10-Q

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C.  20549
Form 10-Q
(Mark One)
[X]   Quarterly Report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 For the quarterly period endedMarch 31, 2017
Or
[  ] 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)
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 and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted 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 and post such files).  Yes☒  No ☐ Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, smaller reporting company, or an emerging growth company.  See the definitions of “large accelerated filer”, “accelerated filer”, “smaller reporting company” and “emerging growth company” in Rule 12b-2 of the Exchange Act.
Large accelerated filer ☒	Accelerated filer ☐	Non-accelerated filer ☐		Smaller reporting company ☐	Emerging growth company☐
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ☐     No ☒
Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date:
Class			Outstanding as of April 25, 2017
Common Stock, Par Value $0.01			505,869,805

SOUTHWESTERN ENERGY COMPANY
INDEX TO FORM 10-Q
FOR THE QUARTERLY PERIOD ENDED MARCH 31, 2017
PART I – FINANCIAL INFORMATION
Item 1.	Financial Statements	3
	Condensed Consolidated Statements of Operations	3
	Condensed Consolidated Statements of Comprehensive Income	4
	Condensed Consolidated Balance Sheets	5
	Condensed Consolidated Statements of Cash Flows	6
	Condensed Consolidated Statements of Changes in Equity	7
	Notes to Unaudited Condensed Consolidated Financial Statements	8
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	27
	Results of Operations	29
	Liquidity and Capital Resources	33
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	38
Item 4.	Controls and Procedures	39
PART II – OTHER INFORMATION
Item 1.	Legal Proceedings	39
Item 1A.	Risk Factors	39
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	39
Item 3.	Defaults Upon Senior Securities	39
Item 4.	Mine Safety Disclosures	39
Item 5.	Other Information	39
Item 6.	Exhibits	40

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:

1

· 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;

· 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 recent 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 the ability to obtain and maintain permits, any increase in severance or similar taxes, and legislation relating to hydraulic fracturing, climate and over-the-counter derivatives;

· the impact of the adverse outcome of any material litigation against us;

· the effects of weather;

· increased competition and regulation;

· 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 publicly update 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.

2

PART I – FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS.

SOUTHWESTERN ENERGY COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(Unaudited)
	For the three months ended
	March 31,
	2017		2016
Operating Revenues:
Gas sales	$	503	$	315
Oil sales		23		11
NGL sales		40		17
Marketing		253		198
Gas gathering		27		38
		846		579
Operating Costs and Expenses:
Marketing purchases		251		196
Operating expenses		147		165
General and administrative expenses		50		54
Restructuring charges		–		64
Depreciation, depletion and amortization		106		143
Impairment of natural gas and oil properties		–		1,034
Taxes, other than income taxes		26		23
		580		1,679
Operating Income (Loss)		266		(1,100)
Interest Expense:
Interest on debt		58		53
Other interest charges		2		2
Interest capitalized		(28)		(41)
		32		14
Gain (Loss) on Derivatives		116		(14)
Loss on Early Extinguishment of Debt		(1)		–
Other Income (Loss), Net		2		(3)
Income (Loss) Before Income Taxes		351		(1,131)
Provision (Benefit) for Income Taxes:
Deferred		–		1
		–		1
Net Income (Loss)	$	351	$	(1,132)
Mandatory convertible preferred stock dividend		27		27
Participating securities - mandatory convertible preferred stock		43		–
Net Income (Loss) Attributable to Common Stock	$	281	$	(1,159)
Earnings (Loss) Per Common Share:
Basic	$	0.57	$	(3.03)
Diluted	$	0.57	$	(3.03)
Weighted Average Common Shares Outstanding:
Basic		493,068,000		382,870,847
Diluted		494,494,995		382,870,847

The accompanying notes are an integral part of these

unauditedcondensed consolidated financial statements.

3

SOUTHWESTERN ENERGY COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
(Unaudited)
	For the three months ended
	March 31,
	2017		2016
Net income (loss)	$	351	$	(1,132)
Change in value of pension and other postretirement liabilities:
Amortization of prior service cost and net loss included in net periodic pension cost (1)		–		1
Change in currency translation adjustment		–		3
Comprehensive income (loss)	$	351	$	(1,128)

(1)     Net of $1 million in taxes for the three months ended March 31, 2017 and 2016.

The accompanying notes are an integral part of these

unauditedcondensed consolidated financial statements.

4

SOUTHWESTERN ENERGY COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
(Unaudited)
	March 31,		December 31,
	2017		2016
ASSETS	(in millions)
Current assets:
Cash and cash equivalents	$	1,382	$	1,423
Accounts receivable, net		310		363
Derivative assets		58		51
Other current assets		39		35
Total current assets		1,789		1,872
Natural gas and oil properties, using the full cost method, including $2,078million as of March 31, 2017 and $2,105 million as of December 31, 2016 excluded from amortization		22,942		22,653
Gathering systems		1,306		1,299
Other		536		537
Less: Accumulated depreciation, depletion and amortization		(19,641)		(19,534)
Total property and equipment, net		5,143		4,955
Other long-term assets		264		249
TOTAL ASSETS	$	7,196	$	7,076
LIABILITIES AND EQUITY
Current liabilities:
Short-term debt	$	266	$	41
Accounts payable		436		473
Taxes payable		50		59
Interest payable		29		74
Dividends payable		27		27
Derivative liabilities		280		355
Other current liabilities		33		35
Total current liabilities		1,121		1,064
Long-term debt		4,364		4,612
Pension and other postretirement liabilities		47		49
Other long-term liabilities		386		434
Total long-term liabilities		4,797		5,095
Commitments and contingencies (Note 10)
Equity:
Common stock, $0.01 par value; 1,250,000,000 shares authorized; issued 502,497,469shares as of March 31, 2017 (does not include 3,346,865 shares issued on April 17, 2017 on account of a dividend declared on March 21, 2017) and 495,248,369 as of December 31, 2016		5		5
Preferred stock, $0.01 par value, 10,000,000 shares authorized, 6.25% Series B Mandatory Convertible, $1,000 per share liquidation preference, 1,725,000 shares issued and outstanding as of March 31, 2017 and December 31, 2016, conversion in January 2018		–		–
Additional paid-in capital		4,687		4,677
Accumulated deficit		(3,374)		(3,725)
Accumulated other comprehensive loss		(39)		(39)
Common stock in treasury,31,269 shares as of March 31, 2017 and December 31, 2016		(1)		(1)
Total equity		1,278		917
TOTAL LIABILITIES AND EQUITY	$	7,196	$	7,076
The accompanying notes are an integral part of these
unaudited condensed consolidated financial statements.

5

SOUTHWESTERN ENERGY COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
	For the three months ended
	March 31,
	2017		2016
	(in millions)
Cash Flows From Operating Activities:
Net income (loss)	$	351	$	(1,132)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization		106		143
Impairment of natural gas and oil properties		–		1,034
Amortization of debt issuance costs		2		2
Deferred income taxes		–		1
(Gain) loss on derivatives, unsettled		(146)		21
Stock-based compensation		6		9
Restructuring charges		–		42
Loss on early extinguishment of debt		1		–
Other		(2)		5
Change in assets and liabilities:
Accounts receivable		53		103
Accounts payable		(13)		(124)
Taxes payable		(8)		(12)
Interest payable		(24)		(11)
Other assets and liabilities		(14)		11
Net cash provided by operating activities		312		92
Cash Flows From Investing Activities:
Capital investments		(340)		(196)
Proceeds from sale of property and equipment		2		–
Other		4		–
Net cash used in investing activities		(334)		(196)
Cash Flows From Financing Activities:
Payments on short-term debt		(25)		–
Payments on revolving credit facility		–		(864)
Borrowings under revolving credit facility		–		2,600
Payments on commercial paper		–		(242)
Borrowings under commercial paper		–		242
Change in bank drafts outstanding		6		(19)
Preferred stock dividend		–		(27)
Other		–		(4)
Net cash provided by (used in) financing activities		(19)		1,686
Increase (decrease) in cash and cash equivalents		(41)		1,582
Cash and cash equivalents at beginning of year		1,423		15
Cash and cash equivalents at end of period	$	1,382	$	1,597

The accompanying notes are an integral part of these

unaudited condensed consolidated financial statements.

6

SOUTHWESTERN ENERGY COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY

(Unaudited)

Common Stock

Preferred Stock

Additional

Accumulated Other

Common

Shares

Shares

Paid-In

Accumulated

Comprehensive

Stock in

Issued

Amount

Issued

Capital

Deficit (1)

Income (Loss)

Treasury

Total

(in millions, except share amounts)

Balance at December 31, 2016

495,248,369

$

5

1,725,000

$

4,677

$

(3,725)

$

(39)

$

(1)

$

917

Comprehensive income:

Net income

–

–

–

–

351

–

–

351

Other comprehensive income

–

–

–

–

–

–

–

–

Total comprehensive income

–

–

–

–

–

–

–

351

Stock-based compensation

–

–

–

10

–

–

–

10

Preferred stock dividend (2)

2,751,410

–

–

–

–

–

–

–

Exercise of stock options

–

–

–

–

–

–

–

–

Issuance of restricted stock

4,549,122

–

–

–

–

–

–

–

Cancellation of restricted stock

(113,185)

–

–

–

–

–

–

–

Performance units vested

121,208

–

–

–

–

–

–

–

Tax withholding – stock compensation

(59,455)

–

–

–

–

–

–

–

Balance at March 31, 2017

502,497,469

$

5

1,725,000

$

4,687

$

(3,374)

$

(39)

$

(1)

$

1,278

(1) Includes a net cumulative-effect adjustment of $59 million related to the recognition of previously unrecognized windfall tax benefits resulting from the adoption of ASU 2016-09 as of the beginning of 2017.  This adjustment was offset by an increase in net deferred tax assets and the related income tax valuation allowance of the same amount.

