SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

~~[X]~~☒ Quarterly Report pursuant to Section 13 or 15(d) of the Securities

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

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.

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:

SOUTHWESTERN ENERGY COMPANY

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

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.

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

You should not place undue reliance on forward-looking statements. They are subject to known and unknown risks, uncertainties and other factors that may affect our operations, markets, products, services and prices and cause our actual results, performance or achievements to be materially different from any future results, performance or achievements expressed or implied by the forward-looking statements. In addition to any assumptions and other factors referred to specifically in connection with forward-looking statements, risks, uncertainties and factors that could cause our actual results to differ materially from those indicated in any forward-looking statement include, but are not limited to:

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

•our ability to fund our planned capital investments;

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

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

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

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

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

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

•our ability to realize the expected benefits from acquisitions;

•our ability to transport our production to the most favorable markets or at all;

•availability and costs of personnel and of products and services provided by third parties;

•the impact of government regulation, including changes in law, the ability to obtain and maintain permits, any increase in severance or similar taxes, and legislation or regulation relating to hydraulic fracturing, climate and over-the-counter derivatives;

•the impact of the adverse outcome of any material litigation against us or judicial decisions that affect us or our industry generally;

•the effects of weather;

•increased competition;

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

•the comparative cost of alternative fuels;

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

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

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

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

PART I – FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

SOUTHWESTERN ENERGY COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS


	For the three months ended March 31,
(in millions, except share/per share amounts)	2020		2019
Operating Revenues:
Gas sales	$	248	$	430
Oil sales	52		39
NGL sales	50		81
Marketing	239		438
Other	3		2
	592		990
Operating Costs and Expenses:
Marketing purchases	248		441
Operating expenses	193		165
General and administrative expenses	26		37

Restructuring charges	10		3
Depreciation, depletion and amortization	113		112
Impairments	1,479		—
Taxes, other than income taxes	13		19
	2,082		777
Operating Income (Loss)	(1,490)		213
Interest Expense:
Interest on debt	40		42
Other interest charges	2		1
Interest capitalized	(23)		(29)
	19		14

Gain (Loss) on Derivatives	339		(32)
Gain on Early Extinguishment of Debt	28		—
Other Income, Net	1		1

Income (Loss) Before Income Taxes	(1,141)		168
Provision (Benefit) for Income Taxes:
Current	(2)		—
Deferred	408		(426)
	406		(426)
Net Income (Loss)	$	(1,547)	$	594


Earnings (Loss) Per Common Share:
Basic	$	(2.86)	$	1.10
Diluted	$	(2.86)	$	1.10

Weighted Average Common Shares Outstanding:
Basic	540,308,491		539,721,751
Diluted	540,308,491		541,320,487

For the three months ended
March 31,
(in millions, except share/per share amounts) 2019 2018
Operating Revenues:
Gas sales $ 430
$ 540
Oil sales 39
35
NGL sales 81
65
Marketing 438
253
Gas gathering —
24
Other 2
3
990
920
Operating Costs and Expenses:
Marketing purchases 441
255
Operating expenses 165
189
General and administrative expenses 37
55
Restructuring charges 3
—
Depreciation, depletion and amortization 112
143
Taxes, other than income taxes 19
23
777
665
Operating Income 213
255
Interest Expense:
Interest on debt 42
65
Other interest charges 1
2
Interest capitalized (29 ) (28 )
14
39

Loss on Derivatives (32 ) (7 )
Other Income (Loss), Net 1
(1 )

Income Before Income Taxes 168
208
Benefit from Income Taxes:
Current —
—
Deferred (426 ) —
(426 ) —
Net Income $ 594
$ 208
Participating securities - mandatory convertible preferred stock —
3
Net Income Attributable to Common Stock $ 594
$ 205

Earnings Per Common Share:
Basic $ 1.10
$ 0.36
Diluted $ 1.10
$ 0.36

Weighted Average Common Shares Outstanding:
Basic 539,721,751
571,297,804
Diluted 541,320,487
573,844,459

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

SOUTHWESTERN ENERGY COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME


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

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

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

For the three months ended
March 31,
(in millions) 2019 2018
Net income $ 594
$ 208

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

Comprehensive income $ 594
$ 208

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

SOUTHWESTERN ENERGY COMPANY AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS


	March 31, 2020		December 31, 2019

ASSETS	(in millions)
Current assets:
Cash and cash equivalents	$	5	$	5
Accounts receivable, net	292		345
Derivative assets	627		278
Other current assets	48		51
Total current assets	972		679
Natural gas and oil properties, using the full cost method, including $1,437 million as of March 31, 2020 and $1,506 million as of December 31, 2019 excluded from amortization	25,488		25,250

Other	523		520
Less: Accumulated depreciation, depletion and amortization	(22,095)		(20,503)
Total property and equipment, net	3,916		5,267
Operating lease assets	152		159
Deferred tax assets	—		407
Other long-term assets	235		205
Total long-term assets	387		771
TOTAL ASSETS	$	5,275	$	6,717
LIABILITIES AND EQUITY
Current liabilities:

Accounts payable	$	465	$	525
Taxes payable	52		59
Interest payable	54		51

Derivative liabilities	268		125
Current operating lease liabilities	32		34
Other current liabilities	43		54
Total current liabilities	914		848
Long-term debt	2,279		2,242
Long-term operating lease liabilities	114		119
Pension and other postretirement liabilities	40		43
Other long-term liabilities	227		219
Total long-term liabilities	2,660		2,623
Commitments and contingencies (Note 11)
Equity:
Common stock, $0.01 par value; 1,250,000,000 shares authorized; issued 586,023,435 shares as of March 31, 2020 and 585,555,923 shares as of December 31, 2019	6		6

Additional paid-in capital	4,728		4,726
Accumulated deficit	(2,798)		(1,251)
Accumulated other comprehensive loss	(33)		(33)
Common stock in treasury, 44,353,224 shares as of March 31, 2020 and December 31, 2019	(202)		(202)
Total equity	1,701		3,246
TOTAL LIABILITIES AND EQUITY	$	5,275	$	6,717

March 31, 2019 December 31, 2018
ASSETS (in millions)
Current assets:
Cash and cash equivalents $ 366
$ 201
Accounts receivable, net 390
581
Derivative assets 87
130
Other current assets 44
44
Total current assets 887
956
Natural gas and oil properties, using the full cost method, including $1,673 million as of March 31, 2019 and $1,755 million as of December 31, 2018 excluded from amortization 24,486
24,180
Gathering systems 38
38
Other 509
487
Less: Accumulated depreciation, depletion and amortization (20,162 ) (20,049 )
Total property and equipment, net 4,871
4,656
Deferred tax assets 426
—
Other long-term assets 262
185
TOTAL ASSETS $ 6,446
$ 5,797
LIABILITIES AND EQUITY
Current liabilities:
Current portion of long-term debt $ 52
$ —
Accounts payable 626
609
Taxes payable 62
58
Interest payable 58
52
Derivative liabilities 50
79
Other current liabilities 95
48
Total current liabilities 943
846
Long-term debt 2,267
2,318
Pension and other postretirement liabilities 43
46
Other long-term liabilities 256
225
Total long-term liabilities 2,566
2,589
Commitments and contingencies (Note 13)

Equity:
Common stock, $0.01 par value; 1,250,000,000 shares authorized; issued 585,548,726 shares as of March 31, 2019 and 585,407,107 as of December 31, 2018 6
6
Additional paid-in capital 4,717
4,715
Accumulated deficit (1,548 ) (2,142 )
Accumulated other comprehensive loss (36 ) (36 )
Common stock in treasury, 44,353,224 shares as of March 31, 2019 and 39,092,537 shares as of December 31, 2018 (202 ) (181 )
Total equity 2,937
2,362
TOTAL LIABILITIES AND EQUITY $ 6,446
$ 5,797

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

SOUTHWESTERN ENERGY COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS


	For the three months ended March 31,
(in millions)	2020		2019
Cash Flows From Operating Activities:
Net income (loss)	$	(1,547)	$	594
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization	113		112
Amortization of debt issuance costs	1		1
Impairments	1,479		—
Deferred income taxes	408		(426)
(Gain) loss on derivatives, unsettled	(246)		22
Stock-based compensation	1		2
Gain on early extinguishment of debt	(28)		—

Other	—		1
Change in assets and liabilities:
Accounts receivable	53		189
Accounts payable	(86)		(48)
Taxes payable	(6)		4
Interest payable	1		2
Inventories	8		5
Other assets and liabilities	9		(16)
Net cash provided by operating activities	160		442

Cash Flows From Investing Activities:
Capital investments	(228)		(258)


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

Cash Flows From Financing Activities:

Payments on long-term debt	(52)		—
Payments on revolving credit facility	(500)		—
Borrowings under revolving credit facility	615		—
Change in bank drafts outstanding	5		3


Purchase of treasury stock	—		(21)

Cash paid for tax withholding	—		(1)

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

Increase in cash and cash equivalents	—		165
Cash and cash equivalents at beginning of year	5		201
Cash and cash equivalents at end of period	$	5	$	366

For the three months ended
March 31,
(in millions) 2019 2018
Cash Flows From Operating Activities:
Net income $ 594
$ 208
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization 112
143
Amortization of debt issuance costs 1
2
Deferred income taxes (426 ) —
(Gain) loss on derivatives, unsettled 22
(2 )
Stock-based compensation 2
4
Other 1
3
Change in assets and liabilities:
Accounts receivable 189
46
Accounts payable (48 ) (17 )
Taxes payable 4
(12 )
Interest payable 2
(4 )
Other assets and liabilities (11 ) (7 )
Net cash provided by operating activities 442
364

Cash Flows From Investing Activities:
Capital investments (258 ) (302 )
Proceeds from sale of property and equipment —
6
Other —
2
Net cash used in investing activities (258 ) (294 )

Cash Flows From Financing Activities:
Change in bank drafts outstanding 3
—
Purchase of treasury stock (21 ) —
Preferred stock dividend —
(27 )
Cash paid for tax withholding (1 ) (1 )
Net cash used in financing activities (19 ) (28 )

Increase in cash and cash equivalents 165
42
Cash and cash equivalents at beginning of year 201
916
Cash and cash equivalents at end of period $ 366
$ 958

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

SOUTHWESTERN ENERGY COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY


	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
Treasury stock	—	—		—		—		—		—	—			—
Performance units vested	—	—		—		—		—		—	—			—
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

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


	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

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

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 (“~~Midstream”~~Marketing”)., which was previously referred to as “Midstream” when it included the operation of gathering systems. Southwestern conducts most of its business through subsidiaries and operates principally in ~~two~~2 segments: E&P and Midstream. The Company also has drilling rigs located in Pennsylvania and West Virginia and provides oilfield products and services, principally serving its E&P operations. The Company’s historical financial and operating results include its Fayetteville Shale E&P and related midstream gathering businesses which were sold in early December 2018 (the “Fayetteville Shale sale”). The sale is discussed in further detail in ~~Note 2~~.Marketing.

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

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

The accompanying consolidated financial statements were prepared using accounting principles generally accepted in the United States of America (“GAAP”) for interim financial information and in accordance with the rules and regulations of the Securities and Exchange Commission. Certain information relating to the Company’s organization and footnote disclosures normally included in financial statements prepared in accordance with GAAP have been appropriately condensed or omitted in this Quarterly Report. The Company believes the disclosures made are adequate to make the information presented not misleading.

The consolidated financial statements contained in this report include all normal and recurring material adjustments that, in the opinion of management, are necessary for a fair statement of the financial position, results of operations and cash flows for the interim periods presented herein. It is recommended that these consolidated financial statements be read in conjunction with the consolidated financial statements and the notes thereto included in the Company’s Annual Report on Form 10-K for the year ended December 31, ~~2018~~2019 (“~~2018~~2019 Annual Report”).

