SOUTHWESTERN ENERGY CO - Quarter Report: 2019 June (Form 10-Q)

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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q

(Mark One)

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

Exchange Act of 1934

For the quarterly period ended June 30, 2019

☐ Transition Report pursuant to Section 13 or 15(d) of the Securities

Exchange Act of 1934

For the transition period from ________ to ________

Commission file number: 001-08246

Southwestern Energy Company

(Exact name of registrant as specified in its charter)



Delaware		71-0205415
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)

10000 Energy Drive
Spring,	Texas	77389
(Address of principal executive offices)		(Zip Code)

(832) 796-1000

(Registrant’s telephone number, including area code)

Not Applicable

(Former name, former address and former fiscal year, if changed since last report)

Securities registered pursuant to Section 12(b) of the Act:



Title of each class	Trading Symbol(s)	Name of each exchange on which registered
Common Stock, Par Value $0.01	SWN	New York Stock Exchange

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ☒ No ☐

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes ☒ No ☐

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer”, “accelerated filer”, “smaller reporting company” and “emerging growth company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer

☒

Accelerated filer

☐

Non-accelerated filer

☐

Smaller reporting company

☐

Emerging growth company

☐

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

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

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



Class		Outstanding as of August 2, 2019
Common Stock, Par Value $0.01		541,316,769

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SOUTHWESTERN ENERGY COMPANY

INDEX TO FORM 10-Q

FOR THE QUARTERLY PERIOD ENDED JUNE 30, 2019



PART I – FINANCIAL INFORMATION			Page

Item 1.	Financial Statements		3
	Consolidated Statements of Operations		3
	Consolidated Statements of Comprehensive Income		4
	Consolidated Balance Sheets		5
	Consolidated Statements of Cash Flows		6
	Consolidated Statements of Changes in Equity		7
	Notes to Consolidated Financial Statements		8
		Note 1. Basis of Presentation	8
		Note 2. Divestitures	8
		Note 3. Restructuring Charges	9
		Note 4. Leases	9
		Note 5. Revenue Recognition	11
		Note 6. Cash and Cash Equivalents	14
		Note 7. Natural Gas and Oil Properties	14
		Note 8. Earnings per Share	14
		Note 9. Derivatives and Risk Management	15
		Note 10. Reclassifications From Accumulated Other Comprehensive Income (Loss)	22
		Note 11. Fair Value Measurements	22
		Note 12. Debt	26
		Note 13. Commitments and Contingencies	28
		Note 14. Income Taxes	29
		Note 15. Pension Plan and Other Postretirement Benefits	30
		Note 16. Stock-Based Compensation	30
		Note 17. Segment Information	33
		Note 18. New Accounting Pronouncements	34
		Note 19. Condensed Consolidated Financial Information	35
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		42
	Results of Operations		44
	Liquidity and Capital Resources		51
Item 3.	Quantitative and Qualitative Disclosures About Market Risk		56
Item 4.	Controls and Procedures		56

PART II – OTHER INFORMATION

Item 1.	Legal Proceedings		57
Item 1A.	Risk Factors		57
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds		57
Item 3.	Defaults Upon Senior Securities		57
Item 4.	Mine Safety Disclosures		57
Item 5.	Other Information		57
Item 6.	Exhibits		58

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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 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,” “target” or similar words.

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


•	the timing and extent of changes in market conditions and prices for natural gas, oil and natural gas liquids (“NGLs”) (including regional basis differentials);


•	our ability to fund our planned capital investments;


•	a change in our credit rating; an increase in interest rates and any adverse impacts from the discontinuation of 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;


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


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


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


•	our ability to realize the expected benefits from acquisitions;


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


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


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


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


•	the effects of weather;


•	increased competition;


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


•	the comparative cost of alternative fuels;


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


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

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

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

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PART I – FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

SOUTHWESTERN ENERGY COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)



	For the three months ended June 30,						For the six months ended June 30,
(in millions, except share/per share amounts)	2019			2018			2019			2018
Operating Revenues:
Gas sales	$	275		$	407		$	705		$	947
Oil sales	47			44			86			79
NGL sales	58			75			139			140
Marketing	287			265			725			518
Gas gathering	—			24			—			48
Other	—			1			2			4
	667			816			1,657			1,736
Operating Costs and Expenses:
Marketing purchases	293			265			734			520
Operating expenses	169			193			334			382
General and administrative expenses	40			59			77			114
Loss on sale of operating assets	3			—			3			—
Restructuring charges	2			18			5			18
Depreciation, depletion and amortization	121			142			233			285
Taxes, other than income taxes	17			15			36			38
	645			692			1,422			1,357
Operating Income	22			124			235			379
Interest Expense:
Interest on debt	41			59			83			124
Other interest charges	2			2			3			4
Interest capitalized	(28		)	(29		)	(57		)	(57		)
	15			32			29			71

Gain (Loss) on Derivatives	152			(36		)	120			(43		)
Loss on Early Extinguishment of Debt	—			(8		)	—			(8		)
Other Income (Loss), Net	(6		)	3			(5		)	2

Income Before Income Taxes	153			51			321			259
Provision (Benefit) for Income Taxes
Current	—			—			—			—
Deferred	15			—			(411		)	—
	15			—			(411		)	—
Net Income	$	138		$	51		$	732		$	259
Participating securities - mandatory convertible preferred stock	—			—			—			2
Net Income Attributable to Common Stock	$	138		$	51		$	732		$	257

Earnings Per Common Share
Basic	$	0.26		$	0.09		$	1.36		$	0.45
Diluted	$	0.26		$	0.09		$	1.35		$	0.44

Weighted Average Common Shares Outstanding:
Basic	539,005,941			581,159,200			539,362,984			576,255,744
Diluted	539,947,053			582,878,106			540,624,742			578,222,740

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

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SOUTHWESTERN ENERGY COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Unaudited)



	For the three months ended June 30,				For the six months ended June 30,
(in millions)	2019		2018 ⁽¹⁾		2019		2018⁽¹⁾
Net income	$	138	$	51	$	732	$	259

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

Comprehensive income	$	142	$	51	$	736	$	259


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


(2)	Primarily related to settlement of pension assets in the second quarter of 2019. Net of $1 million in taxes for the three and six months ended June 30, 2019.

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

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SOUTHWESTERN ENERGY COMPANY AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(Unaudited)



	June 30, 2019			December 31, 2018
ASSETS	(in millions)
Current assets:
Cash and cash equivalents	$	155		$	201
Accounts receivable, net	358			581
Derivative assets	209			130
Other current assets	42			44
Total current assets	764			956
Natural gas and oil properties, using the full cost method, including $1,678 million as of June 30, 2019 and $1,755 million as of December 31, 2018 excluded from amortization	24,823			24,180
Other	555			525
Less: Accumulated depreciation, depletion and amortization	(20,279		)	(20,049		)
Total property and equipment, net	5,099			4,656
Deferred tax assets	410			—
Other long-term assets	272			185
TOTAL ASSETS	$	6,545		$	5,797
LIABILITIES AND EQUITY
Current liabilities:
Current portion of long-term debt	$	52		$	—
Accounts payable	585			609
Taxes payable	52			58
Interest payable	53			52
Derivative liabilities	67			79
Other current liabilities	103			48
Total current liabilities	912			846
Long-term debt	2,267			2,318
Pension and other postretirement liabilities	39			46
Other long-term liabilities	245			225
Total long-term liabilities	2,551			2,589
Commitments and contingencies (Note 13)
Equity:
Common stock, $0.01 par value; 1,250,000,000 shares authorized; issued 585,478,345 shares as of June 30, 2019 and 585,407,107 shares as of December 31, 2018	6			6
Additional paid-in capital	4,720			4,715
Accumulated deficit	(1,410		)	(2,142		)
Accumulated other comprehensive loss	(32		)	(36		)
Common stock in treasury, 44,353,224 shares as of June 30, 2019 and 39,092,537 shares as of December 31, 2018	(202		)	(181		)
Total equity	3,082			2,362
TOTAL LIABILITIES AND EQUITY	$	6,545		$	5,797

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

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SOUTHWESTERN ENERGY COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)



	For the six months ended June 30,
(in millions)	2019			2018
Cash Flows From Operating Activities:
Net income	$	732		$	259
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization	233			285
Amortization of debt issuance costs	2			4
Deferred income taxes	(411		)	—
(Gain) loss on derivatives, unsettled	(96		)	54
Stock-based compensation	4			9
Loss on early extinguishment of debt	—			8
Loss on sale of assets, net	3			—
Other	10			1
Change in assets and liabilities:
Accounts receivable	221			12
Accounts payable	(129		)	53
Taxes payable	(6		)	(4		)
Interest payable	1			(1		)
Inventories	4			(7		)
Other assets and liabilities	(25		)	(9		)
Net cash provided by operating activities	543			664

Cash Flows From Investing Activities:
Capital investments	(586		)	(684		)
Proceeds from sale of property and equipment	26			6
Other	—			3
Net cash used in investing activities	(560		)	(675		)

Cash Flows From Financing Activities:
Payments on long-term debt	—			(1,191		)
Payments on revolving credit facility	—			(645		)
Borrowings under revolving credit facility	—			1,005
Change in bank drafts outstanding	(7		)	—
Debt issuance costs	—			(9		)
Purchase of treasury stock	(21		)	—
Preferred stock dividend	—			(27		)
Cash paid for tax withholding	(1		)	(1		)
Net cash used in financing activities	(29		)	(868		)

Decrease in cash and cash equivalents	(46		)	(879		)
Cash and cash equivalents at beginning of year	201			916
Cash and cash equivalents at end of period	$	155		$	37

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

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SOUTHWESTERN ENERGY COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY

(Unaudited)



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

	(in millions, except share amounts)
Balance at December 31, 2018	585,407,107		$	6	$	4,715		$	(2,142	)	$	(36	)	39,092,537	$	(181	)	$	2,362
Comprehensive income:
Net income	—		—		—			594			—			—	—			594
Other comprehensive income	—		—		—			—			—			—	—			—
Total comprehensive income	—		—		—			—			—			—	—			594
Stock-based compensation	—		—		3			—			—			—	—			3
Issuance of restricted stock	8,798		—		—			—			—			—	—			—
Cancellation of restricted stock	(128,324	)	—		—			—			—			—	—			—
Treasury stock	—		—		—			—			—			5,260,687	(21		)	(21		)
Performance units vested	535,802		—		—			—			—			—	—			—
Tax withholding – stock compensation	(274,657	)	—		(1		)	—			—			—	—			(1		)
Balance at March 31, 2019	585,548,726		$	6	$	4,717		$	(1,548	)	$	(36	)	44,353,224	$	(202	)	$	2,937
Comprehensive income:
Net income	—		—		—			138			—			—	—			138
Other comprehensive income	—		—		—			—			4			—	—			4
Total comprehensive income	—		—		—			—			—			—	—			142
Stock-based compensation	—		—		3			—			—			—	—			3
Issuance of restricted stock	6,424		—		—			—			—			—	—			—
Cancellation of restricted stock	(72,555	)	—		—			—			—			—	—			—
Tax withholding – stock compensation	(4,250	)	—		—			—			—			—	—			—
Balance at June 30, 2019	585,478,345		$	6	$	4,720		$	(1,410	)	$	(32	)	44,353,224	$	(202	)	$	3,082



	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
Comprehensive income:
Net income	—		—		—		—			51			—			—	—			51
Other comprehensive income	—		—		—		—			—			—			—	—			—
Total comprehensive income	—		—		—		—			—			—			—	—			51
Stock-based compensation	—		—		—		6			—			—			—	—			6
Issuance of restricted stock	307,743		—		—		—			—			—			—	—			—
Cancellation of restricted stock	(722,465	)	—		—		—			—			—			—	—			—
Tax withholding – stock compensation	(9,068	)	—		—		—			—			—			—	—			—
Balance at June 30, 2018	586,430,101		$	6	—		$	4,709		$	(2,420	)	$	(44	)	31,269	$	(1	)	$	2,250

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

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SOUTHWESTERN ENERGY COMPANY AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

(1) BASIS OF PRESENTATION

Southwestern Energy Company (including its subsidiaries, collectively “Southwestern” or the “Company”) is an independent energy company engaged in natural gas, oil and NGL exploration, development and production (“E&P”). The Company is also focused on creating and capturing additional value through its marketing business (“Midstream”). Southwestern conducts most of its business through subsidiaries and operates principally in two segments: E&P and Midstream. The Company also operates 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.

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

Midstream. 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 (“2018 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 Annual Report.

(2) DIVESTITURES

On August 30, 2018, the Company entered into an agreement with Flywheel Energy Operating, LLC to sell 100% of the equity in the Company’s subsidiaries that owned and operated its Fayetteville Shale E&P and related midstream gathering assets for $1,865 million in cash, subject to customary closing adjustments, with an economic effective date of July 1, 2018. On December 3, 2018, the Company closed on the Fayetteville Shale sale and received approximately $1,650 million, which included 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 June 30, 2019, approximately $162 million of these contractual commitments remain of which the Company will reimburse the buyer for certain of these potential obligations up to approximately $82 million through 2020 depending on the buyer’s actual use. At June 30, 2019, the Company has recorded a $68 million liability for the estimated future payments.

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

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In June 2019, the Company sold non-core acreage for $25 million. There was no production or proved reserves associated with this acreage.

(3) RESTRUCTURING CHARGES

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. 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. 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 June 30, 2019, a liability of approximately $0.4 million for severance payments has been accrued for the remaining Fayetteville Shale sale-related employment terminations in 2019.

