (Loss)

•E&P segment operating income (loss) decreased $778 million for the three months ended June 30, 2020, compared to the same period in 2019, primarily due to a $650 million non-cash full cost ceiling test impairment. Excluding the effect of the impairment, operating income (loss) decreased $128 million compared to the same period in 2019 primarily due to lower margins associated with decreased commodity pricing.

•Operating income (loss) for the E&P segment decreased $2,474 million for the six months ended June 30, 2020, compared to the same period in 2019, primarily due to $2,129 million of non-cash full cost ceiling test impairments. Excluding the impact of the ceiling test impairments, operating income (loss) decreased $345 million compared to the same period in 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 June 30,
(in millions except percentages)	Natural Gas			Oil			NGLs			Total
2019 sales revenues	$	267		$	46		$	58		$	371
Changes associated with prices	(129)			(37)			(25)			(191)
Changes associated with production volumes	17			7			7			31
2020 sales revenues	$	155		$	16		$	40		$	211
Decrease from 2019	(42)		%	(65)		%	(31)		%	(43)		%


	Six months ended June 30,
(in millions except percentages)	Natural Gas			Oil			NGLs			Total
2019 sales revenues ⁽¹⁾	$	688		$	85		$	139		$	912
Changes associated with prices	(348)			(50)			(63)			(461)
Changes associated with production volumes	54			33			14			101
2020 sales revenues ⁽²⁾	$	394		$	68		$	90		$	552
Decrease from 2019	(43)		%	(20)		%	(35)		%	(39)		%

(1)Excludes $1 million in other operating revenues for the six months ended June 30, 2019 primarily related to third-party water sales.

(2)Excludes $3 million in other operating revenues for the six months ended June 30, 2020 primarily related to gains on purchaser imbalances associated with certain NGLs.

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Production Volumes


	For the three months ended June 30,					Increase/(Decrease)			For the six months ended June 30,				Increase/(Decrease)
Production volumes:	2020		2019					2020			2019
Natural Gas (Bcf)
Northeast Appalachia	113		113		—%	227			225			1%
Southwest Appalachia	45		35		29%	87			66			32%

Total	158		148		7%	314			291			8%

Oil (MBbls)
Southwest Appalachia	1,079		931		16%	2,474			1,780			39%
Other	4		6		(33)%	8			11			(27)%
Total	1,083		937		16%	2,482			1,791			39%

NGL (MBbls)
Southwest Appalachia	6,110		5,493		11%	12,237			11,095			10%
Other	1		4		(75)%	2			5			(60)%
Total	6,111		5,497		11%	12,239			11,100			10%

Production volumes by area: (Bcfe)
Northeast Appalachia	113		113		—%	227			225			1%
Southwest Appalachia⁽¹⁾	88		73		21%	175			143			22%

Total	201		186		8%	402			368			9%

Production percentage: (Bcfe)
Natural gas	79	%	79	%		78	%		79	%
Oil	3	%	3	%		4	%		3	%
NGL	18	%	18	%		18	%		18	%

(1)Approximately 87 Bcfe and 73 Bcfe for the three months ended June 30, 2020 and 2019, respectively, and 174 Bcfe and 142 Bcfe for the six months ended June 30, 2020 and 2019, respectively, were produced from the Marcellus Shale formation.

•E&P production volumes increased by 15 Bcfe for the three months ended June 30, 2020 compared to the same period in 2019, primarily due to a 21% increase in production volumes in Southwest Appalachia.

•E&P production volumes increased by 34 Bcfe for the six months ended June 30, 2020 compared to the same period in 2019, primarily due to a 22% increase in production volumes in Southwest Appalachia.

•Oil and NGL production increased 16% and 11%, respectively, for the three months ended June 30, 2020, compared to the same period in 2019.

•Oil and NGL production increased 39% and 10%, respectively, for the six months ended June 30, 2020, compared to the same period in 2019.

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.