The Company’s significant accounting policies, which have been reviewed and approved by the Audit Committee of the Company’s Board of Directors, are summarized in Note 1 in the Notes to the Consolidated Financial Statements included in the Company’s ~~2018~~2019 Annual Report.

(2) ~~DIVESTITURES~~RESTRUCTURING CHARGES

On ~~August 30, 2018,~~February 4, 2020, the Company ~~entered into an agreement with Flywheel Energy Operating, LLC to sell 100%~~notified employees of the equity in the Company’s subsidiaries that owned and operated its Fayetteville Shale E&P and related midstream gathering assets for $1,865 million in cash, subject to customary closing adjustments, with an economic effective datea workforce reduction plan as a result of July 1, 2018. On December 3, 2018, the Company closed on the Fayetteville Shale sale and received approximately $1,650 million, which included preliminary purchase price adjustments of approximately $215 million primarily related to the net cash flows from the economic effective date to the closing date.

The Company retained certain contractual commitments related to firm transportation, with the buyer obligated to pay the transportation provider directly for these charges. As of March 31, 2019, approximately $188 million of these contractual commitments remain of which the Company will reimburse the buyer for certain of these potential obligations up to approximately $94 million through 2020 depending on the buyer’s actual use. At March 31, 2019, the Company has recorded a ~~$78 million liability for the estimated future payments.~~

~~From the proceeds received, $914 million was used to repurchase $900 million~~strategic realignment of the Company’s ~~outstanding senior notes, including premiums and $9 million in accrued interest paid in December 2018. In addition, $201 million, including approximately $1 million in commissions,~~organizational structure. This reduction was ~~used to repurchase approximately 44 million shares~~substantially complete by the end of the ~~Company’s outstanding common stock, including $21 million during~~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 months ended March 31, ~~2019. The Company intends~~2020, and a liability of approximately $0.3 million has been accrued as of March 31, 2020 related to ~~use~~future payments associated with the ~~remaining net proceeds from the sale to supplement Appalachian Basin development and for general corporate purposes.~~

~~(3) RESTRUCTURING CHARGES~~February 2020 restructuring.

In December 2018, the Company closed on the sale of the equity in certain of its subsidiaries that owned and operated its Fayetteville Shale E&P and related midstream gathering assets in ~~Arkansas.~~Arkansas (the “Fayetteville Shale sale”). As part of the transaction, most employees associated with those assets became employees of the buyer although the employment of some was ~~or will be,~~ terminated. Due to the scale of the assets that were sold, the temporary employment of certain employees was extended through a transition period into 2019. All affected employees were offered a severance package, which included a one-time cash payment depending on length of service and, if applicable, the current value of ~~a portion of~~ equity awards that were forfeited. ~~As of March 31, 2019, a liability of $2 million for severance payments has been accrued for the remaining Fayetteville Shale sale-related employment terminations in 2019.~~

The Company ~~has~~ also incurred charges related to office ~~consolidation and has~~consolidation. A portion of these costs along with the aforementioned severance costs were recognized ~~those costs~~ as restructuring ~~charges.~~ charges in the first quarter of 2019.

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


	For the three months ended March 31,
(in millions)	2020		2019
Severance (including payroll taxes)	$	10	$	2
Office consolidation	—		1

Total restructuring charges⁽¹⁾	$	10	$	3

For the three months ended
(in millions) March 31, 2019
Severance (including payroll taxes) $ 2
Office consolidation 1
Total restructuring charges⁽¹⁾
$ 3

(1)Total restructuring charges were $10 million and $3 million for the Company’s E&P segment for the three months ended March 31, ~~2019.~~ 2020 and 2019, respectively.

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


(in millions)
Liability at December 31, 2019	$	2
Additions	10
Distributions	(12)
Liability at March 31, 2020	$	—

For the three months ended
(in millions) March 31, 2019
Liability at December 31, 2018 $ 5
Additions 3
Distributions (6 )
Liability at March 31, 2019 $ 2

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

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

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

The Company determines if a contract contains a lease at inception. A lease is defined as a contract, or part of a contract, that conveys the right to control the use of identified property, plant or equipment (an identified asset) for a period of time in exchange for consideration. A right of use asset and lease liability are recognized on the balance sheet at commencement at an amount based on the present value of the remaining lease payments over the lease term. As the implicit rate of the lease is not always readily determinable, the Company uses the incremental borrowing rate to calculate the present value of the lease payments based on information available at commencement date. Operating right of use assets are included in other long-term assets while operating lease liabilities are included in other current and other long-term liabilities on the consolidated balance sheet. The Company does not have any financing lease type of arrangements as of March 31, 2019. By policy election, leases with an initial term of twelve months or less are not recorded on the balance sheet. The Company recognizes lease expense for these leases on a straight-line basis, and variable lease payments are recognized in the period as incurred. Variable lease costs were immaterial through the first quarter ended March 31, 2019.

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

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

The Company’s only material residual value guarantee relates to its headquarters building, which would be due only if, at the end of the lease term, the building is either purchased by the Company or marketed to a third party where the purchase price is less than the residual value guarantee. The Company does not consider the residual value guarantee to be probable of being owed; thus, it is not currently included within the minimum lease payments. The Company’s existing operating leases do not contain any material restrictive covenants.

As of March 31, 2019, the Company has operating leases of less than $1.5 million, primarily for compressor leases that have not yet commenced. These operating leases are planned to commence during 2019 with lease terms expiring through 2022.

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

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

For the three months ended
March 31, 2019
(in millions)
Cash paid for amounts included in the measurement of lease liabilities:
Operating cash flows from operating leases $ 11

Right-of use assets obtained in exchange for new operating liabilities:
Operating leases $ 3

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

March 31, 2019
Right-of-use asset balance: (in millions)

Operating leases $ 100
Lease liability balance: (in millions)

Short-term operating leases $ 38
Long-term operating leases 62
Total operating leases $ 100

Weighted average remaining lease term: (years)

Operating leases 4.1

Weighted average discount rate:
Operating leases 5.86 %

~~Maturity analysis of operating lease liabilities:~~

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

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

Revenues from Contracts with Customers

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

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

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

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

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 March 31, 2020
Gas sales	$	239	$	—	$	9	$	248
Oil sales	52		—		—		52
NGL sales	50		—		—		50
Marketing	—		548		(309)		239
Other ⁽¹⁾	3		—		—		3
Total	$	344	$	548	$	(300)	$	592

Three months ended March 31, 2019
Gas sales	$	421	$	—	$	9	$	430
Oil sales	39		—		—		39
NGL sales	81		—		—		81
Marketing	—		940		(502)		438
Other ⁽²⁾	1		1		—		2
Total	$	542	$	941	$	(493)	$	990

(in millions) E&P Midstream
Intersegment
Revenues
Total
Three months ended March 31, 2019
Gas sales $ 421
$ —
$ 9
$ 430
Oil sales 39
—
—
39
NGL sales 81
—
—
81
Marketing —
940
(502 ) 438
Other ⁽¹⁾
1
1
—
2
Total $ 542
$ 941
$ (493 ) $ 990

Three months ended March 31, 2018
Gas sales $ 535
$ —
$ 5
$ 540
Oil sales 34
—
1
35
NGL sales 65
—
—
65
Marketing —
829
(576 ) 253
Gas gathering ⁽²⁾
—
67
(43 ) 24
Other ⁽¹⁾
3
—
—
3
Total $ 637
$ 896
$ (613 ) $ 920
(1)For the three months ended March 31, 2020, other E&P revenues consists primarily of gains on purchaser imbalances associated with certain NGLs.

(2)For the three months ended March 31, 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. ~~In December 2018, the Company sold 100% of its Fayetteville Shale assets.~~


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

Receivables from Contracts with Customers

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

(in millions) March 31, 2019 December 31, 2018
Receivables from contracts with customers $ 297
$ 494
Other accounts receivable 93
87
Total accounts receivable $ 390
$ 581


(in millions)	March 31, 2020		December 31, 2019
Receivables from contracts with customers	$	195	$	284
Other accounts receivable	97		61
Total accounts receivable	$	292	$	345

Amounts recognized against the Company’s allowance for doubtful accounts related to receivables arising from contracts with customers were immaterial for the three months ended March 31, ~~2019~~2020 and ~~2018.~~2019. The Company has no0 contract assets or contract liabilities associated with its revenues from contracts with customers.

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

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

Marketable securities ⁽¹⁾

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

(in millions) March 31, 2019 December 31, 2018
Cash $ 89
$ 32
Marketable securities ⁽¹⁾
277
169
Total $ 366
$ 201

~~(7)~~(5) NATURAL GAS AND OIL PROPERTIES

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


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

Using the average quoted ~~price from the first day of each month from the previous 12 months~~prices above, adjusted for ~~Henry Hub natural gas of $3.07 per MMBtu, West Texas Intermediate oil of $63.00 per barrel and NGLs of $17.65 per barrel, adjusted for~~market differentials, the Company’s net book value of its United States natural gas and oil properties ~~did not exceed~~exceeded the ceiling ~~amount~~by $1.5 billion at March 31, ~~2019. The Company had no derivative positions that were designated for hedge accounting as of March 31, 2019.~~2020, resulting in a non-cash ceiling test impairment. Decreases in market prices as well as changes in production rates, levels of reserves, evaluation of costs excluded from amortization, future development costs and production costs could result in future ceiling test impairments. Given the decline in commodity prices in 2019 and early 2020, the Company expects that an additional non-cash impairment of its assets will likely occur in the second quarter of 2020 and perhaps later.

Using the average quoted price from the first day of each month from the previous 12 months for Henry Hub natural gas of $3.00 per MMBtu, West Texas Intermediate oil of $49.94 per barrel and NGLs of $14.90 per barrel, adjusted for differentials, theThe Company’s net book value of its United States natural gas and oil properties did not exceed the ceiling amount at March 31, ~~2018. The~~2019, and the Company had no0 derivative positions that were designated for hedge accounting as of March 31, ~~2018.~~2019.

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

Basic earnings per common share is computed by dividing net income attributable to common stock by the weighted average number of common shares outstanding during the reportable period. The diluted earnings per share calculation adds to the weighted average number of common shares outstanding: the incremental shares that would have been outstanding assuming the exercise of dilutive stock options, the vesting of unvested restricted shares of common stock, performance units and the assumed conversion of mandatory convertible preferred stock. An antidilutive impact is an increase in earnings per share or a reduction in net loss per share resulting from the conversion, exercise or contingent issuance of certain securities.

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

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

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

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

For the three months ended
March 31,
2019 2018
Unexercised stock options 5,128,640
—
Unvested share-based payment 1,881,355
5,292,454
Performance units 260,201
574,944
Mandatory convertible preferred stock —
9,999,815
Total 7,270,196
15,867,213


	For the three months ended March 31,
	2020	2019
Unexercised stock options	4,584,563	5,128,640
Unvested share-based payment	1,006,860	1,881,355
Restricted stock units	1,312,293	—
Performance units	2,275,498	260,201
Total	9,179,214	7,270,196

(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 March 31, ~~2019,~~2020, the Company’s derivative financial instruments consisted of fixed price swaps, two-way costless collars, three-way costless collars, basis swaps, call options and interest rate swaps. A description of the Company’s derivative financial instruments is provided below:

The Company ~~chooses~~contracts with counterparties for its derivative instruments that it believes are creditworthy at the time the transactions are entered into, and the Company actively monitors the credit ratings and credit default swap rates of these counterparties where applicable. However, there can be no assurance that a counterparty will be able to meet its obligations to the Company. The fair value of the Company’s derivative assets and liabilities includes a non-performance risk factor. See Note 9 for additional details regarding the Company’s fair value measurements of its derivative positions. The Company presents its derivative positions on a gross basis and does not net the asset and liability positions.