On June 27, 2018, the Company notified affected employees of a workforce reduction plan, which resulted primarily from a previously announced study of structural, process and organizational changes to enhance shareholder value and continues with respect to other aspects of the Company’s business activities. Affected employees were offered a severance package, which included a one-time cash payment depending on length of service and, if applicable, current value of a portion of equity awards that were forfeited.

The following table presents a summary of the restructuring charges included in Operating Income for the three and six months ended June 30, 2019 and 2018:



	For the three months ended June 30,				For the six months ended June 30,
(in millions)	2019		2018		2019		2018
Severance (including payroll taxes)	$	1	$	17	$	3	$	17
Office consolidation	1		—		2		—
Professional fees	—		1		—		1
Total restructuring charges⁽¹⁾	$	2	$	18	$	5	$	18


(1)	Total restructuring charges were $2 million and $5 million for the Company’s E&P segment for the three and six months ended June 30, 2019, respectively, and $16 million and $2 million for the Company’s E&P and Midstream segments, respectively, for the three and six months ended June 30, 2018.

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



(in millions)	June 30, 2019
Liability at December 31, 2018	$	5
Additions	5
Distributions	(10		)
Liability at June 30, 2019	$	—

(4) LEASES

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

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


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


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

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


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


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

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

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

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

The Company has a residual value guarantee related to its headquarters office 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. In July 2019, the headquarters office building was sold to a third party, which resulted in the Company making an immaterial short-fall payment to the building’s current lessor.

During July 2019, the Company terminated its existing lease agreement and entered into a new lease agreement for a smaller portion of the headquarters office building.

The components of lease costs are shown below:



	For the six months ended June 30, 2019
(in millions)	For the six months ended June 30, 2019
Operating lease cost	$	22
Short-term lease cost	31
Variable lease cost	—
Total lease cost	$	53

As of June 30, 2019, the Company has operating leases of $4 million, related primarily to compressor leases, that have been executed but not yet commenced. These operating leases are planned to commence during 2019 with lease terms expiring through 2022. The Company’s existing operating leases do not contain any material restrictive covenants.

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



	For the six months ended June 30, 2019
(in millions)	For the six months ended June 30, 2019
Cash paid for amounts included in the measurement of lease liabilities:
Operating cash flows from operating leases	$	22

Right-of use assets obtained in exchange for new operating liabilities:
Operating leases	$	6

Supplemental balance sheet information related to leases is as follows:



Right-of-use asset balance: (in millions)	June 30, 2019
Operating leases	$	103
Lease liability balance: (in millions)
Short-term operating leases	$	47
Long-term operating leases	56
Total operating leases	$	103

Weighted average remaining lease term: (years)
Operating leases	3.8

Weighted average discount rate:
Operating leases	6.28		%

Maturity analysis of operating lease liabilities:



(in millions)	June 30, 2019
2019	$	22
2020	42
2021	19
2022	10
2023	8
2024	5
Thereafter	9
Total undiscounted lease liability	115
Imputed interest	(12		)
Total discounted lease liability	$	103



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

(5) REVENUE RECOGNITION

Revenues from Contracts with Customers

Natural gas and liquids. Natural gas, oil and natural gas liquid (“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

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revenue in the amount to 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 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 as well as other joint interest owners who choose to market with Southwestern. 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 to which the Company has a right to invoice and has not disclosed information regarding its remaining performance obligations.

Gas gathering. 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.

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Disaggregation of Revenues

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



(in millions)	E&P		Midstream		Intersegment Revenues			Total
Three months ended June 30, 2019
Gas sales	$	267	$	—	$	8		$	275
Oil sales	46		—		1			47
NGL sales	58		—		—			58
Marketing	—		626		(339		)	287
Total	$	371	$	626	$	(330	)	$	667

Three months ended June 30, 2018
Gas sales	$	400	$	—	$	7		$	407
Oil sales	44		—		—			44
NGL sales	75		—		—			75
Marketing	—		728		(463		)	265
Gas gathering ⁽¹⁾	—		69		(45		)	24
Other ⁽²⁾	1		—		—			1
Total	$	520	$	797	$	(501	)	$	816



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

Six months ended June 30, 2018
Gas sales	$	935	$	—	$	12		$	947
Oil sales	78		—		1			79
NGL sales	140		—		—			140
Marketing	—		1,557		(1,039		)	518
Gas gathering ⁽¹⁾	—		136		(88		)	48
Other ⁽²⁾	4		—		—			4
Total	$	1,157	$	1,693	$	(1,114	)	$	1,736


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


(2)	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.

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 June 30,				For the six months ended June 30,
(in millions)	2019		2018		2019		2018
Northeast Appalachia	$	217	$	213	$	565	$	540
Southwest Appalachia	153		166		346		322
Fayetteville Shale	—		139		—		291
Other	1		2		2		4
Total	$	371	$	520	$	913	$	1,157

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Receivables from Contracts with Customers

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



(in millions)	June 30, 2019		December 31, 2018
Receivables from contracts with customers	$	238	$	494
Other accounts receivable	120		87
Total accounts receivable	$	358	$	581

Amounts recognized against the Company’s allowance for doubtful accounts related to receivables arising from contracts with customers were immaterial for the three and six months ended June 30, 2019 and 2018. The Company has no contract assets or contract liabilities associated with its revenues from contracts with customers.

(6) CASH AND CASH EQUIVALENTS

The following table presents a summary of cash and cash equivalents as of June 30, 2019 and December 31, 2018:



(in millions)	June 30, 2019		December 31, 2018
Cash	$	71	$	32
Marketable securities ⁽¹⁾	69		169
Other cash equivalents ⁽²⁾	15		—
Total	$	155	$	201


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


(2)	Consists of time deposits.

(7) 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.

Using the average quoted price from the first day of each month from the previous 12 months for Henry Hub natural gas of $3.02 per MMBtu, West Texas Intermediate oil of $61.39 per barrel and NGLs of $16.35 per barrel, adjusted for differentials, the Company’s net book value of its United States natural gas and oil properties did not exceed the ceiling amount at June 30, 2019. The Company had no derivative positions that were designated for hedge accounting as of June 30, 2019. 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.

Using the average quoted price from the first day of each month from the previous 12 months for Henry Hub natural gas of $2.92 per MMBtu, West Texas Intermediate oil of $54.15 per barrel and NGLs of $15.56 per barrel, adjusted for differentials, the Company’s net book value of its United States natural gas and oil properties did not exceed the ceiling amount at June 30, 2018. The Company had no derivative positions that were designated for hedge accounting as of June 30, 2018.

(8) 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

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

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

The following table presents the computation of earnings per share for the three and six months ended June 30, 2019 and 2018:



	For the three months ended June 30,				For the six months ended June 30,
(in millions, except share/per share amounts)	2019		2018		2019		2018
Net income	$	138	$	51	$	732	$	259
Participating securities - mandatory convertible preferred stock	—		—		—		2
Net income attributable to common stock	$	138	$	51	$	732	$	257

Number of common shares:
Weighted average outstanding	539,005,941		581,159,200		539,362,984		576,255,744
Issued upon assumed exercise of outstanding stock options	—		—		—		—
Effect of issuance of non-vested restricted common stock	311,732		480,580		481,948		683,562
Effect of issuance of non-vested performance units	629,380		1,238,326		779,810		1,283,434
Weighted average and potential dilutive outstanding	539,947,053		582,878,106		540,624,742		578,222,740

Earnings per common share
Basic	$	0.26	$	0.09	$	1.36	$	0.45
Diluted	$	0.26	$	0.09	$	1.35	$	0.44

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



	For the three months ended June 30,		For the six months ended June 30,
	2019	2018	2019	2018
Unexercised stock options	5,114,763	—	5,121,663	—
Unvested share-based payment	1,773,074	4,335,715	1,822,346	5,152,847
Performance units	241,896	875,800	250,998	986,585
Mandatory convertible preferred stock	—	—	—	4,972,284
Total	7,129,733	5,211,515	7,195,007	11,111,716

(9) DERIVATIVES AND RISK MANAGEMENT

The Company is exposed to volatility in market prices and basis differentials for natural gas, oil and NGLs which impacts the predictability of its cash flows related to the sale of those commodities. These risks are managed by the Company’s use of certain derivative financial instruments. As of June 30, 2019, 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:



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.

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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, in aggregate, have no net cost. At the contract settlement date, (1) if the index price is higher than the sold call strike price, the Company pays the counterparty the difference between the index price and sold call strike price, (2) if the index price is between the purchased put strike price and the sold call strike price, no payments are due from either party, (3) if the index price is between the sold put strike price and the purchased put strike price, the Company will receive the difference between the purchased put strike price and the index price, and (4) if the index price is below the sold put strike price, the Company will receive the difference between the purchased put strike price and the sold put strike price.

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

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

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

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

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

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



Financial Protection on Production
		Weighted Average Price per MMBtu
	Volume (Bcf)	Swaps		Sold Puts		Purchased Puts		Sold Calls		Basis Differential			Fair Value at June 30, 2019 (in millions)
Natural Gas
2019
Fixed price swaps	131	$	2.92	$	—	$	—	$	—	$	—		$	75
Two-way costless collars	25	—		—		2.78		2.92		—			13
Three-way costless collars	67	—		2.47		2.88		3.22		—			22
Total	223												$	110
2020
Fixed price swaps	24	$	2.88	$	—	$	—	$	—	$	—		$	8
Three-way costless collars	148	—		2.36		2.67		2.97		—			10
Total	172												$	18
2021
Three-way costless collars	37	$	—	$	2.35	$	2.60	$	2.93	$	—		$	(1	)

Basis Swaps
2019	80	$	—	$	—	$	—	$	—	$	(0.45	)	$	(6	)
2020	132	—		—		—		—		(0.34		)	(10		)
2021	28	—		—		—		—		(0.51		)	(1		)
Total	240												$	(17	)

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	Volume (MBbls)	Weighted Average Strike Price per Bbl								Fair Value at June 30, 2019 (in millions)
	Volume (MBbls)	Swaps		Sold Puts		Purchased Puts		Sold Calls		Fair Value at June 30, 2019 (in millions)
Oil
2019
Fixed price swaps⁽¹⁾	1,003	$	60.89	$	—	$	—	$	—	$	4
Two-way costless collars	764	—		—		61.45		67.16		4
Three-way costless collars	276	—		45.00		55.00		63.67		—
Total	2,043									$	8
2020
Fixed price swaps	1,556	$	60.18	$	—	$	—	$	—	$	7
Two-way costless collars	366	—		—		60.00		69.80		3
Three-way costless collars	641	—		45.00		55.00		63.36		1
Total	2,563									$	11

Propane
2019
Fixed price swaps	1,955	$	30.18	$	—	$	—	$	—	$	14
Two-way costless collars	276	—		—		25.62		28.77		1
Total	2,231									$	15
2020
Fixed price swaps	2,196	$	26.97	$	—	$	—	$	—	$	6
Two-way costless collars	366	—		—		25.20		$	29.40	1
Total	2,562									$	7

Ethane
2019
Fixed price swaps	1,858	$	13.90	$	—	$	—	$	—	$	10
2020
Fixed price swaps	732	$	13.49	$	—	$	—	$	—	$	2


(1)	Includes 138 MBbls of purchased fixed price oil swaps hedged at $69.10 per barrel with a fair value of ($1) million and 1,141 MBbls of sold fixed price oil swaps hedged at $61.88 with a fair value of $5 million.



Other Derivative Contracts
	Volume (Bcf)	Weighted Average Strike Price per MMBtu		Fair Value at June 30, 2019 (in millions)
Purchased Call Options – Natural Gas
2019	17	$	3.50	$	—
2020	68	3.63		2
2021	57	3.52		2
Total	142			$	4

Sold Call Options – Natural Gas
2019	26	$	3.50	$	—
2020	137	3.39		(8		)
2021	114	3.33		(8		)
Total	277			$	(16	)

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	Volume (Bcf)	Weighted Average Strike Price per MMBtu		Basis Differential per MMBtu			Fair Value at June 30, 2019 ($ in millions)
Storage ⁽¹⁾
2019
Purchased fixed price swaps	1	$	2.87	$	—		$	(1	)
Purchased basis swaps	1	—		(0.53		)	—
Total	2						$	(1	)

2020
Fixed price swap	1	$	3.14	$	—		$	—


(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.

At June 30, 2019, the net fair value of the Company’s financial instruments related to commodities was a $150 million asset. The net fair value of the Company’s interest rate swaps was a $1 million liability as of June 30, 2019.

As of June 30, 2019, 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.