(2) Does not include 3,346,865 shares issued on April 17, 2017 and distributed to holders of the Company's mandatory convertible preferred stock.

The accompanying notes are an integral part of these

unaudited condensed consolidated financial statements.

7

SOUTHWESTERN ENERGY COMPANY AND SUBSIDIARIES

NOTES TO UNAUDITED CONDENSED 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 natural gas gathering and marketing businesses (“Midstream Services”).  Southwestern conducts most of its businesses through subsidiaries and operates principally in two segments: E&P and Midstream Services.

Exploration and Production.Southwestern’s primary business is the exploration for and production of natural gas, oil and NGLs, with current operations principally focused on the development of unconventional natural gas reservoirs located in Pennsylvania, West Virginia and Arkansas.  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.”  The Company’s operations in Arkansas are primarily focused on an unconventional natural gas reservoir known as the Fayetteville Shale.  Southwestern has activities ongoing in Colorado and Louisiana, along with other areas in which itis currently assessing new development opportunities.  The Company also has drilling rigs located in Pennsylvania, West Virginia and Arkansas, as well as in other operating areas, and provides oilfield products and services, principally serving its E&P operations.

Midstream Services.Through the Company’s affiliated midstream subsidiaries, Southwestern engages in natural gas gathering activities in Arkansas and Louisiana. These activities primarily support the Company’s E&P operations and generate revenue from fees associated with the gathering of natural gas.Southwestern’s marketing activities capture opportunities that arise through the marketing and transportation of the natural gas, oil and NGLs produced in its E&P operations.

The accompanying unaudited condensed 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 unaudited condensed 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 unaudited condensed consolidated financial statements be read in conjunction with the consolidated financial statements and the notes thereto included in the Company’s Annual Report for the year ended December 31, 2016 (“2016 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 2016 Annual Report.

8

(2) CASH AND CASH EQUIVALENTS

The following table presents a summary of cash and cash equivalents as of March 31, 2017 and December 31, 2016:

	March 31,		December 31,
	2017		2016
	(in millions)
Cash	$	265	$	254
Marketable securities (1)		1,117		1,169
Total cash and cash equivalents	$	1,382	$	1,423

(1) Consists ofgovernment stable value money market funds.

(3) REDUCTION IN WORKFORCE

In January 2016, the Company announced a 40% workforce reduction as a result of lower anticipated drilling activity.  This reduction was substantially completedin the first quarter of 2016.  In April 2016, the Company also partially restructured executive management, which was substantially completed in the second quarter of 2016.

The following table presents a summary of the restructuring charges for the threemonths ended March 31, 2016:

	For the three months ended
	March 31, 2016
	(in millions)
Severance (including payroll taxes)	$	42
Stock-based compensation		18
Pension and other postretirement benefits		3
Outplacement services, other		1
Total restructuring charges (1)	$	64

(1) Total restructuring charges were $61 million and $3 million for the Company’s E&P and Midstream Services segments, respectively.

Severance payments and other separation costs related to restructuring were substantially completed by the end of 2016.

(4) 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 costsare 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 designatedfor 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 $2.73 per MMBtu, West Texas Intermediate oil of $44.10 per barrel and NGLs of $10.17 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 and did not result in a ceiling test impairmentat March 31, 2017. The Company had no hedge positionsthat were designated for hedge accountingas of March 31, 2017.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.

9

Using the average quoted price from the first day of each month from the previous 12 months for Henry Hub natural gas of $2.40 per MMBtu, West Texas Intermediate oil of $42.77 per barrel and NGLs of $5.76 per barrel, adjusted for differentials, the net book value of the Company’s United States natural gas and oil properties exceeded the ceiling by $641 million (net of tax) at March 31, 2016 and resulted in a non-cash ceiling test impairment.The Company had no hedge positions that were designated for hedge accounting as of March 31, 2016.

(5) EARNINGS PER SHARE

Basic earnings per common share is computed by dividing net income (loss) 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 July 2016, the Company completed an underwritten public offering of 98,900,000 shares of its common stock, with an offering price to the public of $13.00 per share.  Net proceeds from the common stock offering were approximately $1,247 million, after underwriting discount and offering expenses.  The proceeds from the offering were used to repay $375 million of the $750 million term loan entered into in November 2015 and to settle certain tender offers by purchasing an aggregate principal amount of approximately $700 million of the Company’s outstanding senior notes due in the first quarter of 2018.  The remaining proceeds of the offering have been used for general corporate purposes.

The mandatory convertible preferred stock issued in January 2015 entitles the holder to a proportional fractional interest in the rights and preferences of the convertible preferred stock, including conversion, dividend, liquidation and voting rights. Unless converted earlier at the option of the holders, on or around January 15, 2018 each share of convertible preferred stock will automatically convert into between 37.0028 and 43.4782 shares of the Company’s common stock (correspondingly, each depositary share will convert into between 1.85014 and 2.17391 shares of the Company’s common stock), subject to customary anti-dilution adjustments, depending on the volume-weighted average price of the Company’s common stock over a 20 trading day averaging period immediately prior to that date.  The total potential shares of common stock resulting from the conversion will range from 63,829,830 to 74,999,895 shares.

The mandatory convertible preferred stock has 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 as such, is considered a participating security.Accordingly, it is 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, participating securities are allocated earnings 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.

10

The following table presents the computation of earnings per share for the threemonths ended March 31, 2017 and 2016:

	For the three months ended March 31,
	2017		2016
	(in millions, except share/per share amounts)
Net income (loss)	$	351	$	(1,132)
Mandatory convertible preferred stock dividend		27		27
Participating securities - mandatory convertible preferred stock		43		–
Net income (loss) attributable to common stock	$	281	$	(1,159)
Number of common shares:
Weighted average outstanding		493,068,000		382,870,847
Issued upon assumed exercise of outstanding stock options		82,845		–
Effect of issuance of non-vested restricted common stock		770,429		–
Effect of issuance of non-vested performance units		573,721		–
Effect of issuance of mandatory convertible preferred stock		–		–
Weighted average and potential dilutive outstanding		494,494,995		382,870,847
Earnings (Loss) per common share:
Basic	$	0.57	$	(3.03)
Diluted	$	0.57	$	(3.03)

The following table presents the common stock shares equivalent excluded from the calculation of diluted earnings per share for the three months ended March 31, 2017 and 2016, as they would have had an antidilutive effect:

	For the three months ended March 31,
	2017	2016
Unvested stock options	1,854,004	5,732,521
Unvested share-based payment	1,212,396	5,779,820
Performance units	–	297,297
Mandatory convertible preferred stock	74,999,895	74,999,895
Total	78,066,295	86,809,533

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(6) DERIVATIVES AND RISK MANAGEMENT

The Company is exposed to volatility in market prices and basis differentials for natural gas, oil and NGLs which impacts the predictability of its cash flows related to the sale of those commodities.  These risks are managed by the Company’s use of certain derivative financial instruments.  As of March 31, 2017 and December 31, 2016, the Company’s derivative financial instruments consisted of fixed price swaps, two-way costless collars, three-way costless collars,basis swaps, put and call options, and interest rate swaps.  A description of the Company’s derivative financial instruments is provided below:

Fixed price swaps	The Company receives a fixed price for the contract and pays a floating market price to the counterparty.
Purchased put options	The Company purchases put options based on an index price from the counterparty by payment of a cash premium.  If the index price is lower than the put’s strike price at the time of settlement, the Company receives from the counterparty such difference between the index price and the purchased put strike price.  If the market price settles above the put’s strike price, no payment is due from either party.
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.  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.
Sold call options	The Company sells call options in exchange for a premium.  If the market price exceeds the strike price of the call option at the time of settlement, the Company pays the counterparty such excess on sold call options. If the market price settles 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.

12

The Company utilizes counterparties for its derivative instruments that it believes are creditworthy at the time the transactions are entered into, and the Company closely monitors the credit ratings of these counterparties. Additionally, the Company performs both quantitative and qualitative assessments of these counterparties based on their credit ratings and credit default swap rates where applicable. However, the events in the financial markets in recent years demonstrate there can be no assurance that a counterparty will be able to meet its obligations to the Company.