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

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


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

Three-way costless collars	2	$	—	$	2.15	$	2.55	$	3.35	$	—	$	—

Basis Swaps
2020	199	$	—	$	—	$	—	$	—	$	(0.44)	$	(3)
2021	103	—		—		—		—		(0.03)		12
2022	88	—		—		—		—		(0.48)		(4)
Total	390											$	5

Financial Protection on Production
Weighted Average Price per MMBtu

Volume (Bcf)
Swaps Sold Puts Purchased Puts Sold Calls Basis Differential
Fair Value at March 31, 2019
(in millions)
Natural Gas
2019

Fixed price swaps 195
$ 2.90
$ —
$ —
$ —
$ —
$ 23
Two-way costless collars 44
—
—
2.78
2.92
—
3
Three-way costless collars 101
—
2.46
2.88
3.22
—
13
Total 340
$ 39
2020
Fixed price swaps 24
$ 2.88
$ —
$ —
$ —
$ —
$ 3
Three-way costless collars 122
—
2.35
2.68
2.96
—
(2 )
Total 146
$ 1
2021
Three-way costless collars 37
$ —
$ 2.35
$ 2.60
$ 2.93
$ —
$ (2 )

Basis Swaps
2019 85
$ —
$ —
$ —
$ —
$ (0.50 ) $ (13 )
2020 59
—
—
—
—
(0.44 ) (8 )
Total 144
$ (21 )

Volume
(MBbls)
Weighted Average Strike Price per Bbl
Fair Value at March 31, 2019
(in millions)
Swaps Sold Puts Purchased Puts Sold Calls
Oil
2019
Fixed price swaps⁽¹⁾
921
$ 62.13
$ —
$ —
$ —
$ 1
Two-way costless collars 248
—
—
65.00
72.30
1
Three-way costless collars 412
—
45.00
55.00
63.67
—
Total 1,581
$ 2
2020
Fixed price swaps 366
$ 65.68
$ —
$ —
$ —
$ 3
Two-way costless collars 366
—
—
60.00
69.80
2
Total 732
$ 5

Propane
2019
Fixed price swaps 2,028
$ 31.25
$ —
$ —
$ —
$ 7
2020
Fixed price swaps 824
$ 27.35
$ —
$ —
$ —
$ —
Two-way costless collars 366
—
—
25.20
29.40
—
Total 1,190
$ —

Ethane
2019
Fixed price swaps 2,778
$ 13.90
$ —
$ —
$ —
$ 10
2020
Fixed price swaps 732
$ 13.49
$ —
$ —
$ —
$ 2


~~(1)~~	Includes 206 MBbls of purchased fixed price oil swaps hedged at $69.10 per barrel with a fair value of ($2) million and 1,127 MBbls of sold fixed price oil swaps hedged at $63.41 with a fair value of $3 million.

Other Derivative Contracts

Volume
(Bcf)
Weighted Average Strike Price per MMBtu
Fair Value at March 31, 2019
(in millions)
Purchased Call Options – Natural Gas
2019 30
$ 3.50
$ —
2020 68
3.63
3
2021 57
3.52
3
Total 155
$ 6

Sold Call Options – Natural Gas
2019 39
$ 3.50
$ (1 )
2020 137
3.39
(10 )
2021 114
3.33
(9 )
Total 290
$ (20 )

໿(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 March 31, 2020. As certain natural gas fixed price swaps settle, the premium will be amortized and recognized as a component of gain (loss) on derivatives on the consolidated statements of operations.

Table of Contents

Volume
(Bcf)
Weighted Average Strike Price per MMBtu Basis Differential per MMBtu
Fair Value at March 31, 2019
($ in millions)
Storage ⁽¹⁾

2019
Purchased fixed price swaps 1
$ 2.87
$ —
$ —
Purchased basis swaps 1
—
(0.53 ) —
Total $ —

2020
Fixed price swap 1
$ 3.14
$ —
$ —


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

Ethane
2020
Fixed price swaps	6,952	$	8.59		$	—		$	—		$	—		$	21
2021
Fixed price swaps	3,017	$	7.40		$	—		$	—		$	—		$	2

Propane
2020
Fixed price swaps	4,049	$	23.06		$	—		$	—		$	—		$	43
Two-way costless collars	275	—			—			25.20			29.40			4
Total	4,324													$	47
2021
Fixed price swaps	2,460	$	21.77		$	—		$	—		$	—		$	17

(1)Includes 186 MBbls of purchased fixed price oil swaps at $57.46 per barrel with a fair value of ($5) million and 2,628 MBbls of sold fixed price oil swaps at $57.73 per barrel with a fair value of $71 million.


~~(1)~~	~~The Company has entered into certain derivatives to protect the value of volumes of natural gas injected into a storage facility that will be withdrawn at a later date.~~


Other Derivative Contracts
	Volume (Bcf)	Weighted Average Strike Price per MMBtu		Fair Value at March 31, 2020 (in millions)





Sold Call Options – Natural Gas (Net)
2020	51	$	2.83	$	(2)
2021	57	3.15		(7)
2022	58	3.00		(6)
2023	17	2.84		(3)
2024	9	3.00		(2)
Total	192			$	(20)

໿


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

Table of Contents


	Volume (Bcf)	Weighted Average Strike Price per MMBtu								Fair Value at March 31, 2020 (in millions)
				Swaps			Basis Differential
Storage ⁽¹⁾
2020
Purchased fixed price swaps	3	$	2.00		$	—		$	(1)
Purchased basis swaps	1	—			(0.49)			—
Sold fixed price swaps	2	1.99			—			—
Sold basis swaps	1	—			(0.51)			—
Total	7							$	(1)
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 at a later date.


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

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

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

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

The Company is a party to interest rate swaps that were entered into to mitigate the Company’s exposure to volatility in interest rates. The interest rate swaps have a notional amount of $170 million and expire in June 2020. ~~The Company did not designate the interest rate swaps for hedge accounting treatment.~~ Changes in the fair value of the interest rate swaps are included in gain (loss) on derivatives on the consolidated statements of operations. At March 31, 2020, the net fair value of the Company’s interest rate swaps was a $1 million liability.

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

Derivative Assets
Balance Sheet Classification Fair Value
(in millions) March 31, 2019 December 31, 2018
Derivatives not designated as hedging instruments:
Fixed price swaps – natural gas Derivative assets $ 25
$ 32
Fixed price swaps – oil Derivative assets 5
13
Fixed price swaps – propane Derivative assets 7
11
Fixed price swaps – ethane Derivative assets 11
7
Two-way costless collars – natural gas Derivative assets 5
11
Two-way costless collars – oil Derivative assets 2
6
Three-way costless collars – natural gas Derivative assets 25
41
Three-way costless collars – oil Derivative assets 1
—
Basis swaps – natural gas Derivative assets 2
8
Purchased call options – natural gas Derivative assets 3
⁽¹⁾
—
Interest rate swaps Derivative assets 1
1
Fixed price swaps – natural gas Other long-term assets 4
6
Fixed price swaps – oil Other long-term assets 2
6
Fixed price swaps – ethane Other long-term assets 1
1
Two-way costless collars – oil Other long-term assets 2
5
Three-way costless collars – natural gas Other long-term assets 28
34
Basis swaps – natural gas Other long-term assets —
3
Purchased call options – natural gas Other long-term assets 4
6
Total derivative assets $ 128
$ 191


Derivative Liabilities
Derivative Assets						Derivative Assets
	Balance Sheet Classification	Fair Value						Fair Value
(in millions)		March 31, 2019		December 31, 2018		(in millions)	Balance Sheet Classification	March 31, 2020			December 31, 2019
Derivatives not designated as hedging instruments:						Derivatives not designated as hedging instruments:
Purchased fixed price swap – oil	Derivative liabilities	$	2	$	6

Purchased fixed price swaps – natural gas						Purchased fixed price swaps – natural gas	Derivative assets	$	1		$	—
Fixed price swaps – natural gas	Derivative liabilities	3		9		Fixed price swaps – natural gas	Derivative assets	181		⁽¹⁾	77		⁽¹⁾
Fixed price swaps – oil	Derivative liabilities	1		—		Fixed price swaps – oil	Derivative assets	80			4
Fixed price swaps – ethane	Derivative liabilities	—		3		Fixed price swaps – ethane	Derivative assets	22			11
Fixed price swaps – propane						Fixed price swaps – propane	Derivative assets	48			21
Two-way costless collars – natural gas	Derivative liabilities	2		7		Two-way costless collars – natural gas	Derivative assets	13			10
Two-way costless collars – oil	Derivative liabilities	1		—		Two-way costless collars – oil	Derivative assets	28			5
Two-way costless collars – propane						Two-way costless collars – propane	Derivative assets	4			2
Three-way costless collars – natural gas	Derivative liabilities	17		33		Three-way costless collars – natural gas	Derivative assets	189			126
Three-way costless collars – oil	Derivative liabilities	1		—		Three-way costless collars – oil	Derivative assets	36			3
Basis swaps – natural gas	Derivative liabilities	16		18		Basis swaps – natural gas	Derivative assets	22			17
Sold call options – natural gas	Derivative liabilities	7		3
Purchased call options – natural gas						Purchased call options – natural gas	Derivative assets	3			1
Fixed price swaps – natural gas storage						Fixed price swaps – natural gas storage	Derivative assets	—			1

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

Three-way costless collars – natural gas	Other long-term liabilities	27		35		Three-way costless collars – natural gas	Other long-term assets	71			74
Basis swap – natural gas	Other long-term liabilities	7		4
Sold call options – natural gas	Other long-term liabilities	13		19
Total derivative liabilities		$	97	$	139
Three-way costless collars – oil						Three-way costless collars – oil	Other long-term assets	29			7
Basis swaps – natural gas						Basis swaps – natural gas	Other long-term assets	5			15
Purchased call options – natural gas						Purchased call options – natural gas	Other long-term assets	1			2
Total derivative assets						Total derivative assets		$	791		$	391

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

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

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

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

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

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

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

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 March 31,
						2020			2019

		(in millions)
Purchased fixed price swaps – natural gas	Gain (Loss) on Derivatives	$	(1)	$	—
Purchased fixed price swaps – oil	Gain (Loss) on Derivatives	—		(1)
Fixed price swaps – natural gas	Gain (Loss) on Derivatives	5		(6)
Fixed price swaps – oil	Gain (Loss) on Derivatives	9		2
Fixed price swaps – ethane	Gain (Loss) on Derivatives	6		1
Fixed price swaps – propane	Gain (Loss) on Derivatives	10		2
Two-way costless collars – natural gas	Gain (Loss) on Derivatives	6		(1)
Two-way costless collars – oil	Gain (Loss) on Derivatives	3		1
Two-way costless collars – propane	Gain (Loss) on Derivatives	1		—
Three-way costless collars – natural gas	Gain (Loss) on Derivatives	36		(4)
Three-way costless collars – oil	Gain (Loss) on Derivatives	1		—
Basis swaps – natural gas	Gain (Loss) on Derivatives	16		(4)



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

Total gain (loss) on derivatives				$	339		$	(32)

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

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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 March 31,
2019 2018
(in millions)
Purchased fixed price swaps – oil Gain (Loss) on Derivatives $ 4
$ —

Fixed price swaps – natural gas Gain (Loss) on Derivatives (2 ) (3 )
Fixed price swaps – oil Gain (Loss) on Derivatives (13 ) —

Fixed price swaps – propane Gain (Loss) on Derivatives (4 ) 3

Fixed price swaps – ethane Gain (Loss) on Derivatives 7
—

Two-way costless collars – natural gas Gain (Loss) on Derivatives (1 ) 3

Two-way costless collars – oil Gain (Loss) on Derivatives (7 ) —

Three-way costless collars – natural gas Gain (Loss) on Derivatives 2
(5 )
Basis swaps – natural gas Gain (Loss) on Derivatives (10 ) 20

Purchased call options – natural gas Gain (Loss) on Derivatives —
16

Sold call options – natural gas Gain (Loss) on Derivatives 2
(34 )
Interest rate swaps Gain (Loss) on Derivatives —
2

Total gain (loss) on unsettled derivatives $ (22 ) $ 2

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 March 31,
2019 2018
(in millions)
Purchased fixed price swaps – oil Gain (Loss) on Derivatives $ (1 ) $ —

Sold fixed price swaps – natural gas Gain (Loss) on Derivatives (6 ) —

Sold fixed price swaps – oil Gain (Loss) on Derivatives 2
—

Sold fixed price swaps – propane Gain (Loss) on Derivatives 2
—

Sold fixed price swaps – ethane Gain (Loss) on Derivatives 1
—

Two-way costless collars – natural gas Gain (Loss) on Derivatives (1 ) 4

Two-way costless collars – oil Gain (Loss) on Derivatives 1
—

Three-way costless collars – natural gas Gain (Loss) on Derivatives (4 ) 7

Sold basis swaps – natural gas Gain (Loss) on Derivatives (4 ) (21 )
Purchased call options – natural gas Gain (Loss) on Derivatives —
2
⁽²⁾
Sold call options – natural gas Gain (Loss) on Derivatives —
(1 )
Total loss on settled derivatives $ (10 ) $ (9 )

Total loss on derivatives $ (32 ) $ (7 )


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


~~(2)~~	Includes $1 million amortization of premiums paid related to certain natural gas call options for the three months ended March 31, 2018, which is included in gain (loss) on derivatives on the consolidated statements of operations.