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



Derivative Assets
		Fair Value
(in millions)	Balance Sheet Classification	June 30, 2019			December 31, 2018
Derivatives not designated as hedging instruments:
Fixed price swaps – natural gas	Derivative assets	$	79		$	32
Fixed price swaps – oil	Derivative assets	7			13
Fixed price swaps – propane	Derivative assets	18			11
Fixed price swaps – ethane	Derivative assets	11			7
Two-way costless collars – natural gas	Derivative assets	13			11
Two-way costless collars – oil	Derivative assets	6			6
Two-way costless collars – propane	Derivative assets	2			—
Three-way costless collars – natural gas	Derivative assets	65			41
Three-way costless collars – oil	Derivative assets	2			—
Basis swaps – natural gas	Derivative assets	5			8
Purchased call options – natural gas	Derivative assets	1		⁽¹⁾	—
Interest rate swaps	Derivative assets	—			1
Fixed price swaps – natural gas	Other long-term assets	4			6
Fixed price swaps – oil	Other long-term assets	4			6
Fixed price swaps – propane	Other long-term assets	2			—
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	31			34
Three-way costless collars – oil	Other long-term assets	2			—
Basis swaps – natural gas	Other long-term assets	2			3
Purchased call options – natural gas	Other long-term assets	4			6
Total derivative assets		$	261		$	191



Derivative Liabilities
		Fair Value
(in millions)	Balance Sheet Classification	June 30, 2019		December 31, 2018
Derivatives not designated as hedging instruments:
Purchased fixed price swap – oil	Derivative liabilities	$	1	$	6
Fixed price swaps – natural gas	Derivative liabilities	—		9
Fixed price swaps – ethane	Derivative liabilities	—		3
Two-way costless collars – natural gas	Derivative liabilities	—		7
Two-way costless collars – oil	Derivative liabilities	1		—
Three-way costless collars – natural gas	Derivative liabilities	37		33
Three-way costless collars – oil	Derivative liabilities	2		—
Basis swaps – natural gas	Derivative liabilities	19		18
Sold call options – natural gas	Derivative liabilities	5		3
Storage – fixed price swap	Derivative liabilities	1		—
Interest rate swaps	Derivative liabilities	1		—
Fixed price swaps – natural gas	Other long-term liabilities	—		1
Two-way costless collars – oil	Other long-term liabilities	—		1
Three-way costless collars – natural gas	Other long-term liabilities	28		35
Three-way costless collars – oil	Other long-term liabilities	1		—
Basis swap – natural gas	Other long-term liabilities	5		4
Sold call options – natural gas	Other long-term liabilities	11		19
Total derivative liabilities		$	112	$	139

(1) 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 at June 30, 2019. As certain natural gas purchased call options 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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The following tables summarize the before-tax effect of the Company’s derivative instruments on the consolidated statements of operations for the three and six months ended June 30, 2019 and 2018:



Unsettled Gain (Loss) on Derivatives Recognized in Earnings

Derivative Instrument	Consolidated Statement of Operations Classification of Gain (Loss) on Derivatives, Unsettled	For the three months ended June 30,						For the six months ended June 30,
Derivative Instrument		2019			2018			2019			2018

		(in millions)
Purchased fixed price swaps – oil	Gain (Loss) on Derivatives	$	1		$	—		$	5		$	—
Fixed price swaps – natural gas	Gain (Loss) on Derivatives	57			(26		)	55			(29		)
Fixed price swaps – oil	Gain (Loss) on Derivatives	5			—			(8		)	—
Fixed price swaps – propane	Gain (Loss) on Derivatives	13			(12		)	9			(9		)
Fixed price swaps – ethane	Gain (Loss) on Derivatives	—			(2		)	7			(2		)
Two-way costless collars – natural gas	Gain (Loss) on Derivatives	10			(1		)	9			2
Two-way costless collars – oil	Gain (Loss) on Derivatives	4			—			(3		)	—
Two-way costless collars – propane	Gain (Loss) on Derivatives	2			—			2			—
Three-way costless collars – natural gas	Gain (Loss) on Derivatives	22			(24		)	24			(29		)
Three-way costless collars – oil	Gain (Loss) on Derivatives	1			—			1			—
Basis swaps – natural gas	Gain (Loss) on Derivatives	4			(4		)	(6		)	16
Purchased call options – natural gas	Gain (Loss) on Derivatives	(2		)	(12		)	(2		)	4
Sold call options – natural gas	Gain (Loss) on Derivatives	4			31			6			(3		)
Sold call options – oil	Gain (Loss) on Derivatives	—			(6		)	—			(6		)
Storage – fixed price swap	Gain (Loss) on Derivatives	(1		)	—			(1		)	—
Interest rate swaps	Gain (Loss) on Derivatives	(2		)	—			(2		)	2
Total gain (loss) on unsettled derivatives		$	118		$	(56	)	$	96		$	(54	)

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

Derivative Instrument	Consolidated Statement of Operations Classification of Gain (Loss) on Derivatives, Settled	For the three months ended June 30,						For the six months ended June 30,
Derivative Instrument		2019			2018			2019			2018

		(in millions)
Purchased fixed price swaps – oil	Gain (Loss) on Derivatives	$	(1	)	$	—		$	(2	)	$	—
Sold fixed price swaps – natural gas	Gain (Loss) on Derivatives	14			13			8			13
Sold fixed price swaps – oil	Gain (Loss) on Derivatives	2			—			4			—
Sold fixed price swaps – propane	Gain (Loss) on Derivatives	7			(1		)	9			(1		)
Sold fixed price swaps – ethane	Gain (Loss) on Derivatives	5			—			6			—
Two-way costless collars – natural gas	Gain (Loss) on Derivatives	3			—			2			4
Two-way costless collars – oil	Gain (Loss) on Derivatives	1			—			2			—
Three-way costless collars – natural gas	Gain (Loss) on Derivatives	8			12			4			19
Sold basis swaps – natural gas	Gain (Loss) on Derivatives	(4		)	(3		)	(8		)	(24		)
Purchased call options – natural gas	Gain (Loss) on Derivatives	—			—			—			2			⁽²⁾
Sold call options – natural gas	Gain (Loss) on Derivatives	(1		)	—			(1		)	(1		)
Sold call options – oil	Gain (Loss) on Derivatives	—			(1		)	—			(1		)
Total gain on settled derivatives		$	34		$	20		$	24		$	11

Total gain (loss) on derivatives		$	152		$	(36	)	$	120		$	(43	)


(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 six months ended June 30, 2018, which is included in gain (loss) on derivatives on the consolidated statements of operations.

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

In the first half of 2019, changes in accumulated other comprehensive income primarily related to settlements in the Company’s pension and other postretirement benefits. The following tables detail the components of accumulated other comprehensive income and the related tax effects for the six months ended June 30, 2019:



(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⁾	4			—			4
Net current-period other comprehensive income	4			—			4
Ending balance June 30, 2019	$	(18	)	$	(14	)	$	(32	)


(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 six months ended June 30, 2019
		(in millions)
Pension and other postretirement:
Amortization of prior service cost and net loss⁽¹⁾	Other Income, Net	$	5
	Provision for income taxes	1
	Net income	$	4

Total reclassifications for the period	Net income	$	4

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(1)	See Note 15 for additional details regarding the Company’s pension and other postretirement benefit plans.

(11) FAIR VALUE MEASUREMENTS

Assets and liabilities measured at fair value on a recurring basis

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



	June 30, 2019						December 31, 2018
(in millions)	Carrying Amount			Fair Value			Carrying Amount		Fair Value
Cash and cash equivalents	$	155		$	155		$	201	$	201
2018 revolving credit facility due April 2023	—			—			—		—
Senior notes⁽¹⁾	2,342			2,220			2,342		2,190
Derivative instruments, net	149		⁽²⁾	149		⁽²⁾	52		52


(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 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

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

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 fair value of all derivative instruments is the amount at which the instrument could be exchanged currently between willing parties. The amounts are based on quoted market prices, best estimates obtained from counterparties and an option pricing model, when necessary, for price option contracts.

The Company has classified its derivatives 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 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 June 30, 2019 are based on (i) the contracted notional amounts, (ii) active market-quoted London Interbank Offered Rate (“LIBOR”) yield curves and (iii) the applicable credit-adjusted risk-free rate yield curve.

The Company’s call 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.

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



	June 30, 2019
	Fair Value Measurements Using:
(in millions)	Quoted Prices in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)		Assets (Liabilities) at Fair Value
Assets
Fixed price swap – natural gas	$	—	$	83		$	—	$	83
Fixed price swap – oil	—		11			—		11
Fixed price swap – propane	—		20			—		20
Fixed price swap – ethane	—		12			—		12
Two-way costless collar – natural gas	—		13			—		13
Two-way costless collar – oil	—		8			—		8
Two-way costless collar – propane	—		2			—		2
Three-way costless collar – natural gas	—		96			—		96
Three-way costless collar – oil	—		4			—		4
Basis swap – natural gas	—		7			—		7
Purchased call option – natural gas ⁽¹⁾	—		5			—		5
Liabilities
Purchased fixed price swap – oil	—		(1		)	—		(1		)
Two-way costless collar – oil	—		(1		)	—		(1		)
Three-way costless collar – natural gas	—		(65		)	—		(65		)
Three-way costless collar – oil	—		(3		)	—		(3		)
Basis swap – natural gas	—		(24		)	—		(24		)
Sold call option – natural gas	—		(16		)	—		(16		)
Storage – fixed price swap	—		(1		)	—		(1		)
Interest rate swap	—		(1		)	—		(1		)
Total	$	—	$	149		$	—	$	149



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

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The table below presents reconciliations for the change in net fair value of derivative assets and liabilities measured at fair value on a recurring basis using significant unobservable inputs (Level 3) for the three and six months ended June 30, 2019 and 2018. The fair values of Level 3 derivative instruments were estimated using proprietary valuation models that utilized both market observable and unobservable parameters. Level 3 instruments presented in the table consisted of net derivatives valued using pricing models incorporating assumptions that, in the Company’s judgment, reflected reasonable assumptions a marketplace participant would have used as of June 30, 2018. Commodity derivatives previously presented as Level 3 were transferred to Level 2 in the second quarter of 2018 as the Company moved from using proprietary volatility inputs and forward curves to more widely available published information, increasing market observability.

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	For the three months ended June 30,						For the six months ended June 30,
(in millions)	2019		2018				2019		2018
Balance at beginning of period	$	—	$	22			$	—	$	22
Total gains (losses):
Included in earnings	—		(8		)		—		(17		)
Settlements	—		(8		)		—		1			⁽¹⁾
Transfers into/out of Level 3	—		(6		)	⁽²⁾	—		(6		)	⁽²⁾
Balance at end of period	$	—	$	—			$	—	$	—
Change in gains (losses) included in earnings relating to derivatives still held as of June 30	$	—	$	—			$	—	$	—


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


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

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(12) DEBT

The components of debt as of June 30, 2019 and December 31, 2018 consisted of the following:



	June 30, 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 (3.880% at June 30, 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 June 30, 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.

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) with a new revolving credit facility (the “2018 credit facility”). Concurrent with the closing of the 2018 credit facility agreement on April 26, 2018, the Company repaid the $1,191 million secured term loan balance and recognized a loss on early debt extinguishment of $8 million on the consolidated income statement related to the unamortized issuance expense. In addition, approximately $4 million of unamortized issuance expense associated with the closed $743 million revolving credit facility was carried forward into the unamortized issuance expenses of the 2018 credit facility.

The 2018 credit facility has an aggregate maximum revolving credit amount of $3.5 billion and, at June 30, 2019, had a current borrowing base of $2.1 billion with a current aggregate commitment of $2.0 billion. The borrowing base is subject to redetermination twice a year in April and October. On April 4, 2019, the banks participating in the 2018 credit facility reaffirmed the borrowing base of $2.1 billion. The permitted lien provisions in the senior note indentures currently limit liens securing indebtedness to the greater of $2.0 billion and 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

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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 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 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.

The 2018 credit facility contains customary events of default that include, among other things, the failure to comply with the financial covenants described above, non-payment of principal, interest or fees, violation of covenants, inaccuracy of representations and warranties, bankruptcy and insolvency events, material judgments and cross-defaults to material indebtedness. If an event of default occurs and is continuing, all amounts outstanding under the 2018 credit facility may become immediately due and payable. As of June 30, 2019, the Company was in compliance with all of the covenants of the credit agreement.

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 June 30, 2019, the Company had $172 million in letters of credit and no borrowings outstanding under the 2018 revolving credit facility.

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 on the Notes are determined based upon the public bond ratings from Moody’s and S&P. Downgrades on the 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 S&P downgraded the Notes, 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 the 2025 Notes. In the event of future downgrades, the coupons for this series of notes are capped at 6.05% and 6.95%, respectively. The first coupon payment to the bondholders at the higher interest rates was paid in January 2017. S&P and Moody’s upgraded the Notes in April and May 2018, respectively. As a result of these upgrades, interest rates decreased to 5.30% for the 2020 Notes and 6.20% for the 2025 Notes effective July 2018. The first coupon payment to the bondholders at the lower interest rates was paid in January 2019.

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(13) COMMITMENTS AND CONTINGENCIES

Operating Commitments and Contingencies

As of June 30, 2019, the Company’s contractual obligations for demand and similar charges under firm transportation and gathering agreements to guarantee access capacity on natural gas and liquids pipelines and gathering systems totaled approximately $8.5 billion, $966 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 $362 million of that amount. As of June 30, 2019, 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	$	7,501	$	702	$	1,304	$	1,097	$	1,511	$	2,887
Pending regulatory approval and/or construction ⁽¹⁾	966		9		78		121		196		562
Total transportation charges	$	8,467	$	711	$	1,382	$	1,218	$	1,707	$	3,449


(1)	Based on estimated in-service dates as of June 30, 2019.

In December 2018, the Company closed on the Fayetteville Shale sale. 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 June 30, 2019, approximately $162 million of these contractual commitments remain of which the Company will reimburse the buyer for certain of these potential obligations up to approximately $82 million through 2020 depending on the buyer’s actual use, and has recorded a $68 million liability for the estimated future payments, down from $88 million recorded at December 31, 2018.

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

In July 2019 the Company terminated its existing lease agreement and entered into a new lease agreement for a smaller portion of the headquarters office building, resulting in a contractual commitment totaling $88 million over the next ten years.

Environmental Risk

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

Litigation

The Company is subject to various litigation, claims and proceedings that 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 when a liability is both probable and the amount can be reasonably estimated. 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 States District Court for the Eastern District of Arkansas. The Company denied liability in all these cases. Under the agreement for the sale of the equity in the Company’s subsidiaries that operated in the Fayetteville Shale, the Company retained responsibility for these class actions.