The following table provides 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 table presents the notional amount in Bcf, the weighted average contract prices and the fair value by expected maturity dates as of March 31, 2017:

		Weighted Average Price per MMBtu
	Volume (Bcf)	Swaps		Sold Puts		Purchased Puts		Sold Calls		Basis Differential		Fair value at March 31, 2017 (in millions)
Financial protection on production
2017
Fixed price swaps	262	$	3.07	$	–	$	–	$	–	$	–	$	(58)
Two-way costless-collars	65		–		–		2.92		3.34		–		(11)
Three-way costless-collars	102		–		2.29		2.97		3.30		–		(16)
Basis swaps	138		–		–		–		–		(1.04)		(73)
Total	567											$	(158)
2018
Fixed price swaps	68	$	3.02	$	–	$	–	$	–	$	–	$	(1)
Two-way costless-collars	23		–		–		2.97		3.56		–		(6)
Three-way costless-collars	245		–		2.39		2.97		3.37		–		(6)
Basis swaps	20		–		–		–		–		(0.95)		(15)
Total	356											$	(28)
2019
Three-way costless-collars	99	$	–	$	2.50	$	2.95	$	3.31	$	–	$	(2)
Total	99											$	(2)

		Weighted Average Price per MMBtu
	Volume (Bcf)	Sold Calls		Fair value at March 31, 2017 (in millions)
Call options
2017	64	$	3.54	$	(10)	(1)
2018	63		3.50		(14)
2019	52		3.50		(10)
2020	32		3.75		(5)
Total	211			$	(39)

(1) Excludes$5 million in premiums paid related to certain call options recognized as a component of derivative assets within current assets on the unaudited condensed consolidated balance sheet.  As certain call options settle, the premium will be amortized and recognized as a component of gain (loss) on derivatives on the unaudited condensed consolidated statement 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) are summarized below as of March 31, 2017 and December 31, 2016:

	Derivative Assets
	Balance Sheet Classification		Fair Value
			March 31, 2017			December 31, 2016
		(in millions)
Derivatives not designated as hedging instruments:
Fixed price swaps	Derivative assets		$	2		$	–
Two-way costless collars	Derivative assets			11			8
Three-way costless collars	Derivative assets			23			11
Basis swaps	Derivative assets			2			32
Call options	Derivative assets			15			–
Fixed price swaps	Other long-term assets			7			1
Two-way costless collars	Other long-term assets			–			2
Three-way costless collars	Other long-term assets			120			100
Basis swaps	Other long-term assets			–			1
Total derivative assets			$	180	(1)	$	155
	Derivative Liabilities
	Balance Sheet Classification		Fair Value
			March 31, 2017			December 31, 2016
			(in millions)
Derivatives not designated as hedging instruments:
Fixed price swaps	Derivative liabilities		$	68		$	175
Two-way costless collars	Derivative liabilities			28			49
Three-way costless collars	Derivative liabilities			62			70
Basis swaps	Derivative liabilities			89			13
Call options	Derivative liabilities			32			46
Interest rate swaps	Derivative liabilities			1			2
Fixed price swaps	Other long-term liabilities			–			3
Two-way costless collars	Other long-term liabilities			–			9
Three-way costless collars	Other long-term liabilities			105			122
Basis swaps	Other long-term liabilities			1			5
Call options	Other long-term liabilities			22			35
Interest rate swaps	Other long-term liabilities			1			1
Total derivative liabilities			$	409		$	530

(1) Does not include $5 million in premiums paid related to certain call options currently recognized as a component of derivative assets within current assets on the unaudited condensed consolidated balance sheet.  As certain call options settle, the premium will be amortized and recognized as a component of gain (loss) on derivatives on the unaudited condensed consolidated statement of operations.

At March 31, 2017, the net fair value of the Company’s financial instruments related to natural gas was a $227million liability.  The net fair value of the Company’s interest rate swaps was a $2 million liability as of March 31, 2017.

Derivative Contracts Not Designated for Hedge Accounting

As of March 31, 2017, the Company had no positions designated for hedge accounting treatment.  Gains and losses on derivatives that are not designated for hedge accounting treatment, or that do not meet hedge accounting requirements, are recorded as a component of gain (loss) on derivatives on the unaudited condensed consolidated statements of operations.  Accordingly, the gain (loss) on derivatives component of the statements of operations reflects the gains 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 unaudited condensed consolidated statements of operations.

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The following tables summarize the before tax effect of fixed price swaps, purchased put options, two-way costless collars, three-way costless collars, basis swaps, call optionsand interest rate swaps not designated for hedge accounting on the unaudited condensed consolidated statements of operations for the three months ended March 31, 2017 and 2016:

		Gain (Loss) on Derivatives, Unsettled
		Recognized in Earnings
	Consolidated Statement of Operations	For the three months ended
	Classification of Gain (Loss)	March 31,
Derivative Instrument	on Derivatives, Unsettled	2017		2016
		(in millions)
Fixed price swaps	Gain (Loss) on Derivatives	$	118	$	20
Purchased put options	Gain (Loss) on Derivatives		–		15
Two-way costless-collars	Gain (Loss) on Derivatives		31		–
Three-way costless- collars	Gain (Loss) on Derivatives		57		–
Basis swaps	Gain (Loss) on Derivatives		(103)		(3)
Call options	Gain (Loss) on Derivatives		42		(50)
Interest rate swaps	Gain (Loss) on Derivatives		1		(3)
Total gain (loss) on unsettled derivatives		$	146	$	(21)
		Gain (Loss) on Derivatives, Settled (1)
		Recognized in Earnings
	Consolidated Statement of Operations	For the three months ended
	Classification of Gain (Loss)	March 31,
Derivative Instrument	on Derivatives, Settled	2017		2016
		(in millions)
Fixed price swaps	Gain (Loss) on Derivatives	$	(16)	$	4
Two-way costless-collars	Gain (Loss) on Derivatives		(3)		–
Three-way costless-collars	Gain (Loss) on Derivatives		(4)		–
Basis swaps	Gain (Loss) on Derivatives		(1)		4
Call options	Gain (Loss) on Derivatives		(6)		–
Interest rate swaps	Gain (Loss) on Derivatives		–		(1)
Total gain (loss) on settled derivatives (2)		$	(30)	$	7
Total gain (loss) on derivatives		$	116	$	(14)

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

(2) Excluding interest rate swaps, these amounts are included, along with gas sales revenues, in the calculation of the Company’s realized natural gas price.

Derivative Contracts Designated for Hedge Accounting

All derivatives are recognized in the balance sheet as either an asset or liability and are measured at fair value, other than transactions for which normal purchase/normal sale is applied. Certain criteria must be satisfied in order for derivative financial instruments to be designated for hedge accounting.  Unrealized gains and losses related to unsettled derivatives that have been designated for hedge accounting treatment are recorded in either earnings or as a component of other comprehensive income until settled.  In the period of settlement, the Company recognizes the gains and losses from these qualifying hedges in gas sales revenues.As of March 31, 2017 and 2016, the Company had no positions designated for hedge accounting treatment.  

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

The following tables detail the components of accumulated other comprehensive income (loss) and the related tax effects for the three months ended March 31, 2017:

	March 31, 2017
	Pension and Other Postretirement		Foreign Currency		Total
	(in millions)
Beginning balance, December 31, 2016	$	(19)	$	(20)	$	(39)
Other comprehensive income (loss) before reclassifications		–		–		–
Amounts reclassified from other comprehensive income (loss) (1)		–		–		–
Net current-period other comprehensive income (loss)		–		–		–
Ending balance, March 31, 2017	$	(19)	$	(20)	$	(39)

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

1

Details about Accumulated Other Comprehensive Income	Affected Line Item in the Consolidated Statement of Operations	Amount Reclassified from Accumulated Other Comprehensive Income
		For the three months ended March 31, 2017
		(in millions)
Pension and other postretirement:
Amortization of prior service cost and net loss (1)	General and administrative expenses	$	1
	Provision for income taxes		1
	Net income (loss)	$	–
Total reclassifications for the period	Net income (loss)	$	–

(1)     See Note 11 for additional details regarding the Company’s retirement and employee benefit plans.

(8) FAIR VALUE MEASUREMENTS

The carrying amounts and estimated fair values of the Company’s financial instruments as of March 31, 2017 and December 31, 2016 were as follows:

	March 31, 2017				December 31, 2016
	Carrying		Fair		Carrying		Fair
	Amount		Value		Amount		Value
	(in millions)
Cash and cash equivalents	$	1,382	$	1,382	$	1,423	$	1,423
Credit facility		–		–		–		–
Term loan facility due December 2020 (1)		327		327		327		327
Term loan facility due December 2020 (1)		1,191		1,191		1,191		1,191
Senior notes		3,141		3,088		3,166		3,182
Derivative instruments, net (2)		(229)		(229)		(375)		(375)

(1) The maturity date will accelerate to October 2019 if, by that date, the Company has not amended, redeemed or refinanced at least $765 million of its senior notes due in January 2020.

(2) Does not include $5 million in premiums paid related to certain call options currently recognized as a component of derivative assets within current assets on the unaudited condensed consolidated balance sheet.

The carrying values of cash and cash equivalents, accounts receivable, other current assets,accounts payable and other current liabilities on the unaudited condensed 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 yield of the Company’s senior notes.

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The carrying values of the borrowings under the Company’s term loan facilities and unsecured revolving credit facility approximate fair value because the interest rate is variable and reflective of market rates. The Company considers the fair value of its debt to be a Level 2 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 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 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. The Company utilized discounted cash flow models for valuing its interest rate derivatives (Level 2). The net derivative values attributable to the Company’s interest rate derivative contracts as of March 31, 2017 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, purchased put options, two-way costless collars and three-way costless collars (Level 3) 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 futures index, interest rates, volatility and credit worthiness.  The Company’s basis swaps (Level 3) are estimated using third-party calculations based upon forward commodity price curves.

Inputs to the Black-Scholes model, including the volatility input, which is the significant unobservable input for Level 3 fair value measurements, 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.

Assets and liabilities measured at fair value on a recurring basis are summarized below (in millions):

	March 31, 2017
	Fair Value Measurements Using:
	Quoted Prices in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Assets (Liabilities) at Fair Value
Fixed price swap assets	$	–	$	9	$	–	$	9
Two-way costless collars assets		–		–		11		11
Three-way costless collars assets		–		–		143		143
Basis swap assets		–		–		2		2
Call option assets (1)		–		–		15		15
Fixed price swap liabilities		–		(68)		–		(68)
Two-way costless collars liabilities		–		–		(28)		(28)
Three-way costless collars liabilities		–		–		(167)		(167)
Basis swap liabilities		–		–		(90)		(90)
Call option liabilities		–		–		(54)		(54)
Interest rate swap liabilities		–		(2)		–		(2)
Total	$	–	$	(61)	$	(168)	$	(229)

(1) Does not include $5 million in premiums paid related to certain call options currently recognized as a component of derivative assets within current assets on the unaudited condensed consolidated balance sheet.