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

In the first quarter of ~~2019,~~2020, changes in accumulated other comprehensive income related to the Company’s pension and other postretirement ~~benefits were immaterial.~~benefits. The following tables detail the components of accumulated other comprehensive income and the related tax effects for the three months ended March 31, ~~2019:~~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 March 31, 2020	$	(19)	$	(14)	$	(33)

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


~~(1)~~	~~See separate table below for details about these reclassifications.~~



Details about Accumulated Other Comprehensive Income	Affected Line Item in the Consolidated Statement of Operations	~~Amount Reclassified from Accumulated Other Comprehensive Income~~
		~~For the three months ended~~
		~~March 31, 2019~~
		~~(in millions)~~
~~Pension and other postretirement:~~
~~Amortization of prior service cost and net gain~~⁽¹⁾	~~Other Income (Loss), Net~~	$	—
	~~Benefit from income taxes~~	—
	~~Net income~~	$	—

~~Total reclassifications for the period~~	~~Net income~~	$	—

໿


~~(1)~~	(1)Amounts reclassified from other comprehensive income to earnings were immaterial for the three months ended March 31, 2020. See Note 13~~Note 15~~ for additional details regarding the Company’s pension and other postretirement benefit plans.

~~(11)~~

(9) FAIR VALUE MEASUREMENTS

Assets and liabilities measured at fair value on a recurring basis

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


	March 31, 2020									December 31, 2019
(in millions)	Carrying Amount			Fair Value			Carrying Amount			Fair Value
Cash and cash equivalents	$	5		$	5		$	5		$	5
2018 revolving credit facility due April 2024	149			149			34			34
Senior notes⁽¹⁾	2,148			1,460			2,228			2,085
Derivative instruments, net	401		⁽²⁾	401		⁽²⁾	155		⁽²⁾	155		⁽²⁾

March 31, 2019 December 31, 2018
(in millions)
Carrying
Amount

Fair
Value

Carrying
Amount

Fair
Value
Cash and cash equivalents $ 366
$ 366
$ 201
$ 201
2018 revolving credit facility due April 2023 —
—
—
—
Senior notes⁽¹⁾
2,342
2,352
2,342
2,190
Derivative instruments, net 31
⁽²⁾
31
⁽²⁾
52
52
(1)Excludes unamortized debt issuance costs and debt discounts.

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


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


~~(2)~~	~~Includes $1 million in premiums paid related to certain natural gas purchased call options recognized as a component of derivative assets within current assets on the consolidated balance sheet.~~

The fair value hierarchy prioritizes the inputs to valuation techniques used to measure fair value. As presented in the tables below, this hierarchy consists of three broad levels:

Level 1 valuations - Consist of unadjusted quoted prices in active markets for identical assets and liabilities and have the highest priority.

Level 2 valuations - Consist of quoted market information for the calculation of fair market value.

Level 3 valuations - Consist of internal estimates and have the lowest priority.

The carrying values of cash and cash equivalents, including marketable securities, accounts receivable, other current assets, accounts payable and other current liabilities on the consolidated balance sheets approximate fair value because of their short-term nature. For debt and derivative instruments, the following methods and assumptions were used to estimate fair value:

Debt: The fair values of the Company’s senior notes ~~were~~are based on the market value of the Company’s publicly traded debt as determined based on the market prices of the Company’s senior notes. ~~These instruments were previously classified as a Level~~

~~2 measurement but substantially all senior notes were updated to a Level 1 measurement in the second quarter of 2018 as the market activity~~The fair value of the ~~Company’s debt has resulted in timely quoted prices. The 4.05%~~Company's 4.10% Senior Notes due ~~January 2020 remain~~March 2022 is considered to be a Level 2 measurement ~~due to relative market inactivity.~~

on the fair value hierarchy. The fair values of the Company's 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 ~~all~~its derivative instruments isbased upon a pricing model that utilizes market-based inputs, including, but not limited to, the ~~amount at which~~contractual price of the ~~instrument could be exchanged currently between willing parties. The amounts~~underlying position, current market prices, natural gas and liquids forward curves, discount rates such as the LIBOR curve for a similar duration of each outstanding position, volatility factors and non-performance risk. Non-performance risk considers the effect of the Company’s credit standing on the fair value of derivative liabilities and the effect of counterparty credit standing on the fair value of derivative assets. Both inputs to the model are based on ~~quoted market prices, best estimates obtained from counterparties~~published credit default swap rates and ~~an option pricing model, when necessary, for price option contracts.~~the duration of each

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

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

The Company’s call options, two-way costless collars and three-way costless collars (Level 2) are valued using the Black-Scholes model, an industry standard option valuation model that takes into account inputs such as contract terms, including maturity, and market parameters, including assumptions of the NYMEX and OPIS futures index, interest rates, volatility and credit worthiness. The Company’s basis swaps (Level 2) are estimated using third-party calculations based upon forward commodity price curves. These instruments were previously classified as a Level 3 measurement in the fair value hierarchy but were updated to a Level 2 measurement in the second quarter of 2018 as a result of the Company’s ability to derive volatility inputs and forward commodity price curves from directly observable sources.

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

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

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


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


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

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

March 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 swap – natural gas $ —
$ 29
$ —
$ 29
Fixed price swap – oil —
7
—
7
Fixed price swap – propane —
7
—
7
Fixed price swap – ethane —
12
—
12
Two-way costless collar – natural gas —
5
—
5
Two-way costless collar – oil —
4
—
4
Three-way costless collar – natural gas —
53
—
53
Three-way costless collar - oil —
1
—
1
Basis swap – natural gas —
2
—
2
Purchased call option – natural gas ⁽¹⁾
—
7
—
7
Interest rate swap —
1
—
1
Liabilities
Purchase fixed price swap – oil —
(2 ) —
(2 )
Fixed price swap – natural gas —
(3 ) —
(3 )
Fixed price swap – oil —
(1 ) —
(1 )
Two-way costless collar – natural gas —
(2 ) —
(2 )
Two-way costless collar – oil —
(1 ) —
(1 )
Three-way costless collar – natural gas —
(44 ) —
(44 )
Three-way costless collar – oil —
(1 ) —
(1 )
Basis swap – natural gas —
(23 ) —
(23 )
Sold call option – natural gas —
(20 ) —
(20 )
Total $ —
$ 31
$ —
$ 31

(1)Includes $1$9 million in premiums paid related to certain natural gas ~~purchased call options~~fixed price swaps recognized as a component of derivative assets within current assets on the consolidated balance sheet at March 31, ~~2019.~~2020. As certain natural gas ~~purchased call options~~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.

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

~~The table below presents reconciliations for the change in~~(2)Includes a net fair value reduction of less than $1 million related to estimated nonperformance risk.

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

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


Total	$	—	$	155	$	—	$	155

(1)Includes $9 million in premiums paid related to certain natural gas fixed price swaps recognized as a component of derivative assets within current assets on the consolidated balance sheet at December 31, 2019. As certain natural gas fixed price swaps settle, the premium will be amortized and ~~liabilities measured at fair value~~recognized as a component of gain (loss) on ~~a recurring basis using significant unobservable inputs (Level 3) for~~derivatives on the ~~three months ended March 31, 2019 and 2018.~~ consolidated statements of operations.

The fair values of Level 3 derivative instruments ~~were~~are estimated using proprietary valuation models that ~~utilized~~utilize both market observable and unobservable parameters. Level 3 instruments ~~presented in the table consisted~~consist of net derivatives valued using pricing models incorporating assumptions that, in the Company’s judgment, ~~reflected~~reflect reasonable assumptions a marketplace participant would ~~have used as of March 31, 2018. Commodity derivatives previously presented as~~use. There were no Level 3 ~~were transferred to Level 2~~derivatives in the ~~second quarter~~first quarters of ~~2018 as the Company moved from using proprietary volatility inputs~~2020 and ~~forward curves to more widely available published information, increasing market observability.~~2019.

໿

For the three months ended March 31,
(in millions) 2019 2018
Balance at beginning of period $ —
$ 22
Total gains (losses):
Included in earnings —
(9 )
Settlements ⁽¹⁾
—
9
Transfers into/out of Level 3 —
—
Balance at end of period $ —
$ 22
Change in gains (losses) included in earnings relating to derivatives still held as of March 31 $ —
$ —


~~(1)~~	~~Includes $1 million amortization of premiums paid related to certain natural gas call options for the three months ended March 31, 2018.~~

~~(12)~~(10) DEBT

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


	March 31, 2020
(in millions)	Debt Instrument		Unamortized Issuance Expense			Unamortized Debt Discount		Total




Long-term debt:
Variable rate (2.120% at March 31, 2020) 2018 revolving credit facility due April 2024	$	149	$	—	⁽¹⁾	$	—	$	149
4.10% Senior Notes due March 2022	210		(1)			—		209
4.95% Senior Notes due January 2025⁽²⁾	864		(5)			(1)		858
7.50% Senior Notes due April 2026	621		(6)			—		615
7.75% Senior Notes due October 2027	453		(5)			—		448
Total long-term debt	$	2,297	$	(17)		$	(1)	$	2,279



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

Long-term debt:
Variable rate (3.923% at March 31, 2019) 2018 revolving credit facility, due April 2023 $ —
$ —
⁽²⁾
$ —
$ —
4.10% Senior Notes due March 2022 213
(1 ) —
212
4.95% Senior Notes due January 2025⁽¹⁾
927
(7 ) (1 ) 919
7.50 % Senior Notes due April 2026 650
(8 ) —
642
7.75 % Senior Notes due October 2027 500
(6 ) —
494
Total long-term debt $ 2,290
$ (22 ) $ (1 ) $ 2,267

Total debt $ 2,342
$ (22 ) $ (1 ) $ 2,319

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

~~(1)~~

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

~~(2)~~

~~At March 31, 2019 and December 31, 2018, unamortized issuance expense of $10 million and~~ ~~$11~~ ~~million, respectively, associated with the 2018 revolving credit facility is classified as other long-term assets on the consolidated balance sheets.~~(2)At March 31, 2020 and December 31, 2019, respectively, 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 ~~2016~~ credit facility ~~(which consisted of a $1,191 million secured term loan and an unsecured $743 million revolving credit facility)~~that was entered into in 2016 with a new revolving credit facility (the “2018 credit facility”). 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, at March 31, ~~2019,~~2020, had a ~~current~~ borrowing base of $2.1 billion with ~~a current~~ aggregate ~~commitment~~bank commitments of $2.0 billion. The Company may utilize the credit facility in the form of loans and letters of credit. The borrowing base is subject to redetermination at least twice a year, in April and October. On April ~~4, 2019,~~13, 2020, the banks participating in the 2018 credit facility ~~reaffirmed~~redetermined the borrowing base to be $1.8 billion, which also changed the aggregate commitments to that amount. The 2018 credit facility is secured by substantially all of ~~$2.1 billion.~~the assets owned by the Company and its subsidiaries. The permitted lien provisions in the senior note indentures currently limit liens securing indebtedness to the greater of $2.0 billion ~~and~~or 25% of adjusted consolidated net tangible assets. ~~The 2018 credit facility matures in April 2023 and is secured by substantially all of the assets owned by the Company and its subsidiaries.~~

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

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

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

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

•restrictions on mergers and asset dispositions;

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

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


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

Maximum total net leverage ratio of no less 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 Company’s 2018 credit agreement, excludes the effects of interest expense, depreciation, depletion and amortization, income tax, any non-cash impacts from impairments, certain non-cash hedging activities, stock-based compensation expense, non-cash gains or losses on asset sales, unamortized issuance cost, unamortized debt discount and certain restructuring costs.