In June 2017, the jury returned a verdict in favor of the Company on all counts in Smith v. SEECO, Inc. et al., the class action in the federal court, whose plaintiff class comprises the vast majority of the lessors in these cases. The plaintiff had asserted claims for, among other things, breach of contract, fraud, civil conspiracy, unjust enrichment and violation of certain Arkansas

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statutes. Following the verdict, the court entered judgment in favor of the Company on all claims. The trial court denied the plaintiff’s motion for a new trial, and the plaintiff appealed to the United States Court of Appeals for the Eighth Circuit. Independent of the plaintiff’s appeal, several different parties sought to intervene in the Smith case prior to or shortly after trial, and have appealed the trial court’s order denying their request to intervene. Oral argument occurred in January 2019. On April 23, 2019, the Court of Appeals affirmed the trial court’s order denying all requests to intervene in the case, and, in a separate order, affirmed the trial court’s judgment in favor of the Company on all claims. The Court of Appeals subsequently denied all requests for rehearing.

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, 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 2018 and was paid early in the fourth quarter of 2018. The third class action was dismissed in the second quarter of 2018.

The Smith and the Snow cases cover all affected lessors, except a small percentage who opted out. Most of those have filed separate actions. The Company does not expect those cases to have a material adverse effect on the results of operations, financial position or cash flows of the Company. 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 certain indemnifications in relation to dispositions of assets. 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. No material liabilities have been recognized in connection with these indemnifications.

(14) INCOME TAXES

The Company’s effective tax rate was approximately 10% and 0% for the three months ended June 30, 2019 and 2018, respectively, and (128)% and 0% for the six months ended June 30, 2019 and 2018, respectively, primarily as a result of the release of valuation allowances previously recorded against 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 the year ended December 31, 2018, the Company maintained a full valuation allowance against its deferred tax assets based on its conclusion, considering all available evidence (both positive and negative), that it was more likely than not that the deferred tax assets would 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 had sustained a three-year cumulative level of profitability. Based on this factor and other positive evidence including forecasted income, the Company concluded that it was more likely than not that the deferred tax assets would be realized and released substantially all of the valuation allowance. For the first half of 2019, the Company has recorded a discrete tax benefit of $411 million. The Company expects to retain a valuation allowance of $87 million related to net operating losses in jurisdictions in which it no longer operates.

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(15) PENSION PLAN AND OTHER POSTRETIREMENT BENEFITS

The Company maintains defined pension and other postretirement benefit plans, which cover substantially all of the Company’s employees. Net periodic pension costs include the following components for the three and six months ended June 30, 2019 and 2018:



		Pension Benefits
	Consolidated Statements of Operations Classification of Net Periodic Benefit Cost	For the three months ended June 30,						For the six months ended June 30,
(in millions)		2019			2018			2019			2018
Service cost	General and administrative expenses	$	2		$	3		$	4		$	6
Interest cost	Other Income (Loss), Net	1			1			2			3
Expected return on plan assets	Other Income (Loss), Net	(1		)	(2		)	(3		)	(4		)
Amortization of prior service cost	Other Income (Loss), Net	—			—			—			—
Amortization of net loss	Other Income (Loss), Net	—			—			1			—
Settlement loss	Other Income (Loss), Net	4			—			4			—
Net periodic benefit cost		$	6		$	2		$	8		$	5

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

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

As of June 30, 2019, the Company has contributed $9 million to the pension and other postretirement benefit plans, and expects to contribute an additional $3 million to its pension plan during the remainder of 2019. The Company recognized liabilities of $28 million and $13 million related to its pension and other postretirement benefits, respectively, as of June 30, 2019, compared to liabilities of $34 million and $13 million as of December 31, 2018, respectively.

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

(16) STOCK-BASED COMPENSATION

The Company recognized the following amounts in total employee stock-based compensation costs for the three and six months ended June 30, 2019 and 2018:



	For the three months ended June 30,				For the six months ended June 30,
(in millions)	2019		2018		2019		2018
Stock-based compensation cost – expensed	$	4	$	8	$	11	$	13
Stock-based compensation cost – capitalized	2		4		6		7

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. 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 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 to employees and directors which generally vest over four years. Restricted stock, restricted stock units 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, the Company closed the sale of the equity in certain of its subsidiaries that owned and operated its Fayetteville Shale E&P and related midstream gathering assets in Arkansas. As part of this transaction, most employees associated with those assets became employees of the buyer although the employment of some was or will be terminated. All affected employees were offered a severance package, which included a one-time cash payment depending on length of service and, if

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applicable, the current value of a portion of equity awards that were forfeited. Stock-based compensation costs recognized prior to the cancellation as either general and administrative expense or capitalized expense were reversed and the severance payments were subsequently recognized as restructuring charges for the year ended December 31, 2018 and the three months ended March 31, 2019 on the consolidated statements of operations.

Equity-Classified Awards

The Company recognized the following amounts in employee equity-classified stock-based compensation costs for the three and six months ended June 30, 2019 and 2018:



	For the three months ended June 30,				For the six months ended June 30,
(in millions)	2019		2018		2019		2018
Equity-classified awards – expensed	$	2	$	5	$	4	$	9
Equity-classified awards – capitalized	1		1		2		4

As of June 30, 2019, there was $11 million of total unrecognized compensation cost related to the Company’s unvested equity-classified stock option grants, equity-classified restricted stock grants and equity-classified performance units. This cost is expected to be recognized over a weighted-average period of 1.3 years.

Equity-Classified Stock Options

The following table summarizes equity-classified stock option activity for the six months ended June 30, 2019 and provides information for options outstanding and options exercisable as of June 30, 2019:



	Number of Options		Weighted Average Exercise Price
	(in thousands)
Outstanding at December 31, 2018	5,178		$	17.06
Granted	—		$	—
Exercised	—		$	—
Forfeited or expired	(72	)	$	18.58
Outstanding at June 30, 2019	5,106		$	17.04
Exercisable at June 30, 2019	4,590		$	18.12

Equity-Classified Restricted Stock

The following table summarizes equity-classified restricted stock activity for the six months ended June 30, 2019 and provides information for unvested shares as of June 30, 2019:



	Number of Shares		Weighted Average Fair Value
	(in thousands)
Unvested shares at December 31, 2018	2,717		$	7.91
Granted	15		$	4.12
Vested	(990	)	$	7.37
Forfeited	(175	)	$	8.37
Unvested shares at June 30, 2019	1,567		$	8.17

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Equity-Classified Performance Units

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



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

Liability-Classified Awards

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



	For the three months ended June 30,				For the six months ended June 30,
(in millions)	2019		2018		2019		2018
Liability-classified stock-based compensation cost – expensed	$	2	$	3	$	7	$	4
Liability-classified stock-based compensation cost – capitalized	1		3		4		3

Liability-Classified Restricted Stock Units

In the second quarters of 2019 and 2018, the Company granted restricted stock units that vest over a period of four years and are payable in either cash or shares at the option of the Compensation Committee of the Company’s Board of Directors. The Company has accounted for these as liability-classified awards, and accordingly changes in the market value of the instruments will be recorded to general and administrative expense and capitalized expense over the vesting period of the award. As of June 30, 2019, there was $38 million of total unrecognized compensation cost related to liability-classified restricted stock units that is expected to be recognized over a weighted-average period of 3.2 years. The amount of unrecognized compensation cost for liability-classified awards will fluctuate over time as they are marked to market.



	Number of Units		Weighted Average Fair Value
	(in thousands)
Unvested shares at December 31, 2018	8,202		$	3.41
Granted	8,659		$	4.34
Vested	(2,617	)	$	4.09
Forfeited	(739	)	$	3.13
Unvested units at June 30, 2019	13,505		$	3.16

Liability-Classified Performance Units

In the second quarters of 2019 and 2018, the Company granted performance units that vest over a three-year period and are payable in either cash or shares at the option of the Compensation Committee of the Company’s Board of Directors. The Company has accounted for these as liability-classified awards, and accordingly changes in the fair market value of the instruments will be recorded to general and administrative expense and capitalized expense over the vesting period of the awards. The performance unit awards granted in 2018 include a performance condition based on cash flow per debt-adjusted share and two market conditions, one based on absolute TSR and the other on relative TSR as compared to a group of the Company’s peers. The performance unit awards granted in 2019 include a performance condition based on return on average capital employed and two market conditions, one based on absolute TSR and the other on relative TSR. The fair values of the two market conditions are calculated by Monte Carlo models on a quarterly basis. As of June 30, 2019, there was $16 million of total unrecognized compensation cost related to liability-classified performance units. This cost is expected to be recognized over a weighted-average period of 2.4 years. The

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amount of unrecognized compensation cost for liability-classified awards will fluctuate over time as they are marked to market. The final value of the performance unit awards is contingent upon the Company’s actual performance against these performance measures.



	Number of Shares		Weighted Average Fair Value
	(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 June 30, 2019	5,441		$	3.16

(17) 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 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 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 and other income (loss). The “Other” column includes items not related to the Company’s reportable segments, including real estate and corporate items.



	E&P				Midstream				Other				Total

Three months ended June 30, 2019	(in millions)
Revenues from external customers	$	380			$	287			$	—			$	667
Intersegment revenues	(9		)		339				—				330
Depreciation, depletion and amortization expense	118				3				—				121
Operating income (loss)	30			⁽¹⁾	(8		)		—				22
Interest expense ⁽²⁾	15				—				—				15
Gain on derivatives	152				—				—				152
Other loss, net	(5		)		—				(1		)		(6		)
Provision for income taxes ⁽²⁾	15				—				—				15
Assets	5,945			⁽³⁾	277				323			⁽⁴⁾	6,545
Capital investments⁽⁵⁾	367				—				1				368

Three months ended June 30, 2018
Revenues from external customers	$	527			$	289			$	—			$	816
Intersegment revenues	(7		)		508				—				501
Depreciation, depletion and amortization expense	126				16				—				142
Operating income⁽⁶⁾	97			⁽¹⁾	27			⁽⁷⁾	—				124
Interest expense ⁽²⁾	32				—				—				32
Loss on derivatives	(36		)		—				—				(36		)
Loss on early extinguishment of debt	—				—				(8		)		(8		)
Other income, net	3				—				—				3
Assets	5,583			⁽³⁾	1,228				231			⁽⁴⁾	7,042
Capital investments ⁽⁵⁾	396				5				2				403

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	E&P				Midstream				Other				Total

Six months ended June 30, 2019	(in millions)
Revenues from external customers	$	931			$	726			$	—			$	1,657
Intersegment revenues	(18		)		841				—				823
Depreciation, depletion and amortization expense	228				5				—				233
Operating income (loss)	240			⁽¹⁾	(5		)		—				235
Interest expense⁽²⁾	29				—				—				29
Gain on derivatives	120				—				—				120
Other loss, net	(4		)		—				(1		)		(5		)
Benefit from income taxes ⁽²⁾	(411		)		—				—				(411		)
Assets	5,945			⁽³⁾	277				323			⁽⁴⁾	6,545
Capital investments⁽⁵⁾	692				—				1				693

Six months ended June 30, 2018
Revenues from external customers	$	1,170			$	566			$	—			$	1,736
Intersegment revenues	(13		)		1,127				—				1,114
Depreciation, depletion and amortization expense	243				42			⁽⁸⁾	—				285
Operating income ⁽⁶⁾	335			⁽¹⁾	44			⁽⁷⁾	—				379
Interest expense⁽²⁾	71				—				—				71
Loss on derivatives	(43		)		—				—				(43		)
Loss on early extinguishment of debt	—				—				(8		)		(8		)
Other income (loss), net	3				(1		)		—				2
Assets	5,583			⁽³⁾	1,228				231			⁽⁴⁾	7,042
Capital investments⁽⁵⁾	730				9				2				741


(1)	Operating income for the E&P segment includes $2 million and $16 million of restructuring charges for the three months ended June 30, 2019 and 2018, respectively, and $5 million and $16 million of restructuring charges for the six months ended June 30, 2019 and 2018, respectively.


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


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

(4)

Other assets represent corporate assets not allocated to segments and assets for non-reportable segments. At June 30, 2019 and 2018, other assets included approximately $155 million and $37 million, respectively, in cash and cash equivalents, $68 million and $89 million, respectively, in income taxes receivable, $50 million and $83 million, respectively, in property, plant and equipment, $10 million and $12 million, respectively, in unamortized debt expense, $6 million and $8 million, respectively, in a non-qualified retirement plan and $3 million, respectively, in other assets for both periods presented. Additionally, the June 30, 2019 asset balance includes $29 million in right-of-use lease assets.


(5)	Capital investments include increases of $39 million and $19 million for the three months ended June 30, 2019 and 2018, respectively, and increases of $105 million and $52 million for the six months ended June 30, 2019 and 2018, respectively, relating to the change in accrued expenditures between years.


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


(7)	Operating income for the Midstream segment includes $2 million related to restructuring charges for the three and six months ended June 30, 2018.


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

Included in intersegment revenues of the Midstream segment are $339 million and $463 million for the three months ended June 30, 2019 and 2018, respectively, and $841 million and $1,039 million for the six months ended June 30, 2019 and 2018, respectively, for marketing of the Company’s E&P sales. Corporate assets include cash and cash equivalents, furniture and fixtures and other assets. Corporate general and administrative costs, depreciation expense and taxes, other than income taxes, are allocated to the segments.

(18) NEW ACCOUNTING PRONOUNCEMENTS

New Accounting Standards Implemented

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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 the standard did not materially change 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

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 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 evaluation of Update 2016-13, but does not believe it will have a material impact on its consolidated financial statements at this time.