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	For the three months ended June 30,							Increase/(Decrease)				For the six months ended June 30,					Increase/(Decrease)
	2020			2019							2020				2019
Natural Gas Price:
NYMEX Henry Hub Price ($/MMBtu) ⁽¹⁾	$	1.72		$	2.64		(35)%	$	1.83			$	2.89			(37)%
Discount to NYMEX ⁽²⁾	(0.74)			(0.84)			(12)%	(0.57)				(0.52)				10%
Average realized gas price, excluding derivatives ($/Mcf)	$	0.98		$	1.80		(46)%	$	1.26			$	2.37			(47)%
Gain (loss) on settled financial basis derivatives ($/Mcf)	(0.05)			(0.03)				0.03				(0.03)
Gain (loss) on settled commodity derivatives ($/Mcf)	0.57			0.17				0.43				0.04
Average realized gas price, including derivatives ($/Mcf)	$	1.50		$	1.94		(23)%	$	1.72			$	2.38			(28)%

Oil Price:
WTI oil price ($/Bbl)	$	27.85		$	59.81		(53)%	$	37.01			$	57.36			(35)%
Discount to WTI	(12.16)			(10.26)			19%	(9.46)				(9.75)				(3)%
Average oil price, excluding derivatives ($/Bbl)	$	15.69		$	49.55		(68)%	$	27.55			$	47.61			(42)%
Gain on settled derivatives ($/Bbl)	25.95			2.05				16.53				2.19
Average oil price, including derivatives ($/Bbl)	$	41.64		$	51.60		(19)%	$	44.08			$	49.80			(11)%

NGL Price:
Average realized NGL price, excluding derivatives ($/Bbl)	$	6.43		$	10.51		(39)%	$	7.29			$	12.50			(42)%
Gain on settled derivatives ($/Bbl)	1.79			2.11				2.21				1.34
Average realized NGL price, including derivatives ($/Bbl)	$	8.22		$	12.62		(35)%	$	9.50			$	13.84			(31)%
Percentage of WTI, excluding derivatives	23		%	18		%		20		%		22		%

Total Weighted Average Realized Price:
Excluding derivatives ($/Mcfe)	$	1.05		$	1.99		(47)%	$	1.37			$	2.48			(45)%
Including derivatives ($/Mcfe)	$	1.65		$	2.17		(24)%	$	1.90			$	2.54			(25)%

(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 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 7 to the consolidated financial statements, included in this Quarterly Report.

The table below presents the amount of our future production in which the basis is protected as of June 30, 2020:


	Volume (Bcf)	Basis Differential
Basis Swaps – Natural Gas
2020	145	$	(0.44)
2021	150	(0.14)
2022	122	(0.46)
Total	417

Physical NYMEX Sales Arrangements – Natural Gas
2020	142	$	(0.26)
2021	130	(0.26)
Total	272

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


	Remaining 2020	Full Year 2021	Full Year 2022
Natural gas (Bcf)	321	397	128
Oil (MBbls)	2,504	3,773	1,104
Ethane (MBbls)	5,230	5,889	136
Propane (MBbls)	2,932	4,298	105
Total financial protection on future production (Bcfe)	385	481	136

We refer you to Note 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 June 30,					Increase/(Decrease)			For the six months ended June 30,				Increase/(Decrease)
(in millions except percentages)	2020		2019					2020			2019
Lease operating expenses	$	182	$	169	8%	$	376		$	335		12%
General & administrative expenses	29		35		(17)%	52			69			(25)%

Restructuring charges	2		2		—%	12			5			140%
Taxes, other than income taxes	10		17		(41)%	23			36			(36)%
Full cost pool amortization	77		102		(25)%	183			205			(11)%
Non-full cost pool DD&A	4		10		(60)%	9			17			(47)%
Impairments	655		6		10,817%	2,134			6			35,467%
Total operating costs	$	959	$	341	181%	$	2,789		$	673		314%


	For the three months ended June 30,							Increase/			For the six months ended June 30,				Increase/
Average unit costs per Mcfe:	2020			2019			(Decrease)	2020			2019			(Decrease)
Lease operating expenses ⁽¹⁾	$	0.91		$	0.90		1%	$	0.94		$	0.90		4%
General & administrative expenses	$	0.14	⁽²⁾	$	0.19	⁽³⁾	(26)%	$	0.13	⁽²⁾	$	0.19	⁽³⁾	(32)%
Taxes, other than income taxes	$	0.05		$	0.09		(44)%	$	0.06		$	0.10		(40)%
Full cost pool amortization	$	0.38		$	0.55		(31)%	$	0.46		$	0.56		(18)%

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

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

(3)Excludes $2 million and $5 million of restructuring charges for the three and six months ended June 30, 2019, respectively.