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

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

Each United States domestic subsidiary of the Company for which the Company owns 100% guarantees the 2018 credit facility. Pursuant to requirements under the indentures governing its senior notes, each subsidiary that became a guarantor of the 2018 credit facility also became a guarantor of each of the Company’s senior notes. ~~See~~ ~~Note 19~~ ~~for the Company’s Condensed Consolidated Financial Information, presented in accordance with Rule 3-10 of Regulation S-X.~~

As of March 31, ~~2019,~~2020, the Company had $172 million in letters of credit and no$149 million borrowings outstanding under the 2018 ~~revolving~~ credit facility.

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

Senior Notes

In January 2015, the Company completed a public offering of ~~$850 million aggregate principal amount of its 4.05% senior notes due 2020 (the “2020 Notes”) and~~ $1.0 billion aggregate principal amount of its 4.95% senior notes due 2025 (the “2025 Notes” ~~together with the 2020 Notes, the “Notes”~~). The interest ~~rates~~rate on the 2025 Notes ~~are~~is determined based upon the public bond ratings from Moody’s and S&P. Downgrades on the 2025 Notes from either rating agency increase interest costs by 25 basis points per downgrade level and upgrades decrease interest costs by 25 basis points per upgrade level, up to the stated coupon rate, on the following semi-annual bond interest payment. ~~In February and June 2016, Moody’s and~~At March 31, 2020, the interest rate for the 2025 Notes was 6.20%, reflecting a net downgrade in the Company’s bond ratings since the initial offering. This rate has been in effect since January 2019. On April 7, 2020, S&P downgraded the ~~Notes,~~Company’s bond rating to BB- which had the effect of increasing the interest ~~rates by 175 basis points effective July 2016. As a result of these downgrades, interest rates increased to 5.80% for the 2020 Notes and 6.70% for~~rate on the 2025 ~~Notes.~~Notes to 6.45%. The first coupon payment to the bondholders at the higher interest rate will be paid in January 2021. In the event of future downgrades, the coupons for this series of notes ~~are~~have been capped at ~~6.05%~~6.95%.

In the first quarter of 2020, the Company repurchased $3 million of its 4.10% Senior Notes due 2022, $28 million of its 4.95% Senior Notes due 2025, $18 million of its 7.50% Senior Notes due 2026 and ~~6.95%, respectively. The first coupon payment to~~$31 million of its 7.75% Senior Notes due 2027 for $52 million, and recognized a $28 million gain on the ~~bondholders at the higher interest rates was paid in January 2017. S&P and Moody’s upgraded the Notes in April and May 2018, respectively. As a result~~extinguishment of these upgrades, interest rates decreased to 5.30% for the 2020 Notes and 6.20% for the 2025 Notes effective July 2018. The first coupon payment to the bondholders at the lower interest rates was paid in January 2019.debt.

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

Operating Commitments and Contingencies

As of March 31, ~~2019,~~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 ~~$9.0~~$7.6 billion, ~~$1.4 billion~~$411 million of which related to access capacity on future pipeline and gathering infrastructure projects that still require the granting of regulatory approvals and additional construction efforts. The Company also had guarantee obligations of up to ~~$403 million~~$1.1 billion of that amount. As of March 31, ~~2019,~~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	$	7,199	$	753	$	1,339	$	1,098	$	1,524	$	2,485
Pending regulatory approval and/or construction ⁽¹⁾	411		1		17		23		74		296
Total transportation charges	$	7,610	$	754	$	1,356	$	1,121	$	1,598	$	2,781

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 $ 7,583
$ 723
$ 1,304
$ 1,135
$ 1,520
$ 2,901
Pending regulatory approval and/or construction ⁽¹⁾
1,411
4
113
167
285
842
Total transportation charges $ 8,994
$ 727
$ 1,417
$ 1,302
$ 1,805
$ 3,743
(1)Based on estimated in-service dates as of March 31, 2020.


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

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

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2020, approximately ~~$188~~$81 million of these contractual commitments remain of which the Company will reimburse the buyer for certain of these potential obligations up to approximately ~~$94~~$45 million through December 2020 depending on the buyer’s actual use, and has recorded a ~~$78~~$36 million liability for the estimated future payments, down from ~~$88~~$46 million recorded at December 31, ~~2018.~~2019.

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

In 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.

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, ~~that~~most of which have arisen in the ordinary course of business, such as for alleged breaches of contract, miscalculation of royalties, employment matters, traffic accidents, pollution, contamination, encroachment on others’ property or nuisance. The Company accrues for ~~such items~~litigation, claims and proceedings when a liability is both probable and the amount can be reasonably estimated. ItAs of March 31, 2020, the Company does not currently have any material amounts accrued related to litigation matters. For any matters not accrued for, it is not possible at this time to estimate the amount of any additional loss, or range of loss, that is reasonably possible, but, based on the nature of the claims, management believes that current litigation, claims and proceedings, individually or in aggregate and after taking into account insurance, are not likely to have a material adverse impact on the Company’s financial position, results of operations or cash flows, for the period in which the effect of that outcome becomes reasonably estimable. Many of these matters are in early stages, so the allegations and the damage theories have not been fully developed, and are all subject to inherent uncertainties; therefore, management’s view may change in the future.

~~Arkansas Royalty Litigation~~

The Company has been a defendant in three certified class actions alleging that the Company underpaid lessors of lands in Arkansas by deducting from royalty payments costs for gathering, transportation and compression of natural gas in excess of what is permitted by the relevant leases. Two of the these class actions were filed in Arkansas state courts and the third in the United StatesSt. Lucie County Fire District Court for the Eastern District of Arkansas. The Company denied liability in all these cases. Under the agreement for the sale of the Company’s properties in the Fayetteville Shale, the Company retained responsibility for these class actions.Firefighters’ Pension Trust

~~In June 2017,~~

On October 17, 2016, the ~~jury returned~~St. Lucie County Fire District Firefighters’ Pension Trust filed a ~~verdict in favor of the Company on all counts in~~ ~~Smith v. SEECO, Inc. et al., the~~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, ~~whose plaintiff class comprises~~but after a decision by the ~~vast majority~~United States Supreme Court in an unrelated case that these types of cases are not subject to removal, the ~~lessors in these cases.~~federal court remanded the case to the Texas state court. The plaintiff had asserted claims for, among other things, breach of contract, fraud, civil conspiracy, unjust enrichment and violation of certain Arkansas statutes. Following the verdict, the court entered judgment in favor of the Company on all claims. TheTexas trial court denied the ~~plaintiff’s~~Company’s motion ~~for a new trial,~~to dismiss, and in February 2020, the ~~plaintiff appealed~~court of appeals declined to ~~the United States Court of Appeals for the Eighth Circuit. Independent of the plaintiff’s appeal, several different parties sought~~exercise discretion to ~~intervene in the~~ ~~Smith~~ ~~case prior to or shortly after trial, and have appealed~~reverse the trial court’s ~~order denying their request~~decision. The Company filed a petition to ~~intervene. Oral argument occurred in January 2019. On April 23, 2019, the Court of Appeals affirmed~~review the trial court’s ~~order denying all requests to intervene in~~decision with the ~~case, and, in a separate order, affirmed~~Texas Supreme Court, which remains pending. The Company carries insurance for the ~~trial court’s judgment in favor of the Company on all claims.~~

~~In the second quarter of 2018, the Company entered into an agreement to settle another of the class actions, which has been pending in the Circuit Court of Conway County, Arkansas under the caption~~ ~~Snow et al. v. SEECO, Inc~~.~~, et al. The settlement received final approval by the court during the third quarter of 2018,~~claims asserted against it and the deadline to appeal the order approving the settlement passed without any appeals filed. The amount of the settlement is reflected in the Company’s consolidated statement of operations for the second quarter of 2018officer and ~~was paid early in the fourth quarter of 2018. The third class action was dismissed in the second quarter of 2018.~~

~~The~~ ~~Smith~~director defendants, and the ~~Snow~~ ~~cases cover~~carrier has accepted coverage. The Company denies all ~~affected lessors, except a small percentage who opted out. Most of those have filed separate actions.~~allegations and intends to continue to defend this case vigorously. The Company does not expect ~~those cases~~this case to have a material adverse effect on the results of operations, financial position or cash flows of the ~~Company.~~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 ~~provides~~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 ~~assets. These~~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. NoIn the case of equity offerings, these indemnifications typically relate to claims asserted against underwriters in connection with an offering. NaN material liabilities have been recognized in connection with these indemnifications.

~~(14)~~

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(12) INCOME TAXES

The Company’s effective tax rate was approximately ~~(254)~~(36)% ~~and 0%~~ for the three months ended March 31, ~~2019 and 2018, respectively, primarily as~~2020. The change in the effective tax rate for the three months ended March 31, 2020 related to the effects of recording a ~~result of~~valuation allowance against the ~~release of valuation allowances previously recorded against~~Company’s U.S. deferred tax assets. A valuation allowance for deferred tax assets, including net operating losses, is recognized when it is more likely than not that some or all of the benefit from the deferred tax assets will not be realized. To assess that likelihood, the Company uses estimates and judgment regarding future taxable income, and considers the tax consequences in the jurisdiction where such taxable income is generated, to determine whether a valuation allowance is required. Such evidence can include current financial position, results of operations, both actual and forecasted, the reversal of deferred tax liabilities and tax planning strategies as well as ~~the~~ current and forecasted business economics of the oil and gas industry.

~~For~~Due to significant pricing declines and the ~~year~~material write-down of the carrying value of the Company’s natural gas and oil properties in the three months ended ~~December~~March 31, ~~2018,~~2020, the Company ~~maintained a full valuation allowance against its deferred tax assets based on its conclusion, considering all available evidence (both positive and negative),~~concluded that it was more likely than not that ~~the~~these deferred tax assets ~~would~~will not be realized. A significant item of objective negative evidence considered was the cumulative pre-tax loss incurred over the three-year period ended December 31, 2018, primarily due to impairments of proved natural gas and oil properties recognized in 2015 and 2016. As of the first quarter of 2019, the Company has sustained a three-year cumulative level of profitability. Based on this factor and other positive evidence including forecasted income, the Company concluded that it is more likely than not that the deferred tax assets would be realized and ~~released substantially all of the valuation allowance. This resulted in~~recorded a discrete tax ~~benefit recorded for~~expense in the period of ~~$426 million.~~$408 million for the increase in its valuation allowance. The net change in valuation allowance is reflected as a component of income tax expense. The Company ~~expects to keep~~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.

~~In February 2018,~~The Company’s effective tax rate was approximately (254)% for the ~~FASB issued Accounting Standards Update No. 2018-02 amending~~three months ended March 31, 2019. The effective tax rate for the ~~FASB Accounting Standards relating~~three months ended March 31, 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 ~~effects~~assets would be realized and determined $522 million of the valuation allowance would be released during 2019, of which $426 million was released on a discrete basis in ~~accumulated other comprehensive income. See~~ ~~Note 18 – New Accounting Pronouncements~~ ~~for more information regarding this update.~~the first quarter of 2019.