17

	December 31, 2016
	Fair Value Measurements Using:
	Quoted Prices in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Assets (Liabilities) at Fair Value
Fixed price swap assets	$	–	$	1	$	–	$	1
Two-way costless collars assets		–		–		10		10
Three-way costless collars assets		–		–		111		111
Basis swap assets		–		–		33		33
Fixed price swap liabilities		–		(178)		–		(178)
Two-way costless collars liabilities		–		–		(58)		(58)
Three-way costless collars liabilities		–		–		(192)		(192)
Basis swap liabilities		–		–		(18)		(18)
Call option liabilities		–		–		(81)		(81)
Interest rate swap liabilities		–		(3)		–		(3)
Total	$	–	$	(180)	$	(195)	$	(375)

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 months ended March 31, 2017and 2016.  The fair values of Level 3 derivative instruments are estimated using proprietary valuation models that utilize both market observable and unobservable parameters.  Level 3 instruments presented in the table consist of net derivatives valued using pricing models incorporating assumptions that, in the Company’s judgment, reflect reasonable assumptions a marketplace participant would have used as of March 31, 2017 and 2016.

	For the three months ended
	March 31,
	2017		2016
	(in millions)
Balance at beginning of period	$	(195)	$	3
Total gains (losses):
Included in earnings		13		(34)
Settlements		14		(4)
Transfers into/out of Level 3		–		–
Balance at end of period	$	(168)	$	(35)
Change in gains (losses) included in earnings relating to derivatives still held as of March 31	$	27	$	(38)

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(9) DEBT

The components of debt as of March 31, 2017 and December 31, 2016 consisted of the following:

	March 31, 2017
	Debt Instrument		Unamortized Issuance Expense		Unamortized Debt Discount		Total
		(in millions)
Short-term debt:
7.35% Senior Notes due October 2017	$	15	$	–	$	–	$	15
7.125% Senior Notes due October 2017		25		–		–		25
3.30% Senior Notes due January 2018 (1)		38		–		–		38
7.50% Senior Notes due February 2018 (2)		187		–		–		187
7.15% Senior Notes due June 2018		1		–		–		1
Total short-term debt	$	266	$	–	$	–	$	266
Long-term debt:
Variable rate (3.450% at March 31, 2017) term loan facility, due December 2020(3)		327		(2)		–		325
Variable rate (3.450% at March 31, 2017) term loan facility, due December 2020(3)		1,191		(10)		–		1,181
7.15% Senior Notes due June 2018		25		–		–		25
4.05% Senior Notes due January 2020(1)		850		(4)		–		846
4.10% Senior Notes due March 2022		1,000		(4)		(1)		995
4.95% Senior Notes due January 2025(1)		1,000		(6)		(2)		992
Total long-term debt	$	4,393	$	(26)	$	(3)	$	4,364
Total debt	$	4,659	$	(26)	$	(3)	$	4,630

	December 31, 2016
	Debt Instrument		Unamortized Issuance Expense		Unamortized Debt Discount		Total
		(in millions)
Short-term debt:
7.35% Senior Notes due October 2017	$	15	$	–	$	–	$	15
7.125% Senior Notes due October 2017		25		–		–		25
7.15% Senior Notes due June 2018		1		–		–		1
Total short-term debt	$	41	$	–	$	–	$	41
Long-term debt:
Variable rate (3.220% at December 31, 2016) term loan facility, due December 2020 (3)		327		(2)		–		325
Variable rate (3.220% at December 31, 2016) term loan facility, due December 2020 (3)		1,191		(10)		–		1,181
3.30% Senior Notes due January 2018(1)		38		–		–		38
7.50% Senior Notes due February 2018		212		–		–		212
7.15% Senior Notes due June 2018		25		–		–		25
4.05% Senior Notes due January 2020 (1)		850		(5)		–		845
4.10% Senior Notes due March 2022		1,000		(4)		(1)		995
4.95% Senior Notes due January 2025 (1)		1,000		(7)		(2)		991
Total long-term debt	$	4,643	$	(28)	$	(3)	$	4,612
Total debt	$	4,684	$	(28)	$	(3)	$	4,653

(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 5.05% for the 2018 Notes, 5.80% for the 2020 Notes and 6.70% for the 2025 Notes.

(2) In March 2017, the Company repurchased$25 million of its 7.50% Senior Notes due February 2018 andrecognized a  $1 million loss on the extinguishment of debt.

(3) The maturity date will accelerate to October 2019 if, by that date, the Company has not amended, redeemed or refinanced at least $765 million of its senior notes due in January 2020.

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2016 Credit Facility

In June 2016, the Company reduced its existing $2.0 billion unsecured revolving credit facility to $66 million and entered into a new credit agreement for $1,934 million, consisting of a $1,191 million secured term loan and a new $743 million unsecured revolving credit facility, which matures in December 2020.  The maturity date will accelerate to October 2019 if, by that date, the Company has not amended, redeemed or refinanced at least $765 million of its senior notes due January 2020.  The $1,191 million secured term loan is fully drawn, with approximately $285 million of this balance used to pay down the previous revolving credit facility balance in its entirety.  As of March 31, 2017, there were no borrowings under either revolving credit facility; however, $327 million in letters of credit was outstanding against the 2016 revolving credit facility. 

Loans under the 2016 credit agreement 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 plus applicable margins ranging from 1.750% to 2.500%.  Alternate base rate loans bear interest at the alternate base rate plus the applicable margin ranging from 0.750% to 1.500%.  The interest rate on the term loan facility is determined based upon the Company’s public debt ratings and was 250 basis points over LIBOR as of March 31, 2017.

The new term loan and revolving credit facility contain financial covenants that impose certain restrictions on the Company.  Under the new credit agreement, the Company must maintain a minimum interest coverage of 1.00x in 2017, increasing by 0.25x increments per year to 1.50x in 2019 and 2020.  The Company is also subject to a minimum liquidity requirement of $300 million, which could be increased up to $500 million upon certain conditions, as well as an anti-hoarding provision, requiring unrestricted cash in excess of $100 million to pay down any amounts borrowed under the new revolving credit facility.  The financial covenant with respect to minimum interest coverage consists of EBITDAX divided by consolidated interest expense.  EBITDAX, as defined in our 2016 credit agreement, excludes the effects of interest expense, income taxes, depreciation, depletion and amortization, 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.  Collateral for the new secured term loan is principally the Company’s E&P properties in the Fayetteville Shale area, the equity of its subsidiaries and cash and marketable securities on hand, and the new credit agreement requires a minimum collateral coverage ratio of 1.50x for the 2016 secured term loan.  This collateral also may support all or a part of revolving credit extensions depending on restrictions in the Company’s senior notes indentures.

As of March 31, 2017, the Company was in compliance with all of the covenants of this credit agreement.  Although the Company does not anticipate any violations of the financial covenants, its ability to comply with these covenants is dependent upon the success of its exploration and development program and upon factors beyond the Company’s control, such as the market prices for natural gas, oil and NGLs.

2013 Credit Facility

In December 2013, the Company entered into a credit agreement that exchanged its previous revolving credit facility.  Under the revolving credit facility, the Company had a borrowing capacity of $2.0 billion.  The revolving credit facility was unsecured and was not guaranteed by any subsidiaries.  On March 30, 2016, the Company borrowed $1.55 billion on the revolving credit facility with the proceeds invested in marketable securities.  The $1.55 billion borrowing was repaid on April 1, 2016.  In June 2016, this credit facility was substantially exchanged for a new credit facility comprised of a $1,191million secured term loan and a new $743million revolving credit facility.  The borrowing capacity of the original 2013 credit agreement was reduced from $2.0 billion to $66 million, remains unsecured and the maturity remainsDecember 2018.  As of March 31, 2017, there were no borrowings under this facility.

The existing unsecured 2013 revolving credit facility includes a financial covenant under which the Company may not have total debt in excess of 60% of its total adjusted book capital.  This financial covenant with respect to capitalization percentages excludes the effects of any full cost ceiling impairments, certain hedging activities and the Company’s pension and other postretirement liabilities.  At March 31, 2017, debt constituted 34%of the Company’s adjusted book capital.

2015 Term Facility

In November 2015, the Company entered into a $750 million unsecured three-year term loan credit agreement with various lenders that was utilized to repay borrowings under the revolving credit facility.  The interest rate on the term loan

20

facility is determined based upon the Company’s public debt ratings from Moody’s and S&P and was 250 basis points over LIBOR as of March 31, 2017.  The term loan facility requires prepayment under certain circumstances from the net cash proceeds of sales of equity or certain assets and borrowings outside the ordinary course of business. In June 2016, this term loan agreement was amended to extend the maturity date upon a repayment threshold.  From the net proceeds of the July 2016 equity offering, the Company repaid $375 million of the $750 million unsecured term loan, which had the effect of extending the term loan maturity from November 2018 to December 2020, which will accelerate to October 2019 if, by that date, the Company has not amended, redeemed or refinanced at least $765 million of its senior notes due in January 2020.  In September 2016, the Company repaid an additional $48 million from the proceeds received from the closing of the sale of approximately 55,000 net acres in West Virginia.

Senior Notes

In January 2015, the Company completed a public offering of $350 million aggregate principal amount of its 3.30% senior notes due 2018 (the “2018 Notes”), $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 2018 and 2020 Notes, the “Notes”), with net proceeds from the offering totaling approximately $2.2 billion after underwriting discounts and offering expenses.  The Notes were sold to the public at a price of 99.949% of their face value for the 2018 Notes, 99.897% of their face value for the 2020 Notes and 99.782% of their face value for the 2025 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 5.05% for the 2018 Notes, 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 5.30%,  6.05% and 6.95%, respectively.  The first coupon payment at the higher interest rateswas paid in January 2017.