Lease Operating Expenses

•Lease operating expenses per Mcfe increased $0.01 for the three months ended June 30, 2020, compared to the same period of 2019, primarily due to increased compression costs in Northeast Appalachia.

•Lease operating expenses per Mcfe increased $0.04 for the six months ended June 30, 2020, compared to the same period of 2019, due to a $0.03 per Mcfe increase related to increased compression costs and a $0.01 per Mcfe increase related to a shift towards liquids production, which includes processing fees.

General and Administrative Expenses

•General and administrative expenses decreased $6 million and $17 million for the three and six months ended June 30, 2020, respectively, compared to the same periods in 2019, primarily due to decreased personnel costs and the implementation of cost reduction initiatives.

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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 $0.04 for the three and six months ended June 30, 2020, compared to the same periods of 2019, respectively, primarily due to lower commodity pricing and lower effective severance tax rates in Southwest Appalachia.

Full Cost Pool Amortization

•Our full cost pool amortization rate decreased $0.17 and $0.10 per Mcfe for the three and six months ended June 30, 2020, respectively, as compared to the same periods 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. Additionally, in the second quarter of 2020, the full cost pool amortization rate decreased due to the $1,479 million non-cash full cost ceiling test impairment from the first quarter of 2020.

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

•Unevaluated costs excluded from amortization were $1.4 billion at June 30, 2020, compared to $1.5 billion at December 31, 2019. The unevaluated costs excluded from amortization decreased as the impact of $55 million of unevaluated capital invested during the period was more than offset by the evaluation of previously unevaluated properties totaling $138 million.

Impairments

•For the three and six months ended June 30, 2020, we recognized non-cash full cost ceiling test impairments of $650 million and $2,129 million, respectively, primarily due to decreased commodity pricing over the prior twelve months. Additionally, for the three and six months ended June 30, 2020, we recognized a $5 million impairment related to other non-core assets.

•During the three and six months ended June 30, 2019, we recognized a $6 million impairment to non-core gathering assets.

Marketing


	For the three months ended June 30,							Increase/ (Decrease)				For the six months ended June 30,					Increase/ (Decrease)
(in millions except percentages)	2020			2019							2020				2019
Marketing revenues	$	389		$	626		(38)%	$	937			$	1,566			(40)%
Other operating revenues	—			—			—%	—				1				(100)%
Marketing purchases	391			622			(37)%	938				1,556				(40)%
Operating costs and expenses	6			9			(33)%	11				13				(15)%

Loss on sale of operating assets	—			3			(100)%	—				3				(100)%
Operating loss	$	(8)		$	(8)		—%	$	(12)			$	(5)			140%

Volumes marketed (Bcfe)	265			255			4%	528				544				(3)%

Percent natural gas production marketed from affiliated E&P operations	87		%	83		%		87		%		75		%
Percent oil and NGL production marketed from affiliated E&P operations	83		%	76		%		80		%		75		%

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Operating Income (Loss)

•Marketing operating income (loss) remained flat for the three months ended June 30, 2020, compared to the same period in 2019, as a $6 million decrease in the marketing margin in the second quarter was offset by a $3 million reduction in operating costs and expenses and a $3 million loss on the sale of operating assets in the second quarter of 2019.

•Marketing operating income (loss) decreased $7 million for the six months ended June 30, 2020, compared to the same period in 2019, primarily due to an $11 million decrease in the marketing margin, partially offset by a $2 million reduction in operating costs and expenses. In addition, marketing operating income for the second quarter of 2019 included a $3 million loss 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 ($2) million and $4 million for the three months ended June 30, 2020 and 2019, respectively, and ($1) million and $10 million for the six months ended June 30, 2020 and 2019, respectively. The decrease in marketing margin in 2020, compared to the same periods 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

•Revenues from our marketing activities decreased $237 million for the three months ended June 30, 2020 compared to the same period in 2019, as a 40% decrease in the price received for volumes marketed was only partially offset by a 10 Bcfe increase in volumes marketed.