~~(15)~~(13) PENSION PLAN AND OTHER POSTRETIREMENT BENEFITS

The Company maintains defined pension and other postretirement benefit plans, which cover substantially all of the Company’s employees. Net periodic pension costs include the following components for the three months ended March 31, ~~2019~~2020 and ~~2018:~~2019:



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

Net periodic benefit cost		$	2		$	2

Pension Benefits

Consolidated Statements of
Operations Classification of
Net Periodic Benefit Cost ⁽¹⁾
For the three months ended March 31,
(in millions) 2019 2018
Service cost General and administrative expenses $ 2
$ 3
Interest cost Other Income (Loss), Net 1
2
Expected return on plan assets Other Income (Loss), Net (2 ) (2 )
Amortization of prior service cost Other Income (Loss), Net —
—
Amortization of net loss Other Income (Loss), Net 1
—
Net periodic benefit cost $ 2
$ 3


~~(1)~~	In the first quarter of 2018, the Company adopted Accounting Standards Update No. 2017-07, which requires the service cost component to be disaggregated from the other components of net benefit cost, which are to be presented outside of income from operations. See ~~Note 18 – New Accounting Pronouncements~~ ~~for more information regarding this update.~~

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

As of March 31, ~~2019,~~2020, the Company has contributed $5 million to the pension and other postretirement benefit plans and expects to contribute an additional $7 million to its pension plan during the remainder of ~~2019.~~2020. The Company recognized ~~a liability~~liabilities of ~~$31~~$27 million and $13 million related to its pension and other postretirement benefits, respectively, as of March 31, ~~2019,~~2020, compared to ~~a liability~~liabilities of ~~$34~~$30 million and $13 million as of December 31, ~~2018.~~2019, respectively.

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

~~(16) STOCK-BASED~~

Table of Contents

(14) LONG-TERM INCENTIVE COMPENSATION

The Company’s long-term incentive compensation plans consist of a combination of stock-based awards that derive their value directly or indirectly from the Company’s common stock price, and cash-based awards that are fixed in amount but subject to meeting annual performance thresholds. In March 2020, the Company ~~recognized the following amounts in total employee stock-based compensation costs~~issued its first long-term fixed cash-based awards. The resulting impact to general and administrative expenses as well as capitalized expenses was immaterial for the ~~three months ended March 31, 2019 and 2018:~~first quarter of 2020.

For the three months ended March 31,
(in millions) 2019 2018
Stock-based compensation cost – expensed $ 7
$ 5
Stock-based compensation cost – capitalized 4
3

Stock-Based Compensation

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

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

The Company recognized the following amounts in total employee stock-based compensation costs ~~recognized prior to the cancellation as either general and administrative expense or capitalized expense were reversed and the severance payments~~

~~were subsequently recognized as restructuring charges~~ for ~~the year ended December 31, 2018 and~~ the three months ended March 31, ~~2019 on~~2020 and 2019:


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

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

Equity-Classified Awards

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

For the three months ended March 31,
(in millions) 2019 2018
Equity-classified awards – expensed $ 2
$ 4
Equity-classified awards – capitalized 1
3


	For the three months ended March 31,
(in millions)	2020		2019
Equity-classified awards – expensed	$	1	$	2
Equity-classified awards – capitalized	—		1

As of March 31, ~~2019,~~2020, there was ~~$14~~$4 million of total unrecognized compensation cost related to the Company’s unvested equity-classified stock option grants, equity-classified restricted stock grants and equity-classified performance units. This cost is expected to be recognized over a weighted-average period of ~~one and a half~~0.9 years.

Table of Contents

Equity-Classified Stock Options

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

Number
of Options

Weighted Average
Exercise Price
(in thousands)
Outstanding at December 31, 2018 5,178
$ 17.06
Granted —
$ —
Exercised —
$ —
Forfeited or expired (58 ) $ 15.74
Outstanding at March 31, 2019 5,120
$ 17.07
Exercisable at March 31, 2019 4,604
$ 18.16


	Number of Options	Weighted Average Exercise Price
	(in thousands)
Outstanding at December 31, 2019	4,635	$	15.26
Granted	—	$	—
Exercised	—	$	—
Forfeited or expired	(62)	$	15.11
Outstanding at March 31, 2020	4,573	$	15.27
Exercisable at March 31, 2020	4,478	$	15.48

Equity-Classified Restricted Stock

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

Number
of Shares

Weighted Average
Fair Value
(in thousands)
Unvested shares at December 31, 2018 2,717
$ 7.91
Granted 9
$ 3.72
Vested (608 ) $ 8.74
Forfeited (145 ) $ 8.38
Unvested shares at March 31, 2019 1,973
$ 7.61


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

Equity-Classified Performance Units

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


	Number of 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 March 31, 2020	—	$	—

Number
of Shares ⁽¹⁾

Weighted Average
Fair Value
(in thousands)
Unvested units at December 31, 2018 598
$ 10.01
Granted —
$ —
Vested (371 ) $ 9.73
Forfeited (30 ) $ 10.47
Unvested units at March 31, 2019 197
$ 10.47
(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.


~~(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 months ended March 31, ~~2019:~~2020:


	For the three months ended March 31,
(in millions)	2020		2019
Liability-classified stock-based compensation cost – expensed	$	(1)	$	5
Liability-classified stock-based compensation cost – capitalized	—		3

For the three months ended March 31,
(in millions) 2019 2018
Liability-classified stock-based compensation cost – expensed $ 5
$ 1
Liability-classified stock-based compensation cost – capitalized 3
—

Table of Contents

Liability-Classified Restricted Stock Units

In the first quarter of each year beginning with 2018, ~~and 2019,~~ 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 March 31, ~~2019,~~2020, there was ~~$61~~$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 ~~three~~3.0 years. The amount of unrecognized compensation cost for liability-classified awards will fluctuate over time as they are marked to market.


						Number of Units	Weighted Average Fair Value
	Number of Units		Weighted Average Fair Value			(in thousands)
	(in thousands)
Unvested shares at December 31, 2018	8,202		$	3.41
Unvested units at December 31, 2019					Unvested units at December 31, 2019	12,992	$	2.42
Granted	8,659		$	4.34	Granted	6,172	$	1.41
Vested	(2,120	)	$	4.29	Vested	(3,852)	$	1.38
Forfeited	(504	)	$	3.85	Forfeited	(1,464)	$	1.67
Unvested units at March 31, 2019	14,237		$	4.69
Unvested units at March 31, 2020					Unvested units at March 31, 2020	13,848	$	1.69

In ~~the first quarter of~~each year beginning with 2018, ~~and 2019,~~ the Company granted performance units that vest at the end of, or over, a ~~three-year~~three-year period and are payable in either cash or shares at the option of the Compensation Committee of the Company’s Board of Directors. The Company has accounted for these as liability-classified awards, and accordingly changes in the fair market value of the instruments will be recorded to general and administrative expense and capitalized expense over the vesting period of the awards. The performance unit awards granted in 2018 include a performance condition based on cash flow per debt-adjusted share and two market conditions, one based on absolute TSR and the other on relative TSR as compared to a group of the Company’s peers. The performance unit awards granted in 2019 include a performance ~~condition~~conditions based on return on average capital employed and two market conditions, one based on absolute TSR and the other on relative TSR. The performance units granted in 2020 include a performance condition based on return on average capital employed and a market condition based on relative TSR. The fair values of the ~~two~~ market conditions are calculated by Monte Carlo models on a quarterly basis. As of March 31, ~~2019,~~2020, there was ~~$19~~$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 ~~three~~2.6 years. The amount of unrecognized compensation cost for liability-classified awards will fluctuate over time as they are marked to market. The final value of the performance unit awards is contingent upon the Company’s actual performance against these performance measures.


	Number of Units	Weighted Average Fair Value
	(in thousands)
Unvested units at December 31, 2019	5,142	$	2.42
Granted	6,172	$	1.41
Vested	—	$	—
Forfeited	—	$	—
Unvested units at March 31, 2020	11,314	$	1.69

Cash-Based Compensation

Performance Cash Awards

In 2020, the Company granted performance cash awards that vest over a four-year period and are payable in cash on an annual basis. The value of each unit of the award equals one dollar. The Company recognizes the cost of these awards as general and administrative expense and capitalized expense over the vesting period of the awards. The performance cash awards granted in 2020 include a performance condition determined annually by the Company. In 2020, the performance measure is a targeted discretionary cash flow amount. If the Company, in its sole discretion, determines that the threshold was not met, the amount for that vesting period will not vest and will be cancelled. As of March 31, 2020, there was $19 million of total unrecognized compensation cost related to performance cash awards. This cost is expected to be recognized over a weighted average 3.9 years. The final value of the performance cash awards is contingent upon the Company’s actual performance against these performance measures.

Number
of Shares

Weighted Average
Fair Value
(in thousands)
Unvested shares at December 31, 2018 2,803
$ 3.41
Granted 2,757
$ 4.34
Vested —
$ —
Forfeited (119 ) $ 4.65
Unvested units at March 31, 2019 5,441
$ 4.69


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

~~(17)~~(15) SEGMENT INFORMATION

The Company’s reportable business segments have been identified based on the differences in products or services provided. Revenues for the E&P segment are derived from the production and sale of natural gas and liquids. The ~~Midstream~~Marketing segment generates revenue through the marketing of both Company and third-party produced natural gas and liquids volumes.

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

Summarized financial information for the Company’s reportable segments is shown in the following table. The accounting policies of the segments are the same as those described in Note 1 of the Notes to Consolidated Financial Statements included in Item 8 of the ~~2018~~2019 Annual Report. Management evaluates the performance of its segments based on operating income, defined as operating revenues less operating costs. Income before income taxes, for the purpose of reconciling the operating income amount shown below to consolidated income before income taxes, is the sum of operating income, interest expense, gain (loss) on derivatives, gain on early extinguishment of debt and other ~~income (loss).~~income. The “Other” column includes items not related to the Company’s reportable segments, including real estate and corporate items.

Interest expense ⁽²⁾

Benefit from income taxes ⁽²⁾

Capital investments⁽⁵⁾

Operating income⁽⁶⁾

Interest expense ⁽²⁾

Capital investments ⁽⁵⁾

Included in intersegment revenues of the Midstream segment are $502 million and $576 million for the three months ended March 31, 2019 and 2018, respectively for marketing of the Company’s E&P sales. Corporate assets include cash and cash equivalents, furniture and fixtures and other assets. Corporate general and administrative costs, depreciation expense and taxes, other than income taxes, are allocated to the segments.


	E&P			Marketing		Other			Total

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

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

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

Other income, net	1			—		—			1
Benefit from income taxes⁽²⁾	(426)			—		—			(426)
Assets	5,562		⁽³⁾	342		542		⁽⁴⁾	6,446
Capital investments⁽⁵⁾	325			—		—			325

(1)Operating income for the E&P segment includes $10 million and $3 million of restructuring charges for the three months ended March 31, 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. For the three months ended March 31, 2019, this also includes deferred tax assets which are an allocation of corporate amounts as they are incurred at the corporate level.

(4)Other assets represent corporate assets not allocated to segments and assets for non-reportable segments. At March 31, 2020 and 2019, other assets included approximately $5 million and $366 million, respectively, in cash and cash equivalents, $32 million and $68 million, respectively, in income taxes receivable, $23 million and $56 million, respectively, in property, plant and equipment, $10 million and $10 million, respectively, in unamortized debt expense, $9 million and $10 million, respectively, in prepayments, $5 million and $7 million, respectively, in a non-qualified retirement plan and $77 million and $25 million in right-of-use lease assets, respectively.