In July2016,the Company used a portion of the proceeds from the July 2016 equity offering to settle certain tender offersby purchasing an aggregate principal amount of approximately $700 million of its outstanding senior notes due in the first quarter of 2018.

(10) COMMITMENTS AND CONTINGENCIES

Operating Commitments and Contingencies

As of March 31, 2017, 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 $8.7 billion, $3.7 billion 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 $821 million of that amount.  As of March 31, 2017, future payments under non-cancelable firm transportation and gathering agreements are as follows:

	Payments Due by Period
	Total		Less than 1 Year		1 to 3 Years		3 to 5 Years		5 to 8 Years		More than 8 Years
		(in millions)
Infrastructure currently in service	$	5,011	$	592	$	1,139	$	791	$	832	$	1,657
Pending regulatory approval and/or construction (1)		3,661		35		371		474		730		2,051
Total transportation charges	$	8,672	$	627	$	1,510	$	1,265	$	1,562	$	3,708

(1) Based on the estimated in-service dates as of March  31, 2017.

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 or results of operations of the Company.

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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 and pollution, contamination or nuisance. The Company accrues for such items when a liability is both probable and the amount can be reasonably estimated.Management believes that current litigation, claims and proceedings, individually or in aggregate and after taking into account insurance, are not likely to have a material adverse impact on the Company’s financial position, results of operations or cash flows, although it is possible that adverse outcomes could have a material adverse effect on the Company’s 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

Certain of the Company’s subsidiaries are defendants in three cases, two filed in Arkansas state court in 2010 and 2013 and one in federal court in 2014, on behalf of putative classes of royalty owners on some of the Company’s leases located in Arkansas.  The chief complaint in all three cases is that one of the Company’s subsidiaries underpaid the royalty owners by, among other things, deducting from royalty payments costs for gathering, transportation, and compression of natural gas in excess of what is permitted by the relevant leases.  In September and October 2014, the judges in the two Arkansas state actions entered orders certifying classes of royalty owners who are citizens of Arkansas. 

In November 2015, the court in the federal case denied the plaintiff’s motion to certify a class of royalty owners not included in either of the two state cases.  In April 2016, the court certified a broader class that includes Arkansas residents and citizens.  Class members were notified of the pending action in late 2016, and the period to “opt out” of the class has expired.  The plaintiff in the federal case presented two alternative damages theories.  Under one theory, plaintiffs have asserted that obligations to affiliates are not “incurred” and therefore the exploration and production subsidiary was not entitled to deduct any post-production costs; the federal court has granted partial summary judgment for the Company’s subsidiaries on this theory.  Under another theory, plaintiffs assert that the gathering and treating rates the Company deducted from royalty payments exceeded the affiliates’ actual costs or otherwise were not reasonable.  The class representative’s expert’s report alleges class-wide damages in this case of approximately $98 million,  before interest and statutory amounts.  The class is also seeking punitive damages.  The Company moved for summary judgment on all claims.  The court granted the motion in part and denied it in part and has set a trial date in the second quarter of 2017.

The Company’s subsidiaries appealed the class certification order in the state cases. In December 2016, the Arkansas Supreme Court affirmed the certifications.  These cases are now before the Arkansas trial judges.  The precise configuration of the classes has not been determined, particularly in light of the overlapping composition of the class in the federal case.  One of the state cases has been set for trial in the third quarter of 2017.  No date for trial has been set in the other state case.

In addition, in September 2015 three cases were filed in Arkansas state court on behalf of a total of 248 individually named plaintiffs.  Each case asserts complaints that are in substance virtually identical to the above-described case.  The Company and its subsidiaries have removed two of the cases to federal court, and those cases have been assigned to the court in which the above-described federal case is pending.  All three cases have been stayed.

Management believes that, in all of the above cases, the deductions from royalty payments as calculated are permitted and isvigorously defending the cases.  The Company’s assessment may change in the future due to the occurrence of certain events, such as adverse judgments, and such a re-assessment could lead to the determination that the potential liability is probable and could be material to the Company’s results of operations, financial position or cash flows.

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.No liability has been recognized in connection with these indemnifications.

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(11) PENSION PLAN AND OTHER POSTRETIREMENT BENEFITS

The Company has defined pension and postretirement benefit plans which cover substantially all of the Company’s employees. Net periodic pension costs include the following components for the three months ended March 31, 2017 and 2016:  

	Pension Benefits
	For the three months ended
	March 31,
	2017		2016
	(in millions)
Service cost	$	2	$	4
Interest cost		1		2
Expected return on plan assets		(1)		(2)
Amortization of prior service cost		–		–
Amortization of net loss		1		–
Net periodic benefit cost	$	3	$	4

The Company’s other postretirement benefit plan had a net periodic benefit cost of $1 million for the three months ended March 31, 2017 and 2016.  

As of March 31, 2017, the Company has contributed $5million to the pension and other postretirement benefit plans in 2017.  The Company expects to contribute an additional $9 million to its pension plan during the remainder of 2017.  The Company recognized a liability of $34 million and $13 million related to its pension and other postretirement benefits, respectively, as of March 31, 2017, compared to a liability of $36 million and $13 million as of December 31, 2016.  The Company used an assumption of 4.60%during the first quarter of 2016 for both the pension and other postretirement benefit plans.In January 2016, the Company initiated a reduction in workforce that was substantially completed by the end of the first quarter of 2016.  The impact of the workforce reduction on the Company’s pension and other postretirement benefit costs was not recognized until subsequent quarters in 2016 due to the delayed timing of actuarial data available.  The Company updated the discount rate currently used in the measurement of the benefit obligation of the pension plan and other postretirement benefits plan to 4.20% in the second quarter of 2016. 

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 plan. Shares of the Company’s common stock purchased under the terms of the Non-Qualified Plan are presented as treasury stock and totaled 11,686 shares at March 31, 2017, compared to 31,269shares at December 31, 2016.

(12) STOCK-BASED COMPENSATION

The Company recognized the following amounts in employee stock-based compensation costs for the three months ended March 31, 2017 and 2016:

	For the three months ended
	March 31,
	2017		2016
	(in millions)
Stock-based compensation cost – expensed (1)	$	6	$	23
Stock-based compensation cost – capitalized	$	4	$	3

(1) Includes $18 million related to the reduction in workforce for the three months ended March 31, 2016.

In January 2016, the Company announced a 40% workforce reduction that was substantially completed by the end of March 2016.  In April 2016, the Company also partially restructured executive management, which was substantially completed in the second quarter of 2016.  Affected employees were offered a severance package that included, if applicable, amendments to certain outstanding equity awards that modified forfeiture provisions on separation from the Company.  As a result, certain unvested stock-based equity awards became fully vested at the time of separation.  These shares were revalued and recognized immediately as a component of restructuring charges on the Company’s unaudited condensed consolidated statements of operations.  The unvested portion of equity-based performance units was forfeited upon separation from the Company.

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As of March 31, 2017, there was $96 million of total unrecognized compensation cost related to the Company’s unvested stock option grants, restricted stock grants and performance units.  This cost is expected to be recognized over a weighted-average period of 3years.

Stock Options

The following table summarizes stock option activity for the three months ended March 31, 2017 and provides information for options outstanding and options exercisable as of March 31, 2017:

	Number		Weighted Average
	of Options		Exercise Price
	(in thousands)		(per share)
Outstanding at December 31, 2016		5,416	$	23.46
Granted		1,322		8.59
Exercised		–		–
Forfeited or expired		(17)		45.57
Outstanding at March 31, 2017		6,721		20.48
Exercisable at March 31, 2017		3,537	$	29.34

Restricted Stock

The following table summarizes restricted stock activity for the three months ended March 31, 2017 and provides information for unvested shares as of March 31, 2017:  

	Number		Weighted Average
	of Shares		Fair Value
	(in thousands)		(per share)
Unvested shares at December 31, 2016		3,321	$	11.85
Granted		4,549		8.59
Vested		(70)		13.45
Forfeited		(113)		10.05
Unvested shares at March 31, 2017		7,687	$	9.93

Equity-Classified Performance Units

The following table summarizes performance unit activity for the three months ended March 31, 2017 to be paid out in Company stock and provides information for unvested units as of March 31, 2017.  The performance units awarded in 2013 and 2014 included a market condition based on relative Total Shareholder Return (“TSR”) and a performance condition based on the Company's Present Value Index (“PVI”), collectively the “Performance Measures.”The fair value of the TSR market conditionis based on a Monte Carlo model and is amortized to compensation expense on a straight-line basis over the vesting period of the award. The fair value of the PVI performance condition is based on economic analysis for each investment opportunity based upon the expected present value added for each dollar to be invested and amortized to compensation expense on a straight line basis over the vesting period of the award. The performance unit awards granted in 2015, 2016 and during the first quarterof 2017 are based exclusively on TSR.  The grant date fair value is calculated using the applicable Performance Measures and the closing price of the Company’s common stock at the grant date.

	Number		Weighted Average
	of Units (1)		Fair Value
	(in thousands)		(per share)
Unvested units at December 31, 2016		719	$	11.46
Granted		1,197		10.47
Vested		–		–
Forfeited		–		–
Unvested units at March 31, 2017		1,916	$	10.84

(1) These amounts reflect the number of performance units granted in thousands.  The actual payout of shares may range from a minimum of zero shares to a maximum of two shares contingent upon the actual performance against the Performance Measures. 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.

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Liability-Classified Performance Units

Prior to 2013, certain employees were provided performance units vesting equally over three years, payable in cash.  The payout of these units was based on certain metrics, such as total shareholder return and reserve replacement efficiency, compared to a predetermined group of peer companies and Company goals.  At the end of each performance period, the value of the vested performance units, if any, would bepaid in cash.  In the first quarter of 2016, the Companycompleted the final payout under these performance unit agreements.