•For the six months ended June 30, 2020, revenues from our marketing activities decreased $629 million compared to the same period in 2019, primarily due to a 38% decrease in the price received for volumes marketed and a 16 Bcfe decrease in volumes marketed.

Operating Costs and Expenses

•Operating costs and expenses for the marketing segment decreased $3 million and $2 million for the three and six months ended June 30, 2020, respectively, compared to the same periods in 2019 primarily due to decreased personnel costs and the implementation of cost reduction initiatives.

Consolidated

Restructuring Charges

In February 2020, employees were notified of a workforce reduction plan as a result of a strategic realignment of our organizational structure. Affected employees were offered a severance package, which included a one-time cash payment depending on length of service and, if applicable, the current value of unvested long-term incentive awards that were forfeited. We recognized restructuring expense of $2 million and $12 million for the three and six months ended June 30, 2020, respectively, related to cash severance, including payroll taxes.

In the second quarter of 2019, we recognized $2 million in restructuring charges consisting of cash severance payments and office consolidation expenses related to the Fayetteville Shale sale, which closed in December 2018. For the six months ended June 30, 2019, we recognized total restructuring charges of $5 million, of which $3 million was related to cash severance, including payroll taxes withheld, and $2 million primarily related to office consolidation related to the 2018 Fayetteville Shale sale. We refer you to Note 2 to the consolidated financial statements included in this Quarterly Report for additional details about our restructuring charges.

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Interest Expense


	For the three months ended June 30,					Increase/(Decrease)			For the six months ended June 30,				Increase/(Decrease)
(in millions except percentages)	2020		2019					2020			2019
Gross interest expense:
Senior notes	$	36	$	39	(8)%	$	73		$	78		(6)%
Credit arrangements	4		2		100%	7			5			40%
Amortization of debt costs	3		2		50%	5			3			67%
Total gross interest expense	43		43		—%	85			86			(1)%
Less: capitalization	(21)		(28)		(25)%	(44)			(57)			(23)%
Net interest expense	$	22	$	15	47%	$	41		$	29		41%

•Interest expense related to our senior notes decreased for the three and six months ended June 30, 2020, compared to the same periods of 2019, as we repurchased $107 million and $114 million of our outstanding senior notes during the first half of 2020 and the last half of 2019, respectively.

•Capitalized interest decreased for the three and six months ended June 30, 2020, respectively, compared to the same periods in 2019, due to the evaluation of natural gas and oil properties over the past twelve months.

•Capitalized interest decreased as a percentage of gross interest expense for the three and six months ended June 30, 2020, compared to the same periods in 2019, primarily related to a larger percentage decrease in our unevaluated natural gas and oil properties balance as compared to the smaller percentage decrease in our gross interest expense over the same period.

Gain (Loss) on Derivatives


	For the three months ended June 30,						For the six months ended June 30,
(in millions)	2020		2019		2020		2019
Gain (loss) on unsettled derivatives	$	(229)	$	118	$	17	$	96
Gain on settled derivatives	120		34		213		24
Gain (loss) on derivatives	$	(109)	$	152	$	230	$	120

We refer you to Note 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 six months ended June 30, 2020, we recorded a gain on early extinguishment of debt of $35 million as a result of our repurchase of $107 million in aggregate principal amount of our outstanding senior notes for $72 million. In the second quarter of 2020, we repurchased $27 million in aggregate principal of our outstanding senior notes for $20 million, resulting in a gain on early extinguishment of debt of $7 million. See Note 10 to the consolidated financial statements of this Quarterly Report for more information on our long-term debt.

Income Taxes


	For the three months ended June 30,									For the six months ended June 30,
(in millions except percentages)	2020			2019			2020			2019
Income tax (benefit) expense	$	—		$	15		$	406		$	(411)
Effective tax rate	0		%	10		%	(20)		%	(128)		%

•As of the first quarter of 2019, we had sustained a three-year cumulative level of profitability. Based on this factor and other positive evidence including forecasted income, we concluded that it was more likely than not that the deferred tax asset would be realized and released substantially all of the valuation allowance. This resulted in a discrete tax benefit of $411 million being recorded in the first half of 2019. However, due to commodity price declines during the first half of 2020 and the write-down of the carrying value of our natural gas and oil properties, 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 expense of $408 million for the increase in our valuation allowance in the first quarter of 2020. The net change in valuation allowance is reflected as a component of income tax expense. We also continue to retain a valuation allowance of $87 million related to net operating losses in jurisdictions in which we no longer operate.