(5)Capital investments include increases of $8 million and $66 million for the three months ended March 31, 2020 and 2019, respectively, relating to the change in accrued expenditures between years.

(17) NEW ACCOUNTING PRONOUNCEMENTS

~~New Accounting Standards Implemented~~Recently Adopted

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

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

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

From an evaluation of the Company’s 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 partners. Update 2016-13 did not have a significant impact on the Company’s consolidated financial statements or related control environment upon adoption on January 1, 2020.

Issued but ~~does~~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 ~~believe it will~~expected to have a material impact on ~~its~~the Company’s consolidated financial ~~statements at this time.~~statements.

~~(19)CONDENSED CONSOLIDATING FINANCIAL INFORMATION~~

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

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

~~CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS~~

(in millions) Parent Guarantors Non-Guarantors Eliminations Consolidated
Three months ended March 31, 2018
Operating Revenues:
Gas sales $ —
$ 540
$ —
$ —
$ 540
Oil sales —
35
—
—
35
NGL sales —
65
—
—
65
Marketing —
253
—
—
253
Gas gathering —
24
—
—
24
Other —
3
—
—
3
—
920
—
—
920
Operating Costs and Expenses:
Marketing purchases —
255
—
—
255
Operating expenses —
189
—
—
189
General and administrative expenses —
55
—
—
55
Depreciation, depletion and amortization —
143
—
—
143
Taxes, other than income taxes —
23
—
—
23
—
665
—
—
665
Operating Income —
255
—
—
255
Interest Expense, Net 39
—
—
—
39
Loss on Derivatives —
(7 ) —
—
(7 )
Other Loss, Net —
(1 ) —
—
(1 )
Equity in Earnings of Subsidiaries 247
—
—
(247 ) —

Income (Loss) Before Income Taxes 208
247
—
(247 ) 208
Provision (Benefit) for Income Taxes —
—
—
—
—
Net Income (Loss) $ 208
$ 247
$ —
$ (247 ) $ 208
Participating securities - mandatory convertible preferred stock 3
—
—
—
3
Net Income (Loss) Attributable to
Common Stock $ 205
$ 247
$ —
$ (247 ) $ 205

Net Income (Loss) $ 208
$ 247
$ —
$ (247 ) $ 208
Other comprehensive income —
—
—
—
—
Comprehensive Income (Loss) $ 208
$ 247
$ —
$ (247 ) $ 208

~~CONDENSED CONSOLIDATED BALANCE SHEETS~~

(in millions) Parent Guarantors Non-Guarantors Eliminations Consolidated
December 31, 2018
ASSETS
Cash and cash equivalents $ 201
$ —
$ —
$ —
$ 201
Accounts receivable, net 4
577
—
—
581
Other current assets 8
166
—
—
174
Total current assets 213
743
—
—
956

Intercompany receivables 7,932
—
—
(7,932 ) —

Natural gas and oil properties, using the full cost method —
24,128
52
—
24,180
Gathering systems —
11
27
—
38
Other 197
290
—
—
487
Less: Accumulated depreciation, depletion and amortization (154 ) (19,840 ) (55 ) —
(20,049 )
Total property and equipment, net 43
4,589
24
—
4,656

Investments in subsidiaries (equity method) —
24
—
(24 ) —
Other long-term assets 19
166
—
—
185
TOTAL ASSETS $ 8,207
$ 5,522
$ 24
$ (7,956 ) $ 5,797

LIABILITIES AND EQUITY
Accounts payable $ 113
$ 496
$ —
$ —
$ 609
Other current liabilities 115
122
—
—
237
Total current liabilities 228
618
—
—
846

Intercompany payables —
7,932
—
(7,932 ) —

Long-term debt 2,318
—
—
—
2,318
Pension and other postretirement liabilities 46
—
—
—
46
Other long-term liabilities 54
171
—
—
225
Negative carrying amount of subsidiaries, net 3,199
—
—
(3,199 ) —
Total long-term liabilities 5,617
171
—
(3,199 ) 2,589
Commitments and contingencies

Total equity (accumulated deficit) 2,362
(3,199 ) 24
3,175
2,362
TOTAL LIABILITIES AND EQUITY $ 8,207
$ 5,522
$ 24
$ (7,956 ) $ 5,797

~~CONDENSED CONSOLIDATED STATEMENT OF CASH FLOWS~~

(in millions) Parent Guarantors Non-Guarantors Eliminations Consolidated
Three months ended March 31, 2019
Net cash provided by (used in) operating activities $ 1,031
$ 19
$ —
$ (608 ) $ 442
Investing activities:
Capital investments 3
(261 ) —
—
(258 )
Other —
—
—
—
—
Net cash used in investing activities 3
(261 ) —
—
(258 )
Financing activities
Intercompany activities (850 ) 242
—
608
—
Change in bank drafts outstanding 3
—
—
—
3
Purchase of treasury stock (21 ) —
—
—
(21 )
Cash paid for tax withholding (1 ) —
—
—
(1 )
Net cash provided by (used in) financing activities (869 ) 242
—
608
(19 )
Increase in cash and cash equivalents 165
—
—
—
165
Cash and cash equivalents at beginning of year 201
—
—
—
201
Cash and cash equivalents at end of period $ 366
$ —
$ —
$ —
$ 366

Three months ended March 31, 2018
Net cash provided by (used in) operating activities $ 183
$ 428
$ —
$ (247 ) $ 364
Investing activities:
Capital investments (5 ) (297 ) —
—
(302 )
Other —
8
—
—
8
Net cash used in investing activities (5 ) (289 ) —
—
(294 )
Financing activities
Intercompany activities (116 ) (131 ) —
247
—
Preferred stock dividend (27 ) —
—
—
(27 )
Cash paid for tax withholding (1 ) —
—
—
(1 )
Net cash provided by (used in) financing activities (144 ) (131 ) —
247
(28 )
Increase in cash and cash equivalents 34
8
—
—
42
Cash and cash equivalents at beginning of year 914
2
—
—
916
Cash and cash equivalents at end of period $ 948
$ 10
$ —
$ —
$ 958

The following updates information as to Southwestern Energy Company’s financial condition provided in our ~~2018~~2019 Annual Report and analyzes the changes in the results of operations between the three month periods ended March 31, ~~2019~~2020 and ~~2018.~~2019. For definitions of commonly used natural gas and oil terms used in this Quarterly Report, please refer to the “Glossary of Certain Industry Terms” provided in our ~~2018~~2019 Annual Report.

The following discussion contains forward-looking statements that involve risks and uncertainties. Our actual results could differ materially from those anticipated in forward-looking statements for many reasons, including the risks described in “Cautionary Statement About Forward-Looking Statements” in the forepart of this Quarterly Report, in Item 1A, “Risk Factors” in Part I and elsewhere in our ~~2018~~2019 Annual Report, and Item 1A, “Risk Factors” in Part II in this Quarterly Report and any other quarterly report on Form 10-Q filed during the fiscal year. You should read the following discussion with our consolidated financial statements and the related notes included in this Quarterly Report.

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 ~~refer~~call “Marketing” but previously referred to as ~~“Midstream.”~~“Midstream” when it included the operations of gathering systems. We conduct most of our businesses through subsidiaries, and we currently operate exclusively in the lower 48 United States. ~~Our historical financial and operating results include the Fayetteville Shale E&P and related midstream gathering businesses which were sold in early December 2018.~~

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

~~Midstream.~~Marketing. Our marketing activities capture opportunities that arise through the marketing and transportation of natural gas, oil and NGLs primarily produced in our E&P operations. ~~In December 2018, we divested almost all of our gathering assets as part of the Fayetteville Shale sale.~~

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

•Net ~~income attributable~~loss of $1,547 million, or ($2.86) per diluted share, decreased compared to ~~common stock~~net income of $594 million, or $1.10 per diluted share, ~~increased 190% compared to net income attributable to common stock of $205 million, or $0.36 per diluted share,~~ for the same period in ~~2018.~~2019. The ~~increase~~decrease was primarily due to a ~~$426~~$1,479 million ~~deferred income tax benefit recorded during the first quarter of 2019 resulting from the release of~~non-cash full cost ceiling test impairment and a $408 million tax valuation allowance, ~~previously recorded against our deferred tax assets.~~which were only partially offset by a $371 million positive impact of derivatives, including a $103 million improvement in settled derivatives as compared to the same period in 2019.

•Operating ~~income~~loss of ~~$213~~$1,490 million decreased ~~16%~~ compared to operating income of ~~$255~~$213 million for the same period in ~~2018~~2019 on a consolidated ~~basis. The decrease was~~basis primarily due to a $1,479 million non-cash full cost ceiling test impairment in the ~~divestiture~~first quarter of 2020. Excluding the ~~Fayetteville Shale E&P and related midstream gathering assets on December 3, 2018.~~non-cash impairment, operating loss of $11 million decreased 105% compared to the same period in 2019 primarily due to lower margins associated with reduced commodity prices.

•Net cash provided by operating activities of ~~$442~~$160 million ~~increased 21%~~decreased 64% from ~~$364~~$442 million for the same period in ~~2018~~2019 primarily due to the decrease in operating income net of depreciation, depletion and amortization and impairments, and a ~~positive change~~reduction in net cash flow associated with working ~~capital.~~capital, partially offset by the improvement in settled derivatives discussed above.

•Total capital investing of ~~$325~~$237 million decreased 4%27% from ~~$338~~$325 million for the same period in ~~2018.~~2019.

~~The Company~~•We repurchased ~~5.3~~$80 million ~~shares~~in aggregate principal amount of ~~its common stock for approximately $21~~our outstanding senior notes at a discount and recognized a gain on the extinguishment of debt of $28 million.

•E&P segment operating loss of $1,486 million decreased from operating income of $210 ~~million decreased 12% from $238~~ million for the same period in ~~2018.~~2019, primarily related to the non-cash impairment of $1,479 million in the first quarter of 2020.

•Total net production of ~~182~~201 Bcfe, which was comprised of ~~79%~~78% natural gas and ~~21%~~22% oil and NGLs, and oil. E&P segment production volumes of 226 Bcfe for the first quarter of 2018 include 67 Bcf of production related to our operations in the Fayetteville Shale, which was sold in December 2018. Excluding the impact of the production related to the sold Fayetteville Shale assets, our production increased ~~14%~~10% from ~~159~~182 Bcfe in the same period in ~~2018.~~2019, and our liquids production increased 17% over the same period primarily associated with our oil production.

•Excluding the effect of derivatives, our realized natural gas price of ~~$2.95~~$1.53 per Mcf ~~increased 8% from the same period in 2018,~~decreased 48%, our realized oil price of ~~$45.48~~$36.72 per barrel decreased 19% ~~from the same period in 2018~~ and our realized NGL price of ~~$14.45~~$8.16 per barrel decreased ~~6% from~~44% as compared to the same period in ~~2018.~~2019. Our total weighted average realized price excluding the effect of derivatives of ~~$2.98~~$1.69 per Mcfe ~~increased 6%~~decreased 43% from the same period in ~~2018.~~2019.