(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.

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CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)



(in millions)	Parent		Guarantors			Non-Guarantors		Eliminations			Consolidated
Three months ended June 30, 2019
Operating Revenues:
Gas sales	$	—	$	275		$	—	$	—		$	275
Oil sales	—		47			—		—			47
NGL sales	—		58			—		—			58
Marketing	—		287			—		—			287
	—		667			—		—			667
Operating Costs and Expenses:
Marketing purchases	—		293			—		—			293
Operating expenses	—		169			—		—			169
General and administrative expenses	—		40			—		—			40
Loss on sale of operating assets	—		3			—		—			3
Restructuring charges	—		2			—		—			2
Depreciation, depletion and amortization	—		121			—		—			121
Taxes, other than income taxes	—		17			—		—			17
	—		645			—		—			645
Operating Income	—		22			—		—			22
Interest Expense, Net	15		—			—		—			15
Gain on Derivatives	—		152			—		—			152
Other Loss, Net	—		(6		)	—		—			(6		)
Equity in Earnings of Subsidiaries	153		—			—		(153		)	—

Income (Loss) Before Income Taxes	138		168			—		(153		)	153
Provision for Income Taxes	—		15			—		—			15
Net Income (Loss)	$	138	$	153		$	—	$	(153	)	$	138

Net Income (Loss)	$	138	$	153		$	—	$	(153	)	$	138
Other Comprehensive Income	4		—			—		—			4
Comprehensive Income (Loss)	$	142	$	153		$	—	$	(153	)	$	142

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CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)



(in millions)	Parent			Guarantors			Non-Guarantors		Eliminations			Consolidated
Three months ended June 30, 2018
Operating Revenues:
Gas sales	$	—		$	407		$	—	$	—		$	407
Oil sales	—			44			—		—			44
NGL sales	—			75			—		—			75
Marketing	—			265			—		—			265
Gas gathering	—			24			—		—			24
Other	—			1			—		—			1
	—			816			—		—			816
Operating Costs and Expenses:
Marketing purchases	—			265			—		—			265
Operating expenses	—			193			—		—			193
General and administrative expenses	—			59			—		—			59
Restructuring charges	—			18			—		—			18
Depreciation, depletion and amortization	—			142			—		—			142
Taxes, other than income taxes	—			15			—		—			15
	—			692			—		—			692
Operating Income	—			124			—		—			124
Interest Expense, Net	32			—			—		—			32
Loss on Derivatives	—			(36		)	—		—			(36		)
Loss on Early Extinguishment of Debt	(8		)	—			—		—			(8		)
Other Income, Net	—			3			—		—			3
Equity in Earnings of Subsidiaries	91			—			—		(91		)	—

Income (Loss) Before Income Taxes	51			91			—		(91		)	51
Provision for Income Taxes	—			—			—		—			—
Net Income (Loss)	$	51		$	91		$	—	$	(91	)	$	51

Net Income (Loss)	$	51		$	91		$	—	$	(91	)	$	51
Other Comprehensive Income	—			—			—		—			—
Comprehensive Income (Loss)	$	51		$	91		$	—	$	(91	)	$	51

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CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)



(in millions)	Parent		Guarantors			Non-Guarantors		Eliminations			Consolidated
Six months ended June 30, 2019
Operating Revenues:
Gas sales	$	—	$	705		$	—	$	—		$	705
Oil sales	—		86			—		—			86
NGL sales	—		139			—		—			139
Marketing	—		725			—		—			725
Other	—		2			—		—			2
	—		1,657			—		—			1,657
Operating Costs and Expenses:
Marketing purchases	—		734			—		—			734
Operating expenses	—		334			—		—			334
General and administrative expenses	—		77			—		—			77
Loss on sale of operating assets	—		3			—		—			3
Restructuring charges	—		5			—		—			5
Depreciation, depletion and amortization	—		233			—		—			233
Taxes, other than income taxes	—		36			—		—			36
	—		1,422			—		—			1,422
Operating Income	—		235			—		—			235
Interest Expense, Net	29		—			—		—			29
Gain on Derivatives	—		120			—		—			120
Other Loss, Net	—		(5		)	—		—			(5		)
Equity in Earnings of Subsidiaries	761		—			—		(761		)	—

Income (Loss) Before Income Taxes	732		350			—		(761		)	321
Benefit from Income Taxes	—		(411		)	—		—			(411		)
Net Income (Loss)	$	732	$	761		$	—	$	(761	)	$	732

Net Income (Loss)	$	732	$	761		$	—	$	(761	)	$	732
Other Comprehensive Income	4		—			—		—			4
Comprehensive Income (Loss)	$	736	$	761		$	—	$	(761	)	$	736

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CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)



(in millions)	Parent			Guarantors			Non-Guarantors		Eliminations			Consolidated
Six months ended June 30, 2018
Operating Revenues:
Gas sales	$	—		$	947		$	—	$	—		$	947
Oil sales	—			79			—		—			79
NGL sales	—			140			—		—			140
Marketing	—			518			—		—			518
Gas gathering	—			48			—		—			48
Other	—			4			—		—			4
	—			1,736			—		—			1,736
Operating Costs and Expenses:
Marketing purchases	—			520			—		—			520
Operating expenses	—			382			—		—			382
General and administrative expenses	—			114			—		—			114
Restructuring charges	—			18			—		—			18
Depreciation, depletion and amortization	—			285			—		—			285
Taxes, other than income taxes	—			38			—		—			38
	—			1,357			—		—			1,357
Operating Income	—			379			—		—			379
Interest Expense, Net	71			—			—		—			71
Loss on Derivatives	—			(43		)	—		—			(43		)
Loss on Early Extinguishment of Debt	(8		)	—			—		—			(8		)
Other Income, Net	—			2			—		—			2
Equity in Earnings of Subsidiaries	338			—			—		(338		)	—

Income (Loss) Before Income Taxes	259			338			—		(338		)	259
Provision for Income Taxes	—			—			—		—			—
Net Income (Loss)	$	259		$	338		$	—	$	(338	)	$	259
Participating securities - mandatory convertible preferred stock	2			—			—		—			2
Net Income (Loss) Attributable to Common Stock	$	257		$	338		$	—	$	(338	)	$	257

Net Income (Loss)	$	259		$	338		$	—	$	(338	)	$	259
Other Comprehensive Income	—			—			—		—			—
Comprehensive Income (Loss)	$	259		$	338		$	—	$	(338	)	$	259

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CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)



(in millions)	Parent			Guarantors			Non-Guarantors			Eliminations			Consolidated
June 30, 2019
ASSETS
Cash and cash equivalents	$	155		$	—		$	—		$	—		$	155
Accounts receivable, net	—			358			—			—			358
Other current assets	5			246			—			—			251
Total current assets	160			604			—			—			764

Intercompany receivables	7,894			—			—			(7,894		)	—

Natural gas and oil properties, using the full cost method	—			24,769			54			—			24,823
Other	196			330			29			—			555
Less: Accumulated depreciation, depletion and amortization	(162		)	(20,059		)	(58		)	—			(20,279		)
Total property and equipment, net	34			5,040			25			—			5,099

Investments in subsidiaries (equity method)	—			23			—			(23		)	—
Other long-term assets	45			637			—			—			682
TOTAL ASSETS	$	8,133		$	6,304		$	25		$	(7,917	)	$	6,545

LIABILITIES AND EQUITY
Accounts payable	$	72		$	513		$	—		$	—		$	585
Other current liabilities	193			134			—			—			327
Total current liabilities	265			647			—			—			912

Intercompany payables	—			7,892			2			(7,894		)	—

Long-term debt	2,267			—			—			—			2,267
Pension and other postretirement liabilities	39			—			—			—			39
Other long-term liabilities	39			206			—			—			245
Negative carrying amount of subsidiaries, net	2,441			—			—			(2,441		)	—
Total long-term liabilities	4,786			206			—			(2,441		)	2,551
Commitments and contingencies
Total equity (accumulated deficit)	3,082			(2,441		)	23			2,418			3,082
TOTAL LIABILITIES AND EQUITY	$	8,133		$	6,304		$	25		$	(7,917	)	$	6,545

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CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)



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

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

Natural gas and oil properties, using the full cost method	—			24,128			52			—			24,180
Other	197			301			27			—			525
Less: Accumulated depreciation, depletion and amortization	(154		)	(19,840		)	(55		)	—			(20,049		)
Total property and equipment, net	43			4,589			24			—			4,656

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

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

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

Long-term debt	2,318			—			—			—			2,318
Pension and other postretirement liabilities	46			—			—			—			46
Other long-term liabilities	54			171			—			—			225
Negative carrying amount of subsidiaries, net	3,199			—			—			(3,199		)	—
Total long-term liabilities	5,617			171			—			(3,199		)	2,589
Commitments and contingencies
Total equity (accumulated deficit)	2,362			(3,199		)	24			3,175			2,362
TOTAL LIABILITIES AND EQUITY	$	8,207		$	5,522		$	24		$	(7,956	)	$	5,797

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CONDENSED CONSOLIDATED STATEMENT OF CASH FLOWS

(Unaudited)



(in millions)	Parent			Guarantors			Non-Guarantors			Eliminations			Consolidated
Six months ended June 30, 2019
Net cash provided by (used in) operating activities	$	1,124		$	179		$	—		$	(760	)	$	543
Investing activities:
Capital investments	(1		)	(584		)	(1		)	—			(586		)
Proceeds from sale	—			26			—			—			26
Net cash used in investing activities	(1		)	(558		)	(1		)	—			(560		)
Financing activities:
Intercompany activities	(1,140		)	379			1			760			—
Change in bank drafts outstanding	(7		)	—			—			—			(7		)
Purchase of treasury stock	(21		)	—			—			—			(21		)
Cash paid for tax withholding	(1		)	—			—			—			(1		)
Net cash provided by (used in) financing activities	(1,169		)	379			1			760			(29		)
Decrease in cash and cash equivalents	(46		)	—			—			—			(46		)
Cash and cash equivalents at beginning of year	201			—			—			—			201
Cash and cash equivalents at end of period	$	155		$	—		$	—		$	—		$	155

Six months ended June 30, 2018
Net cash provided by (used in) operating activities	$	276		$	725		$	—		$	(337	)	$	664
Investing activities:
Capital investments	(6		)	(678		)	—			—			(684		)
Other	—			9			—			—			9
Net cash used in investing activities	(6		)	(669		)	—			—			(675		)
Financing activities:
Intercompany activities	(287		)	(50		)	—			337			—
Payments on long-term debt	(1,191		)	—			—			—			(1,191		)
Payments on revolving credit facility	(645		)	—			—			—			(645		)
Borrowings under revolving credit facility	1,005			—			—			—			1,005
Preferred stock dividend	(27		)	—			—			—			(27		)
Other	(10		)	—			—			—			(10		)
Net cash provided by (used in) financing activities	(1,155		)	(50		)	—			337			(868		)
Increase (decrease) in cash and cash equivalents	(885		)	6			—			—			(879		)
Cash and cash equivalents at beginning of year	914			2			—			—			916
Cash and cash equivalents at end of period	$	29		$	8		$	—		$	—		$	37

ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following updates information as to Southwestern Energy Company’s financial condition provided in our 2018 Annual Report and analyzes the changes in the results of operations between the three and six month periods ended June 30, 2019 and 2018. 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 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 Annual Report, and Item 1A, “Risk Factors” in Part II in this Quarterly Report and any other quarterly report on Form 10-Q filed during the fiscal year. You should read the following discussion with our consolidated financial statements and the related notes included in this Quarterly Report.

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OVERVIEW

Background

Southwestern Energy Company (including its subsidiaries, collectively, “we,” “our,” “us,” “the Company” or “Southwestern”) is an independent energy company engaged in natural gas, oil and 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 to as “Midstream.” 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.” We also operate drilling rigs located in Pennsylvania and West Virginia, and we provide certain oilfield products and services, principally serving our E&P operations through vertical integration.

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

Recent Financial and Operating Results

Significant second quarter 2019 operating and financial results include:

Total Company

•

Net income attributable to common stock of $138 million, or $0.26 per diluted share, increased 171% compared to net income attributable to common stock of $51 million, or $0.09 per diluted share, for the same period in 2018. The increase was primarily due to a $188 million positive impact of derivatives, including a $174 million improvement in unsettled derivatives as compared to the same period in 2018, which was partially offset by decreased operating income and the divestiture of the Fayetteville Shale E&P and related midstream gathering assets on December 3, 2018.


•	Operating income of $22 million decreased 82% compared to operating income of $124 million for the same period in 2018 on a consolidated basis. The decrease was primarily due to lower margins associated with reduced commodity prices and the divestiture of the Fayetteville Shale E&P and related midstream gathering assets in December 2018.


•	Net cash provided by operating activities of $543 million decreased 18% from $664 million for the same period in 2018 primarily due to the decrease in operating income discussed above.


•	Total capital investing of $368 million decreased 9% from $403 million for the same period in 2018.

E&P


•	E&P segment operating income of $30 million decreased 69% from $97 million for the same period in 2018.

•

Total net production of 186 Bcfe was comprised of 79% natural gas and 21% NGLs and oil. E&P segment production volumes of 234 Bcfe for the second 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 11% from 167 Bcfe in the same period in 2018, and our liquids production increased 15% over the same periods.

•

Excluding the effect of derivatives, our realized natural gas price of $1.80 per Mcf decreased 10% from the same period in 2018, our realized oil price of $49.55 per barrel decreased 18% from the same period in 2018 and our realized NGL price of $10.51 per barrel decreased 32% from the same period in 2018. Our total weighted average realized price excluding the effect of derivatives of $1.99 per Mcfe decreased 10% from the same period in 2018.