(13) 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 Services segment generates revenue through the marketing of both Company and third-party produced natural gas and liquids volumes and through gathering fees associated with the transportation of natural gas to market.

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 2016 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.

	Exploration and Production			Midstream Services			Other			Total
	(in millions)
Three months ended March 31, 2017:
Revenues from external customers	$	566		$	280		$	–		$	846
Intersegment revenues		(3)			578			–			575
Depreciation, depletion and amortization expense		90			16			–			106
Operating income		225			41			–			266
Interest expense (1)		32			–			–			32
Gain on derivatives		116			–			–			116
Loss on early extinguishment of debt		–			–			(1)			(1)
Other income, net		2			–			–			2
Assets		4,413			1,268			1,515	(2)		7,196
Capital investments (3)		283			6			1			290
Three months ended March 31, 2016:
Revenues from external customers	$	343		$	236		$	–		$	579
Intersegment revenues		(7)			385			–			378
Depreciation, depletion and amortization expense		127			16			–			143
Impairment of natural gas and oil properties		1,034			–			–			1,034
Operating income (loss)		(1,160)	(4)		60	(5)		–			(1,100)
Interest expense (1)		14			–			–			14
Loss on derivatives		(13)			(1)			–			(14)
Other loss, net		(2)			(1)			–			(3)
Provision for income taxes (1)		1			–			–			1
Assets		5,538			1,220			1,760	(2)		8,518
Capital investments (3)		120			2			–			122

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

(2) Other assets represent corporate assets not allocated to segments and assets for non-reportable segments.  At March 31, 2017 and 2016, other assets includes approximately $1.4 billion and $1.6 billion in cash and cash equivalents, respectively.

(3) Capital investments includes decreases of $52 million and $78 million for the three months ended March 31, 2017 and 2016, respectively, relating to the change in accrued expenditures between periods.

(4) Operating income (loss) for the E&P segment includes $61 million related to restructuring charges for the three months ended March 31, 2016.

(5) Operating income (loss) for the Midstream segment includes $3 million related to restructuring charges for the three months ended March 31, 2016.

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Included in intersegment revenues of the Midstream Services segment are $524 million and $319 million for the three months ended March 31, 2017 and 2016, respectively, for marketing of the Company’s E&P sales. Corporate assets include cash and cash equivalents, furniture and fixtures and other costs. Corporate general and administrative costs, depreciation expense and taxes other than income are allocated to the segments.

(14)  INCOME TAXES

The Company’s effective tax rate was approximately 0% for the three months ended March 31, 2017 and 2016, primarily as a result of the recognition of a valuation allowance.  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.  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.

The Company maintained its net deferred tax asset position at March 31, 2017 primarily due to the write-downs of the carrying value of natural gas and oil propertiesin 2015 and 2016.  The Company recorded a $75  million decrease in our valuation allowance for the three months ended March 31, 2017 and  a$431 millionincrease in our valuation allowance for the three months ended March 31, 2016.  Management assesses the available positive and negative evidence to estimate whether sufficient future taxable income will be generated to permit the use of deferred tax assets.  In management’s view, the cumulative loss incurred over recent years outweighs any positive factors, such as the possibility of future growth.  The amount of the deferred tax asset considered realizable, however, could be adjusted if estimates of future taxable income are increased or if objective negative evidence in the form of cumulative losses is no longer present and additional weight is given to subjective evidence such as future expected growth.

(15)  NEW ACCOUNTING PRONOUNCEMENTS

New Accounting Standards Implemented

In March 2016, the FASB issued Accounting Standards Update No. 2016-09, Compensation – Stock Compensation (Topic 718) (“Update 2016-09”), to simplify accounting for share-based payment transactions including income tax consequences, classification of awards as either equity or liabilities, and the classification on the statement of cash flows.  For public entities, Update 2016-09 became effective for fiscal years beginning after December 15, 2016, including interim periods within those fiscal years, with early adoption permitted.  The Company adopted Update 2016-09 during the first quarter with an effective date of January 1, 2017.  The recognition of previously unrecognized windfall tax benefits resulted in a net cumulative-effect adjustment of $59 million, which increased net deferred tax assets and the relatedincome tax valuation allowance by the same amount as of the beginning of 2017.The amendments within Update 2016-09 related to the recognition of excess tax benefits and tax shortfalls in the income statement and presentation within the operating section of the statement of cash flows were adopted prospectively, with no adjustments made to prior periods.  The Company has elected to account for forfeitures as they occur.  The remaining provisions of this amendment did not have a material effect on itsunaudited condensed consolidated results of operations, financial position or cash flows.

New Accounting Standards Not Yet Implemented

In August 2016, the FASB issued Accounting Standards Update No. 2016-15, Statement of Cash Flows (Topic 230) (“Update 2016-15”), which seeks to reduce the existing diversity in practice in how certain cash receipts and cash payments are presented and classified in the statement of cash flows. For public entities, Update 2016-15 becomes effective for fiscal years beginning after December 15, 2017, including interim periods within those fiscal years, with early adoption permitted. The Company is currently evaluating the provisions of Update 2016-15 and assessing the impact, if any, it may have on its consolidated results of operations, financial position or cash flows.

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.  Through March 2017, the Company made progress on contract reviews, drafting its accounting policies and evaluating the new disclosure requirements.  The Company will continue assessing the effect that the updated standard may have on its consolidated financial statements and related disclosures,

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and anticipates that its assessment will be complete in 2018.  For public entities, Update 2016-02 becomes effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years, with early adoption permitted.

In May 2014, the FASB issued Accounting Standards Update No. 2014-09, Revenue from Contracts with Customers (Topic 606) (“Update 2014-09”), which seeks to provide clarity for recognizing revenue.  The new standard removes inconsistencies in existing standards, changes the way companies recognize revenue from contracts with customers and increases disclosure requirements.  The codification was amended through additional ASUs and, as amended, requires an entity to recognize revenue when it transfers promised goods or services to customers in an amount that reflects the consideration the entity expects to be entitled to in exchange for those goods or services.  The standard is required to be adopted using either the full retrospective approach, with all prior periods presented adjusted, or the modified retrospective approach, with a cumulative adjustment to retained earnings on the opening balance sheet.  The Company has not yet selected a transition method.  The Company has a team in place to analyze the impact of Update 2014-09, and the related ASU's, across all revenue streams to evaluate the impact of the new standard on revenue contracts.  This includes reviewing current accounting policies and practices to identify potential differences that would result from applying the requirements under the new standard.  Through March 2017, the Company made progress on contract reviews, drafting its accounting policies and evaluating the new disclosure requirements.  The Company expects to complete its evaluations of the impacts of the accounting and disclosure requirements on its business processes, controls and systems in the second half of 2017.  For public entities, the new standard is effective for annual reporting periods beginning after December 15, 2017, including interim periods within that reporting period.

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 2016 Annual Report and analyzes the changes in the results of operations between the three months ended March 31, 2017 and 2016.  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 2016 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 the “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 2016 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 unaudited condensed consolidated financial statements and the related notes included in this Quarterly Report.

OVERVIEW

Background

Southwestern Energy Company (including its subsidiaries, collectively, “we”, “our”, “us” or “Southwestern”) is an independent energy company engaged in natural gas, oil and NGLexploration, development and production, which we refer to as “E&P.”  We are also focused on creating and capturing additional value through our natural gas gathering and marketing businesses, which we refer to as “Midstream Services.”  We conduct most of our businesses through subsidiaries and we operate principally in two segments: E&P and Midstream Services.  Currently we operate only in the United States.

Exploration and Production.  Our primary business is the exploration for and production of natural gas, oil and NGL, with our current operations principally focused on the development of unconventional natural gas reservoirs located in Pennsylvania, West Virginia and Arkansas.  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, we refer to our properties located in Pennsylvania and West Virginia as the “Appalachian Basin.”  Our operations in Arkansas are primarily focused on an unconventional natural gas reservoir known as the Fayetteville Shale.  We have smaller holdings in Colorado and Louisiana, along with other areas in which we are testing potential new resources.  We also have drilling rigs located in Pennsylvania, West Virginia and Arkansas, as well as in other operating areas, and provide oilfield products and services, principally serving our E&P operations.

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Midstream Services.Through our affiliated midstream subsidiaries, we engage in natural gas gathering activities in Arkansas and Louisiana. These activities primarily support our E&P operations and generate revenue from fees associated with the gathering of natural gas. Our marketing activities capture opportunities that arise through the marketing and transportation of natural gas, oil and NGLs produced in our E&P operations.

We are focused on providing long-term growth in the net asset value per share of our business.  Historically, the vast majority of our operating income and cash flow has been derived from the production associated with our E&P business.  However, beginning in 2015 and continuing into 2017, depressed commodity prices significantly decreased our pace of activity and cash flow from our E&P operations.  The price we expect to receive for our production is a critical factor in the capital investments we make to develop our properties.  The current commodity price environment has resulted in the impairment of a significant portion of our natural gas and oil properties over recent reporting periods.  Commodity prices fluctuate due to a variety of factors we cannot control or predict. These factors, which include 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, impact supply and demand, which in turn determines the sales prices for our production. In addition to the factors identified above, the prices we realize for our production are affected by our hedging activities as well as locational differences in market prices, including basis differentials. Our 2016 results also reflect reduced costs of third-party services we were able to negotiate during the downturn in the industry.  As industry activity increases, demand for these services also increases, and these service providers are likely to seek higher prices than we were able to obtain in 2016.

With the successful implementation of our debt reduction strategy in 2016, along with improving forward pricing, we began increasing our activity in the third quarter of 2016, continuing into the first quarter of 2017.