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New Accounting Standards Implemented in this Report

Refer to Note 16 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 16 to the consolidated financial statements of this Quarterly Report for a discussion of new accounting standards which have not yet been implemented.

LIQUIDITY AND CAPITAL RESOURCES

We depend primarily on funds generated from our operations, our 2018 credit facility, our cash and cash equivalents balance and capital markets as our primary sources of liquidity. On April 13, 2020, the banks participating in our 2018 credit facility redetermined our borrowing base to be $1.8 billion, which also changed our aggregate commitments to that amount. As of July 28, 2020, we had approximately $1.3 billion of total available liquidity, which exceeds our currently modeled needs, and we remain committed to our strategy of 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 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 the first half of 2020, gains on derivatives have offset a large portion of the impact of lower commodity prices, and as of July 28, 2020, we currently have derivative positions in place for over 85% of our expected remaining 2020 production, including over 90% of our 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” in Item 3 in Part I and Note 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 owners 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.

Credit Arrangements and Financing Activities

In April 2018, we replaced our credit facility entered into in 2016 with a new revolving credit facility (the “2018 credit facility”) with a group of banks that, as amended, has a maturity date of April 2024. The 2018 credit facility has an aggregate maximum revolving credit amount of $3.5 billion and, 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 borrowing base is subject to redetermination at least twice a year, in April and October, and is subject to change based primarily on drilling results, commodity prices, our future derivative position, the level of capital investment and operating costs. The 2018 credit facility is secured by substantially all of our assets, 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 or 25% of adjusted consolidated net tangible assets. We may utilize the 2018 credit facility in the form of loans and letters of credit. As of June 30, 2020, we had $336 million borrowings outstanding on our 2018 credit facility and $209 million in outstanding

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letters of credit. We currently do not anticipate being required to supply a materially greater amount of letters of credit under our existing contracts.

As of June 30, 2020, we were in compliance with all of the covenants contained in the credit agreement governing our revolving credit facility. As a result of improving market conditions as evidenced by oil and NGL pricing and management actions, current modeling no longer indicates that we will be in non-compliance with any covenants under our 2018 credit facility in late 2020. Our ability to comply with financial covenants in future periods depends, among other things, on the success of our development program and upon other factors beyond our control, such as the market demand, prices for natural gas and liquids and the effects of the aforementioned COVID-19 pandemic. We refer you to the Outlook section of Management’s Discussion and Analysis of Financial Condition and Results of Operations above for additional discussion related to economic conditions associated with the COVID-19 pandemic and to Note 10 of the consolidated financial statements for additional discussion of the covenant requirements of our 2018 credit facility, both of which are included in this Quarterly Report.

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

Our exposure to the anticipated transition from LIBOR in late 2021 is limited to the 2018 credit facility. Upon announcement by the administrator of LIBOR identifying a specific date for LIBOR cessation, the credit agreement governing the 2018 credit facility will be amended to reference an alternative rate as established by JP Morgan, as Administrative Agent, and Southwestern. The alternative rate will be based on the prevailing market convention and is expected to be SOFR.

During the first six months of 2020, we repurchased $6 million of our 4.10% Senior Notes due 2022, $36 million of our 4.95% Senior Notes due 2025, $21 million of our 7.50% Senior Notes due 2026 and $44 million of our 7.75% Senior Notes due 2027 for $72 million, and recognized a $35 million gain on the extinguishment of debt.

In the second half of 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 the last three years, only $207 million of our senior notes outstanding as of June 30, 2020 is scheduled to become due prior to 2025.

At July 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 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 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.