•	E&P segment invested $367 million in capital; drilling 41 wells, completing 40 wells and placing 36 wells to sales.

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Outlook

We expect to continue to exercise capital discipline through a fully-funded 2019 capital investment program. We remain committed to our focus on optimizing our portfolio by concentrating our efforts on our highest return investment opportunities, looking for opportunities to maximize margins in each core area of our business and further developing our knowledge of our asset base. We believe our industry will continue to face challenges due to the uncertainty of natural gas, oil and NGL prices in the United States, changes in laws, regulations and investor sentiment, and other key factors described in “Risk Factors” in the Company’s 2018 Annual Report.

RESULTS OF OPERATIONS

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

E&P

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



	For the three months ended June 30,				For the six months ended June 30,
(in millions)	2019		2018		2019		2018
Revenues	$	371	$	520	$	913	$	1,157
Operating costs and expenses	341		423		673		822
Operating income	$	30	$	97	$	240	$	335

Gain on derivatives, settled ⁽¹⁾	$	34	$	20	$	24	$	11

(1) Represents the gain on settled commodity derivatives.

Operating Income

•

E&P segment operating income for the second quarter of 2018 included $20 million related to our operations in the Fayetteville Shale, which was sold in December 2018. Excluding amounts relating to the Fayetteville Shale, E&P segment operating income decreased $47 million for the three months ended June 30, 2019, compared to the same period in 2018, due to lower margins associated with decreased commodity pricing.

•

Operating income for the E&P segment included $51 million related to our operations in the Fayetteville Shale for the six months ended June 30, 2018. Excluding the amounts related to the Fayetteville Shale, operating income for the E&P segment decreased $44 million for the six months ended June 30, 2019, compared to the same period in 2018, due to lower margins associated with decreased commodity pricing.

Revenues

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



	Three months ended June 30,
(in millions except percentages)	Natural Gas			Oil			NGLs			Total
2018 sales revenues⁽¹⁾	$	400		$	44		$	75		$	519
Changes associated with the Fayetteville Shale sale⁽²⁾	(139		)	—			—			(139		)
2018 sales revenues, net of Fayetteville Shale revenues	261			44			75			380
Changes associated with prices	(22		)	(10		)	(27		)	(59		)
Changes associated with production volumes	28			12			10			50
2019 sales revenues	$	267		$	46		$	58		$	371
Increase (decrease) from 2018, net of Fayetteville Shale revenues	2		%	5		%	(23		)%	(2		%)


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


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

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	Six months ended June 30,
(in millions except percentages)	Natural Gas			Oil			NGLs			Total
2018 sales revenues ⁽¹⁾	$	935		$	78		$	140		$	1,153
Changes associated with the Fayetteville Shale sale⁽²⁾	(291		)	—			—			(291		)
2018 sales revenues, net of Fayetteville Shale revenues	644			78			140			862
Changes associated with prices	(22		)	(19		)	(32		)	(73		)
Changes associated with production volumes	66			26			31			123
2019 sales revenues ⁽³⁾	$	688		$	85		$	139		$	912
Increase (decrease) from 2018, net of Fayetteville Shale revenues	7		%	9		%	(1		)%	6		%


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


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


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

Production Volumes



	For the three months ended June 30,				Increase/(Decrease)	For the six months ended June 30,				Increase/(Decrease)
Production volumes:	2019		2018		Increase/(Decrease)	2019		2018		Increase/(Decrease)
Natural Gas (Bcf)
Northeast Appalachia	113		112		1%	225		220		2%
Southwest Appalachia	35		22		59%	66		44		50%
Fayetteville Shale ⁽¹⁾	—		67		(100%)	—		134		(100%)
Total	148		201		(26%)	291		398		(27%)

Oil (MBbls)
Southwest Appalachia	931		707		32%	1,780		1,301		37%
Other	6		16		(63%)	11		35		(69%)
Total	937		723		30%	1,791		1,336		34%

NGL (MBbls)
Southwest Appalachia	5,493		4,850		13%	11,095		9,068		22%
Other	4		12		(67%)	5		24		(79%)
Total	5,497		4,862		13%	11,100		9,092		22%

Production volumes by area: (Bcfe)
Northeast Appalachia	113		112		1%	225		220		2%
Southwest Appalachia	73		55		33%	143		106		35%
Fayetteville Shale ⁽¹⁾	—		67		(100%)	—		134		(100%)
Total	186		234		(21%)	368		460		(20%)

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


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

•

E&P segment production volumes for the second quarter of 2018 included 67 Bcf of production related to our operations in the Fayetteville Shale, which was sold in December 2018. Excluding this amount, production volumes for our E&P segment increased by 19 Bcfe for the three months ended June 30, 2019 compared to the same period in 2018, primarily due to a 33% increase in production volumes from Southwest Appalachia.

•

E&P segment production volumes for the six months ended June 30, 2018 included 134 Bcf of production related to our operations in the Fayetteville Shale, which was sold in December 2018. Excluding this amount, production volumes for our E&P segment increased by 42 Bcfe for the six months ended June 30, 2019 compared to the same period in 2018, primarily due to a 35% increase in production volumes from Southwest Appalachia.

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•	Oil and NGL production increased 30% and 13%, respectively, for the three months ended June 30, 2019, compared to the same period in 2018, reflecting our shifting commodity production mix towards liquids.


•	Oil and NGL production increased 34% and 22%, respectively, for the six months ended June 30, 2019, compared to the same period in 2018.

Commodity Prices

The price we expect to receive for our production is a critical factor in determining the capital investments we make to develop our properties. Commodity prices fluctuate due to a variety of factors we cannot control or predict, including increased supplies of natural gas, oil or NGLs due to greater exploration and development activities, weather conditions, political and economic events, and competition from other energy sources. These factors impact supply and demand, which in turn determine the sales prices for our production. In addition to these factors, the prices we realize for our production are affected by our hedging activities as well as locational differences in market prices, including basis differentials. We will continue to evaluate the commodity price environments and adjust the pace of our activity in order to maintain appropriate liquidity and financial flexibility.



	For the three months ended June 30,						Increase/(Decrease)	For the six months ended June 30,						Increase/(Decrease)
	2019			2018			Increase/(Decrease)	2019			2018			Increase/(Decrease)
Natural Gas Price:
NYMEX Henry Hub Price ($/MMBtu) ⁽¹⁾	$	2.64		$	2.80		(6)%	$	2.89		$	2.90		—%
Discount to NYMEX ⁽²⁾	(0.84		)	(0.81		)	4%	(0.52		)	(0.55		)	(5%)
Average realized gas price per Mcf, excluding derivatives	$	1.80		$	1.99		(10)%	$	2.37		$	2.35		1%
Loss on settled financial basis derivatives ($/Mcf)	(0.03		)	(0.01		)		(0.03		)	(0.06		)
Gain on settled commodity derivatives ($/Mcf)	0.17			0.13				0.04			0.10
Average realized gas price per Mcf, including derivatives	$	1.94		$	2.11		(8)%	$	2.38		$	2.39		—%

Oil Price:
WTI oil price ($/Bbl)	$	59.81		$	67.88		(12%)	$	57.36		$	65.37		(12%)
Discount to WTI	(10.26		)	(7.73		)	33%	(9.75		)	(7.12		)	37%
Average oil price per Bbl, excluding derivatives	$	49.55		$	60.15		(18%)	$	47.61		$	58.25		(18%)
Gain (loss) on settled derivatives ($/Bbl)	2.05			(0.93		)		2.19			(0.51		)
Average oil price per Bbl, including derivatives	$	51.60		$	59.22		(13%)	$	49.80		$	57.74		(14%)

NGL Price:
Average net realized NGL price per Bbl, excluding derivatives	$	10.51		$	15.37		(32%)	$	12.50		$	15.39		(19%)
Gain (loss) on settled derivatives ($/Bbl)	2.11			(0.32		)		1.34			(0.17		)
Average net realized NGL price per Bbl, including derivatives	$	12.62		$	15.05		(16%)	$	13.84		$	15.22		(9%)
Percentage of WTI, excluding derivatives	18		%	23		%		22		%	24		%

Total Weighted Average Realized Price:
Excluding derivatives ($/Mcfe)	$	1.99		$	2.21		(10)%	$	2.48		$	2.51		(1)%
Including derivatives ($/Mcfe)	$	2.17		$	2.30		(6)%	$	2.54		$	2.53		—%


(1)	Based on last day settlement prices from monthly futures contracts.


(2)	This discount includes a basis differential, a heating content adjustment, physical basis sales, third-party transportation charges and fuel charges, and excludes financial basis hedges.

We receive a sales price for our natural gas at a discount to average monthly NYMEX settlement prices based on heating content of the gas, locational basis differentials and transportation and fuel charges. Additionally, we receive a sales price for our oil and NGLs at a difference to average monthly West Texas Intermediate settlement and Mont Belvieu NGL composite prices, respectively, due to a number of factors including product quality, composition and types of NGLs sold, locational basis differentials, transportation and fuel charges.

We regularly enter into various hedging and other financial arrangements with respect to a portion of our projected natural gas, oil and NGL production in order to ensure certain desired levels of cash flow and to minimize the impact of price fluctuations, including fluctuations in locational market differentials. We refer you to Item 3, “Quantitative and Qualitative Disclosures About Market Risk” and Note 9 to the consolidated financial statements, included in this Quarterly Report.

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The table below presents the amount of our future production in which the basis is protected as of June 30, 2019:



	Volume (Bcf)	Basis Differential
Basis Swaps - Natural Gas
2019	80	$	(0.45	)
2020	132	(0.34		)
2021	28	(0.51		)
Total	240

Physical NYMEX Sales Arrangements - Natural Gas
2019	134	$	(0.24	)
2020	103	(0.13		)
Total	237

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



	Remaining 2019	Full Year 2020	Full Year 2021
Natural gas (Bcf)	223	172	37
Oil (MBbls)	2,043	2,563	—
Propane (MBbls)	2,231	2,562	—
Ethane (MBbls)	1,858	732	—
Total financial protection on future production (Bcfe)	260	207	37

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

Operating Costs and Expenses



	For the three months ended June 30,						Increase/(Decrease)	For the six months ended June 30,						Increase/(Decrease)
(in millions except percentages)	2019			2018			Increase/(Decrease)	2019			2018			Increase/(Decrease)
Lease operating expenses	$	169		$	215		(21%)	$	335		$	428		(22%)
General & administrative expenses	35			53		⁽¹⁾	(34%)	69			101		⁽¹⁾	(32%)
Restructuring charges	2			16			(88)%	5			16			(69)%
Taxes, other than income taxes	17			13			31%	36			34			6%
Full cost pool amortization	108			117			(8%)	211			225			(6%)
Non-full cost pool DD&A	10			9			11%	17			18			(6%)
Total operating costs	$	341		$	423		(19%)	$	673		$	822		(18%)

(1) Includes $7.9 million of legal settlement charges for the three and six months ended June 30, 2018.

	For the three months ended June 30,						Increase/	For the six months ended June 30,						Increase/
Average unit costs per Mcfe:	2019			2018			(Decrease)	2019			2018			(Decrease)
Lease operating expenses ⁽¹⁾	$	0.90		$	0.91		(1%)	$	0.90		$	0.93		(3%)
General & administrative expenses	$	0.19	⁽²⁾	$	0.19	⁽³⁾	—%	$	0.19	⁽²⁾	$	0.20	⁽³⁾	(5%)
Taxes, other than income taxes	$	0.09		$	0.06	⁽⁴⁾	50%	$	0.10		$	0.07	⁽⁴⁾	43%
Full cost pool amortization	$	0.58		$	0.50		16%	$	0.57		$	0.49		16%


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


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


(3)	Excludes $15 million of restructuring charges and $7.9 million of legal settlement charges for the three and six months ended June 30, 2018.


(4)	Excludes $1 million of restructuring charges for the three and six months ended June 30, 2018.

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Lease Operating Expenses


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

•

Lease operating expenses per Mcfe decreased $0.03 for the six months ended June 30, 2019, compared to the same period of 2018, primarily due to a $0.02 per Mcfe decrease associated with the Fayetteville Shale sale, and a $0.02 per Mcfe decrease primarily related to preventative maintenance associated with extended severe winter weather along with a one-time charge of $3.7 million related to NGL processing fees, both recorded in the first quarter of 2018. These decreases were partially offset by a $0.01 per Mcfe increase primarily related to a shift towards liquids production, which includes processing fees.

General and Administrative Expenses


•	General and administrative expenses decreased $18 million and $32 million for the three and six months ended June 30, 2019, respectively, compared to the same periods of 2018, primarily due to decreased personnel costs, the implementation of cost reduction initiatives and a $7.9 million legal settlement charge recorded in the second quarter of 2018.

Taxes, Other than Income Taxes

•

On a per Mcfe basis, taxes, other than income taxes, may vary from period to period due to changes in ad valorem and severance taxes that result from the mix of our production volumes and fluctuations in commodity prices. Taxes, other than income taxes, increased $0.03 for the three and six months ended June 30, 2019, compared to the same periods of 2018, primarily due to an $8 million severance tax refund received in the second quarter of 2018.

Full Cost Pool Amortization

•

Our full cost pool amortization rate increased $0.08 per Mcfe for the three and six months ended June 30, 2019, respectively, as compared to the same periods of 2018. The average amortization rate increased primarily as a result of the impact of capital investment and the further evaluation of our unproved properties during the past twelve months and the impact of the Fayetteville Shale sale, which reduced our total natural gas reserves along with the carrying value of our full cost pool assets.