Three Months Ended March 31, 2017 Compared with Three Months Ended March 31, 2016

We reported net income attributable to common stock of $281 million for the three months ended March 31, 2017, or $0.57 per diluted share, compared to a net loss attributable to common stock of $1.2billion, or ($3.03) per diluted share, for the same period in 2016.  

Our natural gas and liquids production decreased to 204 Bcfe for the three months ended March 31, 2017, a decrease of 14% from 237 Bcfe for the same period in 2016.  The 33 Bcfe decrease was due to a 22 Bcfe decrease in net production from our Fayetteville Shale and other properties, a 7 Bcf decrease in net production from our Northeast Appalachia properties and a 4 Bcfe decrease in net production from our Southwest Appalachia properties, compared to the same period in 2016.  The average price realized for our gas production, including the effects of derivatives, increased 74% to $2.57 per Mcf for the three months ended March 31, 2017, compared to $1.48 per Mcf for the same period in 2016.  The average price realized for our oil production increased 135% to $43.74 per barrel for the three months ended March 31, 2017, compared to $18.65 per barrel for the same period in 2016.  The average price realized for our NGL production, including the effects of derivatives, increased 167% to $13.28 per barrel for the three months ended March 31, 2017, compared to $4.98 per barrel for the same period in 2016.  We did not use derivatives to financially protect our 2017 or 2016 oil production.

Our E&P segment operating income was $225 million for the three months ended March 31, 2017, an increase from an operating loss of $1.2 billion for the same period in 2016.  This increase was primarily due to the impairment of natural gas and oil properties of $1,034 million for the three months ended March 31, 2016.  Excluding the 2016 impairment, our E&P segment operating income increased $351 million for the three months ended March 31, 2017, compared to the same period in 2016, primarily due to a $274 million increase in revenue related to increased realized natural gas, oil and NGL prices (excluding derivatives) and a $124 million decrease in operating costs and expenses, partially offset by a $47 million decrease in revenue resulting from a 33 Bcfe decrease in production.

Operating income for our Midstream Services segment was $41 million for the three months ended March 31, 2017, a decrease from $60 million for the same period in 2016, primarily due to a $22 million decrease in gas gathering revenues and a $3 million decrease in our marketing margin, partially offset by a $6 million decrease in operating costs and expenses.

Capital investments were $290 million for the three months ended March 31, 2017 (including $28 million in capitalized interest and $25 million in capitalized expenses), of which $283 million was invested in our E&P segment, compared to $122 million for the same period of 2016, of which $120 million was invested in our E&P segment.

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RESULTS OF OPERATIONS

The following discussion of our results of operations for our segments is presented before intersegment eliminations. We evaluate our segments as if they were stand-alone operations and accordingly discuss their results prior to any intersegment eliminations. Interest expense and income tax expense are discussed on a consolidated basis.

Exploration and Production
	For the three months
	ended March 31,
	2017		2016
Revenues (in millions)	$	563	$	336
Impairment of natural gas and oil properties (in millions)	$	–	$	1,034
Operating costs and expenses (in millions) (1)	$	338	$	462
Operating income (loss) (in millions)	$	225	$	(1,160)
Gain (loss) on derivatives, settled (in millions) (2)	$	(30)	$	8
Gas production (Bcf)		183		213
Oil production (MBbls)		519		607
NGL production (MBbls)		3,008		3,376
Total production (Bcfe)		204		237
Average realized gas price per Mcf, including derivatives (3)	$	2.57	$	1.48
Average realized gas price per Mcf, excluding derivatives	$	2.73	$	1.44
Average realized oil price per Bbl	$	43.74	$	18.65
Average realized NGL price per Bbl	$	13.28	$	4.98
Average unit costs per Mcfe:
Lease operating expenses	$	0.89	$	0.88
General & administrative expenses (4)	$	0.21	$	0.19
Taxes, other than income taxes (5)	$	0.12	$	0.08
Full cost pool amortization	$	0.40	$	0.49

(1)     Includes $61 million of restructuring charges for the three months ended March 31, 2016.

(2)     Represents the gain (loss) on settled commodity derivatives.

(3)     Includes the gain (loss) on settled commodity derivatives.

(4)     Excludes $58 million of restructuring charges for the three months ended March 31, 2016.

(5)     Excludes $3 million of restructuring charges for the three months ended March 31, 2016.

Revenues

Revenues for our E&P segment were $563 million, an increase of 68%, for the three months ended March 31, 2017, compared to $336 million for the same period in 2016.  Revenues increased by $274 million as a result of increased natural gas, oil and NGL pricing, excluding the effects of derivatives, partially offset by a decrease of $47 million as a result of decreasedproduction volumes.Natural gas, oil and NGL prices are difficult to predict and are subject to wide price fluctuations.  Excluding basis swaps, as of March 31, 2017 we had protected429 Bcf of our remaining 2017 natural gas production to limit our exposure to price fluctuations. We refer you to Note 6 to the unaudited condensed consolidated financial statements included in this Quarterly Report and to the discussion of “Commodity Prices” provided below for additional information.

Production

For the three months ended March 31, 2017, our natural gas and liquids production decreased 14% to 204 Bcfe, from 237 Bcfe for the same period in 2016, and was produced entirely by our properties in the United States.  The 33 Bcfe decrease was due to a 22 Bcfe decrease in net production from our Fayetteville Shale and other properties, a 7 Bcf decrease in net production from our Northeast Appalachia properties and a 4 Bcfe decrease in net production from our Southwest Appalachia properties, compared to the same period in 2016.  Net production from our Northeast Appalachia, Southwest Appalachia and Fayetteville Shale properties was 87 Bcf, 36 Bcfe and 81 Bcf, respectively, for the three months ended March 31, 2017, compared to 94 Bcf, 40 Bcfe, and 103 Bcf, respectively, for the same period in 2016. 

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Commodity Prices

The average price realized for our natural gas production, including the effects of derivatives, increased to $2.57 per Mcf for the three months ended March 31, 2017, compared to $1.48 per Mcf for the same period in 2016.  The increase was primarily due to the $1.29 per Mcf increase in the average realized natural gas price, excluding the effects of derivatives, partially offset by a loss from our derivative program during the three months ended March 31, 2017, compared to a gain for the same period in 2016.  The average price realized for our natural gas production, excluding the effects of derivatives, increased 90% to $2.73 per Mcf for the three months ended March 31, 2017, compared to the same period in 2016.  Our derivatives decreased the average realized natural gas price by $0.16 per Mcf for the three months ended March 31, 2017, compared to an increase of $0.04 per Mcf for the same period in 2016.

Our E&P segment receives a sales price for our natural gas at a discount to average monthly NYMEX settlement prices due to heating content of the gas, locational basis differentials, transportation charges 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 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 Risks"and Note 6 to the unaudited condensed consolidated financial statements included in this Quarterly Report for additional discussion about our derivatives and risk management activities.

Excluding the impact of derivatives, the average price received for our natural gas production for the three months ended March 31, 2017 of $2.73 per Mcf was approximately $0.59 per Mcf lower than the average monthly NYMEX settlement price, primarily due to locational basis differentials and transportation charges.  We protected approximately 57% of our natural gas production for the three months ended March 31, 2017 from the impact of widening basis differentials through our sales arrangementsand financial derivatives.  As of March 31, 2017, we have protected basis on approximately 296 Bcf and 101 Bcf of our 2017 and 2018expected natural gas production, respectively, through physical sales arrangements and financial derivatives at a basis differential to NYMEX natural gas prices of approximately ($0.73) per Mcf and ($0.50) per Mcf for the remainder of 2017 and 2018, respectively.  We refer you to Note 6 to the unaudited condensed consolidated financial statements included in this Quarterly Report for additional details about our derivative instruments.

We realized an average sales price of $43.74 per barrel for our oil production for the three months ended March 31, 2017, an increase of approximately 135% from $18.65 per barrel for the same period in 2016.  Oil accounted for 2% of our total production for the three months ended March 31, 2017 and 2016.  We did not use derivatives to financially protect our 2017 or 2016 oil production.

We realized an average sales price of $13.28 per barrel for our NGL production for the three months ended March 31, 2017, an increase of approximately 167% from $4.98 per barrel for the same period in 2016.  NGLs accounted for 9% of our total production for the three months ended March 31, 2017 and 2016.  A small portion of our 2017 NGL production was financially protected through the use of derivatives.  The impact was immaterial.

Operating Income

Our E&P segmentoperating income was $225 million for the three months ended March 31, 2017, an increase from an operating loss of $1.2 billion for the same period in 2016.  The E&P segment recorded a $1.0 billion impairment of natural gas and oil properties for the three months ended March 31, 2016.  Excluding the 2016 impairment, our E&P segment operating income increased $351 million for the three months ended March 31, 2017, compared to the same period in 2016, primarily due to a $274 million increase in revenue related to increased realized natural gas, oil and NGL prices (excluding derivatives) and a $124 million decrease in operating costs and expenses, partially offset by a $47 million decrease in revenue resulting from a 33 Bcfe decrease in production.  For the three months ended March 31, 2016, general and administrative expenses and taxes other than income taxes included $58 millionand $3 million, respectively, related to restructuring charges.

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Operating Costs and Expenses

Lease operating expenses per Mcfe for the E&P segment were $0.89 for the three months ended March 31, 2017, compared to $0.88 for the same period in 2016.  Lease operating expenses per Mcfe increased for the three months ended March 31, 2017, compared to the same period of 2016, primarily due tothe impact of increased prices for natural gas used as compressor fuel.  In total, lease operating expenses for the E&P segment were $182 million and $209 millionfor the three months ended March 31, 2017 and 2016, respectively.