Cash Flows


	For the six months ended June 30,
(in millions)	2020		2019
Net cash provided by operating activities	$	254	$	543
Net cash used in investing activities	(470)		(560)
Net cash provided by (used in) financing activities	221		(29)

Cash Flow from Operating Activities


	For the six months ended June 30,
(in millions)	2020		2019
Net cash provided by operating activities	$	254	$	543
Add back (subtract) changes in working capital	12		(66)
Net cash provided by operating activities, net of changes in working capital	$	266	$	477

•Net cash provided by operating activities decreased 53%, or $289 million, for the six months ended June 30, 2020, compared to the same period in 2019, due to a $461 million decrease resulting from lower commodity prices, a $78 million decreased impact of working capital, a $17 million increase in operating costs, a $14 million decrease in marketing margin

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and a $13 million decrease in capitalized interest expense. These decreases were partially offset by a $189 million increase in our settled derivatives and a $101 million increase associated with increased production.

•Net cash generated from operating activities, net of changes in working capital, provided 55% of our cash requirements for capital investments for the six months ended June 30, 2020, compared to providing 69% of our cash requirements for capital investments for the same period in 2019. Consistent with past years, our capital program for 2020 is weighted to the first half of the year. We remain committed to our disciplined capital strategy.

Cash Flow from Investing Activities

•Total capital investments decreased $123 million for the three months ended June 30, 2020, compared to the same period in 2019, primarily due to a $109 million decrease in direct E&P capital investments and a $13 million decrease in capitalized interest and internal costs.

•Total capital investments decreased $211 million for the six months ended June 30, 2020, compared to the same period in 2019, due to a $184 million decrease in direct E&P capital investments and a $26 million decrease in capitalized interest and internal costs, as compared to the same period in 2019.


	For the six months ended June 30,
(in millions)	2020		2019
Additions to properties and equipment	$	472	$	586
Adjustments for capital investments
Changes in capital accruals	8		105
Other ⁽¹⁾	2		2
Total capital investment	$	482	$	693

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

Capital Investment


	For the three months ended June 30,					Increase/(Decrease)			For the six months ended June 30,				Increase/(Decrease)
(in millions except percentages)	2020		2019					2020			2019
E&P capital investment	$	245	$	367	(33)%	$	482		$	692		(30)%
Other capital investment⁽¹⁾	—		1		(100)%	—			1			(100)%
Total capital investment	$	245	$	368	(33)%	$	482		$	693		(30)%

(1)Other capital investment was immaterial for the three and six months ended June 30, 2020 and 2019.


	For the three months ended June 30,						For the six months ended June 30,
(in millions)	2020		2019		2020		2019
E&P Capital Investments by Type:
Exploratory and development drilling, including workovers	$	197	$	284	$	387	$	535
Acquisitions of properties	8		16		14		23
Seismic expenditures	—		1		—		2
Water infrastructure project	2		11		3		26
Other	5		9		9		11
Capitalized interest and expenses	33		46		69		95
Total E&P capital investments	$	245	$	367	$	482	$	692

E&P Capital Investments by Area:
Northeast Appalachia	$	115	$	126	$	201	$	232
Southwest Appalachia	123		223		269		421
Other E&P ⁽¹⁾	7		18		12		39
Total E&P capital investments	$	245	$	367	$	482	$	692

(1)Includes $2 million and $11 million for the three months ended June 30, 2020 and 2019, respectively, and $3 million and $26 million for the six months ended June 30, 2020 and 2019, respectively, related to our water infrastructure project.

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	For the three months ended June 30,			For the six months ended June 30,
	2020	2019	2020	2019
Gross Operated Well Count Summary:
Drilled	30	41	68	71
Completed	31	40	53	71
Wells to sales	31	36	43	55

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 the first half of 2020, we repurchased $107 million in aggregate principal amount of our outstanding senior notes at a discount for $72 million, and recognized a $35 million gain on the extinguishment of debt.

We refer you to Note 10 of the consolidated financial statements included in this Quarterly Report for additional discussion of our outstanding debt and credit facilities.