•

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


•	Unevaluated costs excluded from amortization were $1.7 billion at June 30, 2019, compared to $1.8 billion at December 31, 2018. The unevaluated costs excluded from amortization decreased as the impact of $151 million of unevaluated capital invested during the period was more than offset by the evaluation of previously unevaluated properties totaling $229 million.

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Midstream



	For the three months ended June 30,								Increase/ (Decrease)	For the six months ended June 30,								Increase/ (Decrease)
(in millions except percentages)	2019				2018				Increase/ (Decrease)	2019				2018				Increase/ (Decrease)
Marketing revenues	$	626			$	728			(14)%	$	1,566			$	1,557			1%
Gas gathering revenues	—			⁽¹⁾	69				(100%)	—			⁽¹⁾	136				(100%)
Other operating revenues	—				—				—%	1				—				100%
Marketing purchases	622				716				(13)%	1,556				1,535				1%
Operating costs and expenses	9			⁽¹⁾	54			⁽²⁾	(83%)	13			⁽¹⁾	115			⁽³⁾	(89%)
(Gain) loss on sale of operating assets	3				—				100%	3				(1		)		(400%)
Operating income (loss)	$	(8	)		$	27			(130%)	$	(5	)		$	44			(111%)

Volumes marketed (Bcfe)	255			⁽⁴⁾	289				(12)%	544			⁽⁴⁾	554				(2)%
Volumes gathered (Bcf)	—			⁽¹⁾	106				(100%)	—			⁽¹⁾	209				(100%)

Percent natural gas marketed from affiliated E&P operations	83		%	⁽⁴⁾	94		%			75		%	⁽⁴⁾	95		%
Affiliated E&P oil and NGL production marketed	76		%		69		%			75		%		68		%


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


(2)	Includes $2 million of restructuring charges for the three months ended June 30, 2018.


(3)	Includes $10 million impairment related to certain non-core gathering assets and $2 million of restructuring charges for the six months ended June 30, 2018.


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

Operating Income

•

Midstream operating income for the second quarter of 2018 includes $20 million related to our gathering operations in the Fayetteville Shale, which were sold in December 2018. Excluding this amount, operating income decreased $15 million for the three months ended June 30, 2019, compared to the same period in 2018, primarily due to an $8 million decrease in the marketing margin, a $3 million loss on sale of operating assets and a $2 million increase in allocated corporate expenses.

•

Midstream operating income for the six months ended June 30, 2018 includes $42 million related to our gathering operations in the Fayetteville Shale, which we sold in December 2018. Excluding this amount, operating income decreased $7 million for the six months ended June 30, 2019, compared to the same period in 2018, primarily due to a $12 million decrease in the marketing margin, a $3 million loss on sale of operating assets and a $2 million increase in allocated corporate expenses, partially offset by a $1 million gain on storage gas and a $10 million impairment of non-core gathering assets in 2018.


•	The margin generated from marketing activities was $4 million and $12 million for the three months ended June 30, 2019 and 2018, respectively, and $10 million and $22 million for the six months ended June 30, 2019 and 2018, respectively.

Margins are driven primarily by volumes marketed and may fluctuate depending on the prices paid for commodities, related cost of transportation and the ultimate disposition of those commodities. Increases and decreases in marketing revenues due to changes in commodity prices and volumes marketed are largely offset by corresponding changes in marketing purchase expenses.

Revenues


•	Revenues from our marketing activities decreased $102 million for the three months ended June 30, 2019, compared to the same period in 2018, primarily due to a 12% decrease in volumes marketed and a 3% decrease in the price received for volumes marketed.


•	For the six months ended June 30, 2019, revenues from our marketing activities increased $9 million compared to the same period in 2018, as a 10 Bcfe decrease in the volumes marketed was more than offset by a 2% increase in the price received for volumes marketed.

Operating Costs and Expenses

•

Midstream operating costs and expenses for the second quarter of 2018 included $48 million related to our gathering operations in the Fayetteville Shale, which were sold in December 2018. Excluding this amount, operating costs and expenses increased $3 million for the three months ended June 30, 2019, compared to the same period in 2018, primarily due to a $2 million increase in allocated corporate costs.

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•

Midstream operating costs and expenses for the first half of 2018 included $92 million related to our gathering operations in the Fayetteville Shale, which were sold in December 2018. Excluding this amount, operating costs and expenses decreased $10 million for the six months ended June 30, 2019, compared to the same period in 2018, primarily due to a $10 million impairment of non-core gathering assets, which were divested in 2018, along with $2 million of operating expenses associated with the related assets, partially offset by a $2 million increase in allocated corporate costs.

Consolidated

Restructuring Charges

For the three months ended June 30, 2019, we recognized total restructuring charges of $2 million, of which $1 million was related to cash severance, including payroll taxes withheld, and $1 million primarily related to office consolidation associated with the Fayetteville Shale sale. For the six months ended June 30, 2019, we recognized total restructuring charges of $5 million, of which $3 million was related to cash severance, including payroll taxes withheld, and $2 million primarily related to office consolidation associated with the Fayetteville Shale sale. We expect to incur an additional $3 million to $5 million in restructuring charges for the remainder of 2019 related to office consolidation.

On June 27, 2018, we announced a workforce reduction plan, which resulted primarily from our previously announced study of structural, process and organizational changes to enhance shareholder value and continues with respect to other aspects of our business and activities. Affected employees were offered a severance package, which included a one-time cash payment depending on length of service and, if applicable, current value of a portion of equity awards to be forfeited. We recognized restructuring expense of $18 million for the three and six months ended June 30, 2018, of which $16 million was related to cash severance, including payroll taxes.

Interest Expense



	For the three months ended June 30,						Increase/(Decrease)	For the six months ended June 30,						Increase/(Decrease)
(in millions except percentages)	2019			2018			Increase/(Decrease)	2019			2018			Increase/(Decrease)
Gross interest expense:
Senior notes	$	39		$	51		(24%)	$	78		$	101		(23%)
Credit arrangements	2			8			(75%)	5			23			(78%)
Amortization of debt costs	2			2			—%	3			4			(25%)
Total gross interest expense	43			61			(30%)	86			128			(33%)
Less: capitalization	(28		)	(29		)	(3)%	(57		)	(57		)	—%
Net interest expense	$	15		$	32		(53%)	$	29		$	71		(59%)

•

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

•

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


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


•	Capitalized interest remained flat for the six months ended June 30, 2019, compared to the same period in 2018, as an increase in our average cost of debt was offset by the evaluation of natural gas and oil properties over the past twelve months.


•	Capitalized interest increased as a percentage of gross interest expense for the three and six months ended June 30, 2019, compared to the same periods in 2018, primarily due to an increase in our average cost of debt.

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Gain (Loss) on Derivatives



	For the three months ended June 30,					For the six months ended June 30,
(in millions)	2019		2018			2019		2018
Gain (loss) on unsettled derivatives	$	118	$	(56	)	$	96	$	(54	)
Gain on settled derivatives	34		20			24		11
Gain (loss) on derivatives	$	152	$	(36	)	$	120	$	(43	)

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

Loss on Early Extinguishment of Debt

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

Income Taxes



	For the three months ended June 30,						For the six months ended June 30,
(in millions except percentages)	2019			2018			2019			2018
Income tax (benefit) expense	$	15		$	—		$	(411	)	$	—
Effective tax rate	10		%	0		%	(128		%)	0		%

•

As of the first quarter of 2019, we had sustained a three-year cumulative level of profitability. Based on this factor and other positive evidence such as forecasted income, we 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 a discrete tax benefit of $411 million being recorded in the first half of 2019. We expect to retain a valuation allowance of $87 million related to net operating losses in jurisdictions in which we no longer operate.

•

Our low effective tax rate in 2018 was the result of our recognition of a valuation allowance that reduced the deferred tax asset primarily related to our current net operating loss carryforward. A valuation allowance for deferred tax assets, including net operating losses, is recognized when it is more likely than not that some or all of the benefit from the deferred tax asset will not be realized.

New Accounting Standards Implemented in this Report

Refer to Note 18 to the consolidated financial statements of this Quarterly Report for a discussion of new accounting standards which have been implemented.

New Accounting Standards Not Yet Implemented in this Report

Refer to Note 18 to the consolidated financial statements of this Quarterly Report for a discussion of new accounting standards which have not yet been implemented.

LIQUIDITY AND CAPITAL RESOURCES

We depend on funds generated from our operations, our cash and cash equivalents balance, our revolving credit facility and capital markets as our primary sources of liquidity. Although we have financial flexibility with our cash balance and the ability to draw on our $2.0 billion revolving credit facility (less outstanding letters of credit, which were approximately $172 million as of June 30, 2019), we continue to be committed to our capital discipline strategy of investing within our cash flow from operations net of changes in working capital, supplemented by a portion of the net proceeds from the Fayetteville Shale sale realized in December 2018.

Our cash flow from operating activities is highly dependent upon the sales prices that we receive for our natural gas and liquids production. Natural gas, oil and NGL prices are subject to wide fluctuations and are driven by market supply and demand, which is impacted by many factors. The sales price we receive for our production is also influenced by our commodity hedging activities. Our derivative contracts allow us to ensure a certain level of cash flow to fund our operations. See “Quantitative and Qualitative Disclosures about Market Risks” in Item 3 and Note 9, in the consolidated financial statements included in this Quarterly Report for further details.

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

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

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

Credit Arrangements and Financing Activities

On April 26, 2018, we replaced our 2016 credit facility with a new revolving credit facility which matures in April 2023. Although the 2018 revolving credit facility currently has a maximum borrowing capacity of $3.5 billion, a borrowing base of $2.1 billion and commitments of $2.0 billion, it is subject to both a borrowing base that is determined semiannually in April and October by the lenders and the permitted lien limitations in our senior note indentures. The borrowing base is subject to change based primarily on drilling results, commodity prices, our future derivative position, the level of capital investing and operating costs. In April 2019, the banks participating in our 2018 credit facility reaffirmed the borrowing base of $2.1 billion. As of June 30, 2019, we had no borrowings outstanding on our 2018 revolving credit facility and $172 million in outstanding letters of credit.

As of June 30, 2019, we were in compliance with all of the covenants of our revolving credit facility in all material respects. We refer you to Note 12 of the consolidated financial statements included in this Quarterly Report for additional discussion of the covenant requirements of our 2018 revolving credit facility. Although we do not anticipate any violations of the financial covenants, our ability to comply with these covenants is dependent upon the success of our exploration and development program and upon factors beyond our control, such as the market prices for natural gas and liquids.

The credit status of the financial institutions participating in our revolving credit facility could adversely impact our ability to borrow funds under the revolving credit facility. Although we believe all of the lenders under the facility have the ability to provide funds, we cannot predict whether each will be able to meet their obligation to us. We refer you to Note 12 to the consolidated financial statements included in this Quarterly Report for additional discussion of our revolving credit facility.

Because of the focused work on refinancing and repayment of our debt during 2017 and 2018, only $265 million, or 11%, of our outstanding debt balance as of June 30, 2019 will come due prior to 2025, with $52 million of that coming due in the next year.

At June 30, 2019, we had a long-term issuer credit rating of Ba2 by Moody’s, a long-term debt rating of BB by S&P and a long-term issuer default rating of BB by Fitch Ratings. Any upgrades or downgrades in our public debt ratings by Moody’s or S&P could decrease or increase our cost of funds, respectively.

Cash Flows



	For the six months ended June 30,
(in millions)	2019			2018
Net cash provided by operating activities	$	543		$	664
Net cash used in investing activities	(560		)	(675		)
Net cash used in financing activities	(29		)	(868		)

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Cash Flow from Operating Activities



	For the six months ended June 30,
(in millions)	2019			2018
Net cash provided by operating activities	$	543		$	664
Less: Changes in working capital	(66		)	(44		)
Net cash provided by operating activities, net of changes in working capital	$	477		$	620

•

Net cash provided by operating activities decreased 18%, or $121 million, for the six months ended June 30, 2019, compared to the same period in 2018, primarily due to a $191 million decrease as a result of the December 2018 Fayetteville Shale sale and a $73 million decrease resulting from lower commodity prices. These decreases were partially offset by an $83 million increase associated with increased production, a $41 million increase as a result of reduced interest costs and a $22 million change in working capital.

•

Net cash generated from operating activities, net of changes in working capital, provided 69% of our cash requirements for capital investments for the six months ended June 30, 2019, compared to providing 84% of our cash requirements for capital investments for the same period in 2018. While we front-load our capital programs into the earlier quarters in the year, we remain committed to our capital discipline strategy of investing within our cash flow from operations, net of changes in working capital, supplemented by a portion of the net proceeds from the Fayetteville Shale sale.

Cash Flow from Investing Activities


•	Total E&P capital investing decreased $29 million for the three months ended June 30, 2019, compared to the same period in 2018, due to a $22 million decrease in direct E&P capital investing and a $7 million decrease in capitalized interest and internal costs, as compared to the same period in 2018.


•	Total E&P capital investing decreased $38 million for the six months ended June 30, 2019, compared to the same period in 2018, due to a $27 million decrease in direct E&P capital investing and a $11 million decrease in capitalized interest and internal costs, as compared to the same period in 2018.