Class						Outstanding as of April ~~23, 2019~~28, 2020
Common Stock, Par Value $0.01						~~541,156,741~~541,688,616



PART I – FINANCIAL INFORMATION						Page

Item 1.		Financial Statements			3
		Consolidated Statements of Operations			3
		Consolidated Statements of Comprehensive Income ~~(Loss)~~			4
		Consolidated Balance Sheets			5
		Consolidated Statements of Cash Flows			6
		Consolidated Statements of Changes in Equity			7
		Notes to Consolidated Financial Statements			8
			Note 1. Basis of Presentation	8
			Note 2. ~~Divestitures~~Restructuring Charges	8
			Note 3. ~~Restructuring Charges~~Revenue Recognition	9
			Note 4. ~~Leases~~	9
	~~Note 5. Revenue Recognition~~	11
	~~Note 6.~~ Cash and Cash Equivalents	1311
			Note 7.5. Natural Gas and Oil Properties	1311
			Note 8.6. Earnings per Share	1411
			Note 9.7. Derivatives and Risk Management	1513
			Note ~~10.~~8. Reclassifications From Accumulated Other Comprehensive Income (Loss)	20
			Note ~~11.~~9. Fair Value Measurements	20
			Note ~~12.~~10. Debt	2322
			Note ~~13.~~1 1 . Commitments and Contingencies	2524
			Note ~~14.~~1 2 . Income Taxes	26
			Note ~~15.~~1 3 . Pension Plan and Other Postretirement Benefits	2726
			Note ~~16.~~1 4 . Stock-Based Compensation	27
			Note ~~17.~~1 5 . Segment Information	30
			Note ~~18.~~1 6 . New Accounting Pronouncements	31
	~~Note 19. Condensed Consolidated Financial Information~~	31
Item 2.		Management’s Discussion and Analysis of Financial Condition and Results of Operations			3631
		Results of Operations			3834
		Liquidity and Capital Resources			4440
Item 3.		Quantitative and Qualitative Disclosures About Market Risk			4845
Item 4.		Controls and Procedures			4845

PART II – OTHER INFORMATION

Item 1.		Legal Proceedings			5046
Item 1A.		Risk Factors			5047
Item 2.		Unregistered Sales of Equity Securities and Use of Proceeds			5047
Item 3.		Defaults Upon Senior Securities			5047
Item 4.		Mine Safety Disclosures			5047
Item 5.		Other Information			5047
Item 6.		Exhibits			5048



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

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

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

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

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

Interest rate swaps			Interest rate swaps are used to fix or float interest rates on existing or anticipated indebtedness. The purpose of these instruments is to manage the Company’s existing or anticipated exposure to unfavorable interest rate changes.


~~(1)~~	~~For the three months ended March 31, 2018, deferred tax activity incurred in other comprehensive income was offset by a valuation allowance.~~



	Common Stock				Preferred Stock		Additional Paid-In Capital			Accumulated Deficit			Accumulated Other Comprehensive Income (Loss)			Common Stock in Treasury				Total
	Shares Issued		Amount		Shares Issued		Additional Paid-In Capital			Accumulated Deficit			Accumulated Other Comprehensive Income (Loss)			Shares	Amount			Total
	(in millions, except share amounts)
Balance at December 31, 2017	512,134,311		$	5	1,725,000		$	4,698		$	(2,679	)	$	(44	)	31,269	$	(1	)	$	1,979
Comprehensive income:
Net income	—		—		—		—			208			—			—	—			208
Other comprehensive income	—		—		—		—			—			—			—	—			—
Total comprehensive income	—		—		—		—			—			—			—	—			208
Stock-based compensation	—		—		—		7			—			—			—	—			7
Conversion of preferred stock	74,998,614		1		(1,725,000	)	(1		)	—			—			—	—			—
Issuance of restricted stock	5,076		—		—		—			—			—			—	—			—
Cancellation of restricted stock	(160,168	)	—		—		—			—			—			—	—			—
Performance units vested	214,866		—		—		—			—			—			—	—			—
Tax withholding – stock compensation	(338,808	)	—		—		(1		)	—			—			—	—			(1		)
Balance at March 31, 2018	586,853,891		$	6	—		$	4,703		$	(2,471	)	$	(44	)	31,269	$	(1	)	$	2,193



	For the three months ended
(in millions)	March 31, 2019
Severance (including payroll taxes)	$	2
Office consolidation	1
Total restructuring charges⁽¹⁾	$	3



	March 31, 2019
Right-of-use asset balance: (in millions)
Operating leases	$	100
Lease liability balance: (in millions)
Short-term operating leases	$	38
Long-term operating leases	62
Total operating leases	$	100

Weighted average remaining lease term: (years)
Operating leases	4.1

Weighted average discount rate:
Operating leases	5.86		%



(in millions)	E&P		Midstream		Intersegment Revenues			Total
Three months ended March 31, 2019
Gas sales	$	421	$	—	$	9		$	430
Oil sales	39		—		—			39
NGL sales	81		—		—			81
Marketing	—		940		(502		)	438
Other ⁽¹⁾	1		1		—			2
Total	$	542	$	941	$	(493	)	$	990

Three months ended March 31, 2018
Gas sales	$	535	$	—	$	5		$	540
Oil sales	34		—		1			35
NGL sales	65		—		—			65
Marketing	—		829		(576		)	253
Gas gathering ⁽²⁾	—		67		(43		)	24
Other ⁽¹⁾	3		—		—			3
Total	$	637	$	896	$	(613	)	$	920


~~(1)~~	~~Other E&P revenues consists primarily of water sales to third-party operators, and other Midstream revenues consists primarily of sales of gas from storage.~~


~~(2)~~	~~The Company’s gas gathering assets were divested in December 2018 as part of the Fayetteville Shale sale.~~


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



	For the three months ended March 31,
	2019	2018
Unexercised stock options	5,128,640	—
Unvested share-based payment	1,881,355	5,292,454
Performance units	260,201	574,944
Mandatory convertible preferred stock	—	9,999,815
Total	7,270,196	15,867,213



	Volume (MBbls)	Weighted Average Strike Price per Bbl								Fair Value at March 31, 2019 (in millions)
	Volume (MBbls)	Swaps		Sold Puts		Purchased Puts		Sold Calls		Fair Value at March 31, 2019 (in millions)
Oil
2019
Fixed price swaps⁽¹⁾	921	$	62.13	$	—	$	—	$	—	$	1
Two-way costless collars	248	—		—		65.00		72.30		1
Three-way costless collars	412	—		45.00		55.00		63.67		—
Total	1,581									$	2
2020
Fixed price swaps	366	$	65.68	$	—	$	—	$	—	$	3
Two-way costless collars	366	—		—		60.00		69.80		2
Total	732									$	5

Propane
2019
Fixed price swaps	2,028	$	31.25	$	—	$	—	$	—	$	7
2020
Fixed price swaps	824	$	27.35	$	—	$	—	$	—	$	—
Two-way costless collars	366	—		—		25.20		29.40		—
Total	1,190									$	—

Ethane
2019
Fixed price swaps	2,778	$	13.90	$	—	$	—	$	—	$	10
2020
Fixed price swaps	732	$	13.49	$	—	$	—	$	—	$	2



	Volume (Bcf)	Weighted Average Strike Price per MMBtu		Basis Differential per MMBtu			Fair Value at March 31, 2019 ($ in millions)
Storage ⁽¹⁾
2019
Purchased fixed price swaps	1	$	2.87	$	—		$	—
Purchased basis swaps	1	—		(0.53		)	—
Total							$	—

2020
Fixed price swap	1	$	3.14	$	—		$	—



		Pension Benefits
	Consolidated Statements of Operations Classification of Net Periodic Benefit Cost ⁽¹⁾	For the three months ended March 31,
(in millions)		2019			2018
Service cost	General and administrative expenses	$	2		$	3
Interest cost	Other Income (Loss), Net	1			2
Expected return on plan assets	Other Income (Loss), Net	(2		)	(2		)
Amortization of prior service cost	Other Income (Loss), Net	—			—
Amortization of net loss	Other Income (Loss), Net	1			—
Net periodic benefit cost		$	2		$	3



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


~~(1)~~	~~Operating income for the E&P segment includes $3 million of restructuring charges for the three months ended March 31, 2019.~~


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


~~(3)~~	Includes office, technology, water infrastructure, drilling rigs and other ancillary equipment not directly related to natural gas and oil properties. 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 March 31, 2019 and 2018, other assets included approximately $366 million and $958 million, respectively, in cash and cash equivalents.


~~(5)~~	~~Capital investments include increases of $66 million and $33 million for the three months ended March 31, 2019 and 2018, respectively, relating to the change in accrued expenditures between years.~~


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


~~(7)~~	~~Includes a $10 million impairment related to certain non-core gathering assets.~~



(in millions)	Parent		Guarantors			Non-Guarantors		Eliminations			Consolidated
Three months ended March 31, 2019
Operating Revenues:
Gas sales	$	—	$	430		$	—	$	—		$	430
Oil sales	—		39			—		—			39
NGL sales	—		81			—		—			81
Marketing	—		438			—		—			438
Other	—		2			—		—			2
	—		990			—		—			990
Operating Costs and Expenses:
Marketing purchases	—		441			—		—			441
Operating expenses	—		165			—		—			165
General and administrative expenses	—		37			—		—			37
Restructuring charges	—		3			—		—			3
Depreciation, depletion and amortization	—		112			—		—			112
Taxes, other than income taxes	—		19			—		—			19
	—		777			—		—			777
Operating Income	—		213			—		—			213
Interest Expense, Net	14		—			—		—			14
Loss on Derivatives	—		(32		)	—		—			(32		)
Other Income, Net	—		1			—		—			1
Equity in Earnings of Subsidiaries	608		—			—		(608		)	—

Income (Loss) Before Income Taxes	594		182			—		(608		)	168
Benefit from Income Taxes	—		(426		)	—		—			(426		)
Net Income (Loss)	594		608			—		(608		)	594

Net Income (Loss)	$	594	$	608		$	—	$	(608	)	$	594
Other comprehensive income	—		—			—		—			—
Comprehensive Income (Loss)	$	594	$	608		$	—	$	(608	)	$	594


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


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


	For the three months ended March 31,					Increase/(Decrease)
Production volumes:	2020		2019
Natural Gas (Bcf)
Northeast Appalachia	114		112		2%
Southwest Appalachia	42		31		35%

Total	156		143		9%

Oil (MBbls)
Southwest Appalachia	1,395		849		64%
Other	4		5		(20)%
Total	1,399		854		64%

NGL (MBbls)
Southwest Appalachia	6,127		5,602		9%
Other	1		1		—%
Total	6,128		5,603		9%

Production volumes by area: (Bcfe)
Northeast Appalachia	114		112		2%
Southwest Appalachia⁽¹⁾	87		70		24%

Total	201		182		10%

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



	For the three months ended March 31,				Increase/ (Decrease)
Production volumes:	2019		2018		Increase/ (Decrease)
Natural Gas (Bcf)
Northeast Appalachia	112		108		4%
Southwest Appalachia	31		22		41%
Fayetteville Shale ⁽¹⁾	—		67		(100%)
Total	143		197		(27%)

Oil (MBbls)
Southwest Appalachia	849		594		43%
Other	5		19		(74%)
Total	854		613		39%

NGL (MBbls)
Southwest Appalachia	5,602		4,218		33%
Other	1		12		(92%)
Total	5,603		4,230		32%

Production volumes by area: (Bcfe)
Northeast Appalachia	112		108		4%
Southwest Appalachia	70		51		37%
Fayetteville Shale ⁽¹⁾	—		67		(100%)
Other	—		—		—%
Total	182		226		(19%)

Production percentage: (Bcfe)
Natural gas	79	%	87	%
Oil	3	%	2	%
NGL	18	%	11	%
Total	100	%	100	%


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


~~(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.~~



	Volume (Bcf)	Basis Differential
Basis Swaps - Natural Gas
2019	85	$	(0.50	)
2020	59	(0.44		)
Total	144

Physical NYMEX Sales Arrangements - Natural Gas
2019	157	$	(0.31	)
2020	53	(0.19		)
Total	210


	Remaining 2019	Full Year 2020	Full Year 2021		Remaining 2020	Full Year 2021	Full Year 2022
Natural gas (Bcf)	340	146	37	Natural gas (Bcf)	438	330	120
Oil (MBbls)	1,581	732	—	Oil (MBbls)	4,383	3,773	1,104
Ethane (MBbls)				Ethane (MBbls)	6,952	3,017	—
Propane (MBbls)	2,028	1,190	—	Propane (MBbls)	4,324	2,460	—
Ethane (MBbls)	2,778	732	—
Total financial protection on future production (Bcfe)	378	162	37	Total financial protection on future production (Bcfe)	532	386	127