Working Capital

•We had negative working capital of $105 million at June 30, 2020, a $64 million improvement from December 31, 2019, as a $31 million positive change in the current mark-to-market value of our derivative position, a $99 million decrease in accounts payable, a $16 million decrease in a firm transportation liability and an $11 million decrease in taxes payable, as compared to December 31, 2019, were only partially offset by a $95 million decrease in accounts receivable, as compared to December 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 June 30, 2020, our material off-balance sheet arrangements and transactions include operating service arrangements, $209 million in letters of credit outstanding against our 2018 credit facility and $159 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 regarding off-balance sheet arrangements, we refer you to “Contractual Obligations and Contingent Liabilities and Commitments” in our 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 2019 Annual Report.

Contingent Liabilities and Commitments

As of June 30, 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 $7.3 billion, $402 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 $1.0 billion. As of June 30, 2020, future payments under non-cancelable firm transportation and gathering agreements are as follows:


	Payments Due by Period
(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	$	6,947	$	667	$	1,323	$	1,091	$	1,462	$	2,404
Pending regulatory approval and/or construction ⁽¹⁾	402		2		17		22		65		296
Total transportation charges	$	7,349	$	669	$	1,340	$	1,113	$	1,527	$	2,700

(1)Based on the estimated in-service dates as of June 30, 2020.

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Included in the transportation charges above are $54 million (due in less than one year) related to certain agreements that remain in the name of our marketing affiliate but are expected to be paid in full by the purchaser of the Fayetteville Shale assets. Of these amounts, we may be obligated to reimburse the purchaser for a portion of volumetric shortfalls during 2020 (up to $27 million) under these transportation agreements and have currently recorded a $21 million liability as of June 30, 2020, down from $46 million recorded at December 31, 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.

In February 2020, we were notified that the proposed Constitution pipeline project was cancelled and that we were released from a firm transportation agreement with its sponsor. Prior to its cancellation, we had contractual commitments totaling $512 million over the next 17 years related to the Constitution pipeline project.

Substantially all of our employees are covered by defined benefit and postretirement benefit plans. For the six months ended June 30, 2020, we have contributed $9 million to the pension and postretirement benefit plans, and we expect to further contribute an additional $3 million to our pension plan during the remainder of 2020. We recognized liabilities of $38 million and $43 million as of June 30, 2020 and December 31, 2019, respectively, as a result of the underfunded status of our pension and other postretirement benefit plans. See Note 13 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.

For further information, we refer you to “Litigation” and “Environmental Risk” in Note 11 to the consolidated financial statements included in Item 1 of Part I of this Quarterly Report.

Supplemental Guarantor Financial Information

As discussed in Note 10, 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.

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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. However, at June 30, 2020, one purchaser accounted for 11% 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. 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 June 30, 2020, we had approximately $2.1 billion of outstanding senior notes with a weighted average interest rate of 6.70%, and we had $336 million in borrowings under our revolving credit facility. At June 30, 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.


	Expected Maturity Date
($ in millions)	2021			2022			2023			2024			2025			Thereafter			Total
Fixed rate payments ⁽¹⁾	$	—		$	207		$	—		$	—		$	856		$	1,058		$	2,121
Weighted average interest rate	—		%	4.10		%	—		%	—		%	6.20		%	7.60		%	6.70		%

Variable rate payments ⁽¹⁾	$	—		$	—		$	—		$	336		$	—		$	—		$	336
Weighted average interest rate	—		%	—		%	—		%	1.86		%	—		%	—		%	1.86		%

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

Commodities Risk

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

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

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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 June 30, 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 June 30, 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 11 to the consolidated financial statements included in Item 1 of Part I of this Quarterly Report for a discussion of the Company’s legal proceedings.

ITEM 1A. RISK FACTORS

There were no additions or material changes to our risk factors as disclosed in Item 1A of Part I in the Company’s 2019 Annual Report and Item 1A of Part II in the Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2020.

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.

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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 (I ncorporated by reference to Exhibit 3.2 to the R egistrant's Quarterly Report on Form 10-Q filed April 30, 2020)
(10.1)			Retirement and Consulting Agreement dated as of June 4, 2020 by and between Southwestern Energy Company and John C. Ale (Incorporated by reference to Exhibit 10.1 to the Registrant’s Current Report on Form 8-K filed June 4, 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:	July 30, 2020	/s/ JULIAN M. BOTT
		Julian M. Bott Executive Vice President and Chief Financial Officer

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