	For the six months ended June 30,
(in millions)	2019		2018
Cash Flows from Investing Activities
Additions to properties and equipment	$	586	$	684
Adjustments for capital investments
Changes in capital accruals	105		52
Other	2		5
Total capital investing	$	693	$	741

Capital Investing



	For the three months ended June 30,				Increase/(Decrease)	For the six months ended June 30,				Increase/(Decrease)
(in millions except percentages)	2019		2018		Increase/(Decrease)	2019		2018		Increase/(Decrease)
E&P capital investing	$	367	$	396	(7%)	$	692	$	730	(5%)
Midstream capital investing⁽¹⁾	—		5		(100%)	—		9		(100%)
Other capital investing	1		2		(50)%	1		2		(50)%
Total capital investing	$	368	$	403	(9%)	$	693	$	741	(6%)

໿


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

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	For the three months ended June 30,				For the six months ended June 30,
(in millions)	2019		2018		2019		2018
E&P Capital Investments by Type:
Exploratory and development drilling, including workovers	$	284	$	311	$	535	$	566
Acquisitions of properties	16		16		23		36
Seismic expenditures	1		1		2		2
Water infrastructure project	11		—		26		13
Drilling rigs and other	9		15		11		7
Capitalized interest and expenses	46		53		95		106
Total E&P capital investments	$	367	$	396	$	692	$	730

E&P Capital Investments by Area:
Northeast Appalachia	$	126	$	149	$	232	$	260
Southwest Appalachia	223		220		421		422
Fayetteville Shale	—		10		—		25
New Ventures & Other ⁽¹⁾	18		17		39		23
Total E&P capital investments	$	367	$	396	$	692	$	730


(1)	Includes $11 million and $26 million for the three and six months ended June 30, 2019, respectively, and $13 million for the six months ended June 30, 2018 related to our water infrastructure project.



	For the three months ended June 30,		For the six months ended June 30,
	2019	2018	2019	2018
Gross Operated Well Count Summary:
Drilled	41	37	71	69
Completed	40	56	71	85
Wells to sales	36	45	55	78

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

Cash Flow from Financing Activities



(in millions except percentages)	June 30, 2019			December 31, 2018			Increase/(Decrease)
Debt ⁽¹⁾	$	2,319		$	2,318		$	1
Equity	3,082			2,362			720
Total debt to capitalization ratio	43		%	50		%

Debt ⁽¹⁾	$	2,319		$	2,318		$	1
Less: Cash and cash equivalents	155			201			(46		)
Debt, net of cash and cash equivalents ⁽²⁾	$	2,164		$	2,117		$	47


(1)	The increase in total debt as of June 30, 2019, as compared to December 31, 2018, relates to the amortization of financing costs during the first half of 2019.


(2)	Debt, net of cash and cash equivalents is a non-GAAP financial measure of a company’s ability to repay its debt if it was all due today.

We refer you to Note 12 of the consolidated financial statements included in this Quarterly Report for additional discussion of our outstanding debt and credit facilities.

Working Capital

•

We had negative working capital of $148 million at June 30, 2019, a $258 million decrease from December 31, 2018, as decreases of $223 million in accounts receivable, as compared to December 2018, related to lower commodity prices, a current liability of $47 million recorded in 2019 related to the implementation of the new lease accounting standard (Topic 842) and $52 million of our long-term debt, which matures in less than a year, being reclassified as a current liability in 2019 were only partially offset by positive changes in the current mark-to-market value of our derivative position, as compared to December 31, 2018.

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•	At December 31, 2018, we had positive working capital of $110 million primarily due to $201 million of cash and cash equivalents resulting from the net proceeds from the Fayetteville Shale sale and an increase in accounts receivable primarily related to the increase in commodity pricing in December 2018, as compared to December 2017.

Off-Balance Sheet Arrangements

We may enter into off-balance sheet arrangements and transactions that can give rise to material off-balance sheet obligations. As of June 30, 2019, our material off-balance sheet arrangements and transactions include operating service arrangements and $172 million in letters of credit outstanding against our 2018 revolving credit facility. There are no other transactions, arrangements or other relationships with unconsolidated entities or other persons that are reasonably likely to materially affect our liquidity or availability of our capital resources. For more information regarding off-balance sheet arrangements, we refer you to “Contractual Obligations and Contingent Liabilities and Commitments” in our 2018 Annual Report.

Contractual Obligations and Contingent Liabilities and Commitments

We have various contractual obligations in the normal course of our operations and financing activities. Other than the firm transportation and gathering agreements discussed below, there have been no material changes to our contractual obligations from those disclosed in our 2018 Annual Report.

Contingent Liabilities and Commitments

As of June 30, 2019, our contractual obligations for demand and similar charges under firm transportation and gathering agreements to guarantee access capacity on natural gas and liquids pipelines and gathering systems totaled approximately $8.5 billion, $966 million of which related to access capacity on future pipeline and gathering infrastructure projects that still require the granting of regulatory approvals and/or additional construction efforts. This amount also included guarantee obligations of up to $362 million. As of June 30, 2019, future payments under non-cancelable firm transportation and gathering agreements are as follows:



	Payments Due by Period
(in millions)	Total		Less than 1 Year		1 to 3 Years		3 to 5 Years		5 to 8 years		More than 8 Years
Infrastructure currently in service	$	7,501	$	702	$	1,304	$	1,097	$	1,511	$	2,887
Pending regulatory approval and/or construction ⁽¹⁾	966		9		78		121		196		562
Total transportation charges	$	8,467	$	711	$	1,382	$	1,218	$	1,707	$	3,449


(1)	Based on the estimated in-service dates as of June 30, 2019.

Included in the transportation charges above are $108 million (potentially due in less than one year) and $54 million (potentially due in one to two years) related to certain agreements that remain in the name of our marketing affiliate but are expected to be paid in full by Flywheel Energy Operating, LLC, the purchaser of the Fayetteville Shale assets. Of these amounts, we may be obligated to reimburse Flywheel Energy Operating, LLC for a portion of volumetric shortfalls during 2019 and 2020 (up to $82 million) under these transportation agreements and have currently recorded a $68 million liability as of June 30, 2019, down from $88 million recorded at December 31, 2018.

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

During the second quarter of 2019, we executed an agreement to convey our purchase option in our headquarters office building to a third-party, which closed on the purchase of the building in July 2019. Concurrent with the closing of the building sale, we terminated our existing lease agreement and entered into a new lease agreement for a smaller portion of the headquarters office building in July 2019, resulting in an estimated annual savings of $7 million to $8 million over the next ten years.

Substantially all of our employees are covered by defined benefit and postretirement benefit plans. For the six months ended June 30, 2019, we have contributed $9 million to the pension and postretirement benefit plans. We expect to contribute an additional $3 million to our pension and postretirement benefit plans during the remainder of 2019. We recognized liabilities of $41 million and $47 million as of June 30, 2019 and December 31, 2018, respectively, as a result of the underfunded status of our pension and other postretirement benefit plans. See Note 15 to the consolidated financial statements included in this Quarterly Report for additional discussion about our pension and other postretirement benefits.

We are subject to various litigation, claims and proceedings that arise in the ordinary course of business, such as for alleged breaches of contract, miscalculation of royalties, employment matters, traffic incidents, pollution, contamination, encroachment on others’ property or nuisance. We accrue for such items when a liability is both probable and the amount can be reasonably

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estimated. Management believes that current litigation, claims and proceedings, individually or in aggregate and after taking into account insurance, are not likely to have a material adverse impact on our financial position, results of operations or cash flows, although it is possible that adverse outcomes could have a material adverse effect on our results of operations or cash flows for the period in which the effect of that outcome becomes reasonably estimable. Many of these matters are in early stages, so the allegations and the damage theories have not been fully developed, and are all subject to inherent uncertainties; therefore, management’s view may change in the future.

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

For further information, we refer you to “Litigation” and “Environmental Risk” in Note 13 to the consolidated financial statements included in Item I of Part I of this Quarterly Report.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Market risks relating to our operations result primarily from the volatility in commodity prices, basis differentials and interest rates, as well as service costs and credit risk concentrations. We use fixed price swap agreements, options, basis swaps and interest rate swaps to reduce the volatility of earnings and cash flow due to fluctuations in the prices of natural gas, oil and certain NGLs along with interest rates. Our Board of Directors has approved risk management policies and procedures to utilize financial products for the reduction of defined commodity price risk. Utilization of financial products for the reduction of interest rate risks is also overseen by our Board of Directors. These policies prohibit speculation with derivatives and limit swap agreements to counterparties with appropriate credit standings.

Credit Risk

Our exposure to concentrations of credit risk consists primarily of trade receivables and derivative contracts associated with commodities trading. Concentrations of credit risk with respect to receivables are limited due to the large number of our purchasers and their dispersion across geographic areas. No single purchaser accounted for greater than 10% of revenues as of June 30, 2019. At December 31, 2018, two subsidiaries of Royal Dutch Shell Plc in aggregate accounted for approximately 10.4% of the quarter’s total natural gas, oil and NGL sales. We believe that the loss of any one customer would not have an adverse effect on our ability to sell our natural gas, oil and NGL production. See “Commodities Risk” below for discussion of credit risk associated with commodities trading.

Interest Rate Risk

As of June 30, 2019, we had approximately $2.3 billion of outstanding senior notes with a weighted average interest rate of 6.68%, and no borrowings under our revolving credit facility. We currently have an interest rate swap in effect to mitigate a portion of our exposure to volatility in interest rates. At June 30, 2019, we had a long-term issuer credit rating of Ba2 by Moody’s, a long-term debt rating of BB by S&P and a long-term issuer default rating of BB by Fitch Ratings. Any upgrades or downgrades in our public debt ratings by Moody’s or S&P could decrease or increase our cost of funds, respectively.



	Expected Maturity Date
($ in millions)	2019			2020			2021			2022			2023				Thereafter			Total
Fixed rate payments ⁽¹⁾	$	—		$	52		$	—		$	213		$	—			$	2,077		$	2,342
Weighted average interest rate	—		%	5.30		%	—		%	4.10		%	—		%		6.98		%	6.68		%

Variable rate payments ⁽¹⁾	$	—		$	—		$	—		$	—		$	—		⁽¹⁾	$	—		$	—		⁽¹⁾
Weighted average interest rate	—		%	—		%	—		%	—		%	3.88		%		—		%	3.88		%


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

Commodities Risk

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

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The primary market risks relating to our derivative contracts are the volatility in market prices and basis differentials for our production. However, the market price risk is offset by the gain or loss recognized upon the related sale or purchase of the production that is financially protected. Credit risk relates to the risk of loss as a result of non-performance by our counterparties. The counterparties are primarily major banks and integrated energy companies that management believes present minimal credit risks. The credit quality of each counterparty and the level of financial exposure we have to each counterparty are closely monitored to limit our credit risk exposure. Additionally, we perform both quantitative and qualitative assessments of these counterparties based on their credit ratings and credit default swap rates where applicable. We have not incurred any counterparty losses related to non-performance and do not anticipate any losses given the information we have currently. However, we cannot be certain that we will not experience such losses in the future. We refer you to Note 9 of the consolidated financial statements included in this Quarterly Report for additional details about our derivative instruments.

ITEM 4. CONTROLS AND PROCEDURES

Disclosure Controls and Procedures

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

Changes in Internal Control over Financial Reporting

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

PART II - OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

Refer to “Litigation” and “Environmental Risk” in Note 13 to the consolidated financial statements included in Item 1 of Part I of this Quarterly Report for a discussion of the Company’s legal proceedings.

ITEM 1A. RISK FACTORS

There were no additions or material changes to our risk factors as disclosed in Item 1A of Part I in the Company’s 2018 Annual Report.

ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

Not applicable.

ITEM 3. DEFAULTS UPON SENIOR SECURITIES

Not applicable.

ITEM 4. MINE SAFETY DISCLOSURES

Our sand mining operations in support of our E&P business are subject to regulation by the Federal Mine Safety and Health Administration under the Federal Mine Safety and Health Act of 1977. Information concerning mine safety violations or other regulatory matters required by Section 1503(a) of the Dodd-Frank Wall Street Reform and Consumer Protection Act and Item 104 of Regulation S-K (17 CFR 229.106) is included in Exhibit 95.1 to this Quarterly Report.

ITEM 5. OTHER INFORMATION

On May 21, 2019, the Company adopted the Southwestern Energy Company Non-Employee Director Deferred Compensation Plan allowing directors who are not employees of the Company to defer receipt of cash and/or equity components of their compensation.

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ITEM 6. EXHIBITS



10.1	Third Amendment to Southwestern Energy Company 2013 Incentive Plan. (Incorporated by reference to Exhibit 4.1 of the Registrant’s Current Report on Form 8-K filed on May 22, 2019)
10.2*	Southwestern Energy Company Non-Employee Director Deferred Compensation Plan
10.3*	Form of Deferral Agreement under the Non-Employee Director Deferred Compensation Plan
10.4*	Southwestern Energy Company 2013 Incentive Plan Form of Restricted Stock Unit Award Agreement for Directors, effective July 1, 2019
(31.1)*	Certification of CEO filed pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
(31.2)*	Certification of CFO filed pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
(32.1)*	Certification of CEO furnished pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
(32.2)*	Certification of CFO furnished pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
(95.1)*	Mine Safety Disclosure
(101.INS)	Interactive Data File Instance Document
(101.SCH)	Interactive Data File Schema Document
(101.CAL)	Interactive Data File Calculation Linkbase Document
(101.LAB)	Interactive Data File Label Linkbase Document
(101.PRE)	Interactive Data File Presentation Linkbase Document
(101.DEF)	Interactive Data File Definition Linkbase Document

*Filed herewith

Signatures

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



		SOUTHWESTERN ENERGY COMPANY
		Registrant

Dated:	August 6, 2019	/s/ JULIAN M. BOTT
		Julian M. Bott Executive Vice President and Chief Financial Officer

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