General and administrative expenses for the E&P segment increased to $0.21 per Mcfe for the three months ended March 31, 2017, compared to $0.19 per Mcf for the same period in 2016, excluding the restructuring charges associated primarily with our workforce reduction in the first quarter of 2016, as a result of decreased production volumes.  In total, general and administrative expenses for the E&P segment were $43 million and $45 million for the three months ended March 31, 2017 and 2016, respectively, excluding the 2016 restructuring charges.  Including restructuring charges, general and administrative costs for three months ended March 31, 2016were $103 million for our E&P segment. 

Taxes other than income taxes per Mcfe were $0.12 for the three months ended March 31, 2017, compared to $0.08 per Mcfe for the same period in 2016, excluding $3 million relating to restructuring charges in the first quarter of 2016.  Taxes other than income taxes per Mcfe 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.

Our full cost pool amortization rate averaged $0.40 per Mcfe and $0.49 per Mcfe for the three months ended March 31, 2017 and 2016, respectively.  The decrease in the average amortization rate resulted primarily from our full cost ceiling impairments between the respective periods.  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.  In total, depreciation, depletion and amortization expense for the E&P segment was $90 million and $127 million for the three months ended March 31, 2017 and 2016, respectively.

Unevaluated costs excluded from amortization were $2.1 billion at March 31, 2017 and December 31, 2016.  The unevaluated costs excluded from amortization remained flat as the evaluation of previously unevaluated properties totaling $127 million in the first quarter of 2017 was partially offset by the impact of $96 million of unevaluated capital invested during the same period.

Midstream Services
	For the three months ended
	March 31,
	2017		2016
	($ in millions, except volumes)
Marketing revenues	$	777	$	518
Gas gathering revenues	$	81	$	103
Marketing purchases	$	765	$	503
Operating costs and expenses (1)	$	52	$	58
Operating income	$	41	$	60
Volumes marketed (Bcfe)		245		279
Volumes gathered (Bcf)		129		165

(1) Includes $3 million of restructuring charges for the three months ended March 31, 2016.

Revenues

Revenues from our marketing activities increased 50% to $777 million for the three months ended March 31, 2017, compared to the same period in 2016.  For the three months ended March 31, 2017, the volumes marketed decreased 12% and the price received for volumes marketed increased 71%, compared to the same period in 2016.  Increases and decreases in marketing revenues due to changes in commodity prices are largely offset by corresponding changes in marketing purchase expenses.  Of the total natural gas volumes marketed, production from our affiliated E&P operated wells accounted for 95% and 96% of the natural gas marketed volumes for the three months ended March 31, 2017 and 2016, respectively.  Our Midstream Services segment marketed approximately 67% of our combined oil and NGL production for the three months ended March 31, 2017 and 2016.

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Revenues from our gathering activities decreased 21% to $81 million for the three months ended March 31, 2017, compared to the same period in 2016.  The decrease in the gathering revenues for the three months ended March 31, 2017 was primarily due to the decreased volumes in the Fayetteville Shale. 

Operating Income

Operating income from our Midstream segment decreased to $41 million for the three months ended March 31, 2017, compared to $60 million for the same period in 2016, primarily due to a $22 million decrease in gas gathering revenues and a $3 million decrease in marketing margin, partially offset by a $6 million decrease in operating costs and expenses. 

The margin generated from marketing activities was $12 million and $15 million for the three months ended March 31, 2017 and 2016, respectively.  Margins are driven primarily by volumes marketed and may fluctuate depending on the prices paid for commodities and the ultimate disposition of those commodities.  We enter into derivative contracts from time to time with respect to our natural gas marketing activities to provide margin protection. For more information about our derivatives and risk management activities, we refer you to Item 3, "Quantitative and Qualitative Disclosures About Market Risks" included in this Quarterly Report for additional information.

Restructuring Charges

In January 2016, we announced a 40% workforce reduction, which was substantially concluded by the end of March 2016. In April 2016, we also partially restructured executive management.  Affected employees were offered a severance package that included a one-time cash payment depending on length of service and, if applicable, accelerated vesting of outstanding stock-based equity awards.  As a result of the workforce reduction and executive management restructuring, we recognized restructuring charges of $64 million for the three months ended March 31, 2016.

Interest Expense

Interest expense, net of capitalization, was $32 million for the three months ended March 31, 2017, compared to $14 million interest expense, net of capitalization, for the same period in 2016.  Gross interest expense increased to $60 million for the three months ended March 31, 2017, compared to $55 million for the same period in 2016, primarily due to an increase in our cost of debt.  We capitalized interest of $28 million and $41 million for the three months ended March 31, 2017 and 2016, respectively.  The decrease in capitalized interest for the three months ended March 31, 2017, compared to the same period in 2016, was primarily due to the evaluation of a portion of our Southwest Appalachia assets acquired in December 2014.

Gain (Loss) on Derivatives

Our current derivatives are not designated for hedge accounting treatment.  Changes in the fair value of derivatives that are not designated for hedge accounting are recorded in gain (loss) on derivatives. We recorded a $116 million net gain on our derivatives for the three months ended March 31, 2017, consisting of a$146million gain on unsettled derivatives, partially offset by a $30million loss on settled derivatives. For the three months ended March 31, 2016, we recorded a $14 million net loss on our derivatives, consisting of a $21 million loss on unsettled derivatives, partially offset by a $7 million gain on settled derivatives. We refer you to Note 6 to the unaudited condensed consolidated financial statements included in this Quarterly Report for additional details about our gain (loss) on derivatives.  In general and without consideration of volatility or duration, as natural gas prices increase from March 31, 2017 levels, we will recognize losses in future periods and, likewise, as natural gas prices decline from March 31, 2017 levels, we will recognize gains in future periods on our derivative contracts not designated for hedge accounting treatment prior to settlement.

Income Taxes

Our effective tax rate was approximately 0% for the three months ended March 31, 2017 and 2016.  We recorded an immaterial income tax benefit for the three months ended March 31, 2017, and a $1million income tax expense for the three months ended March 31, 2016.  Ourlow effective tax rate is 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.

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New Accounting Standards Implemented in this Report

Refer to Note 15 to the unaudited condensed 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 15 to the unaudited condensed consolidated financial statements of this Quarterly Report for a discussion of new accounting standards which have not yet been implemented.

LIQUIDITY AND CAPITAL RESOURCES

We depend primarily on funds generated from our operations, our cash and cash equivalents balance, our $809 million revolving credit facilities and capital markets as our primary sources of liquidity.

During 2016, we took significant steps in managing our maturities and liquidity.  In June 2016, we refinanced approximately 97% of our principal credit facility, which was due in December 2018, including extending the maturity by two years until December 2020, granting liens on certain assets and modifying borrowing rates and covenants. We simultaneously modified borrowing rates and covenants under our $750 million unsecured term loan facility and extended its maturity by two years also until December 2020 should its principal balance be reduced by 50% by June 2018.  The maturity dates of our principle credit facility and our unsecured term loan facility will accelerate to October 2019 if, by that date, we have not amended, redeemed or refinanced at least $765 million of our senior notes due in January 2020.  In July 2016, we completed a public offering of 98,900,000 shares of our common stock, with net proceeds totaling approximately $1,247 million after underwriting discounts and offering expenses.  Of the funds received from the common stock offering, $375 million was used to pay down a portion of our $750 million unsecured term loan and $750 million was used to settle certain tender offers by purchasing an aggregate principal amount of approximately $700 million of our outstanding senior notes due in the first quarter of 2018.  The repayment of $375 million on the $750 million unsecured term loan had the effect of extending its maturity date to December 2020 subject to the conditions described above.  In September 2016, we completed the sale of 55,000 net acres in West Virginia for $422 million, subject to customary post-closing adjustments, and used $48 million of the proceeds to further decrease the balance of this term loan. We earmarked the remaining funds from the equity issuance and the sale of the West Virginia acreage for capital activity.In March 2017, we repurchased $25 million of our 7.50% Senior Notes due February 2018.

During the first half of 2016, we suspended drilling and completion activity in the Appalachian Basin and Fayetteville Shale as a result of the commodity price environment.  After the successful implementation of our debt reduction strategy along with our equity offering, we began increasing our activity in the third quarter of 2016, which has continued throughout the first quarter of 2017.  Although we have the financial flexibility to draw on the funds available under our cash balance and revolving credit facility as necessary, we continue to be committed to our capital discipline strategy of investing within our cash flow from operations, supplemented by the remaining funds from the July 2016 equity issuance and asset sale in West Virginia.  We refer you to Note 9 of the unaudited condensed consolidated financial statements included in this Quarterly Report and the section below under “Financing Requirements” for additional discussion of our credit facilities.

The credit status of the financial institutions participating in our revolving credit facilities could adversely impact our ability to borrow funds under the revolving credit facilities.  Although we believe all of the lenders under the facilities have the ability to provide funds, we cannot predict whether each will be able to meet their obligation to us.  We refer you to the section below under “Financing Requirements” for additional discussion of our compliance with the covenants of our term loans and revolving credit facilities.

Net cash provided by operating activities increased 239% to $312 million for the three months ended March 31, 2017, from $92 million for the same period in 2016, primarily due to an increase in net income adjusted for non-cash expenses and changes in working capital accounts.  During the three months ended March 31, 2017, requirements for our capital investments were funded primarily from our cash generated by operating activities and cash and cash equivalents.  Net cash generated from operating activities exceeded our cash requirements for capital investmentsfor the three months ended March 31, 2017, compared to net cash from operating activities being 75% of our cash requirements for capital investments for the same period in 2016, reflecting our commitment to our capital discipline strategy of investing within our cash flow from operations, supplemented by the 2016 equity issuance and asset sales, during the current commodity price environment.

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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.  See “Quantitative and Qualitative Disclosures about Market Risks” in Item 3and Note 6 to the unaudited condensed consolidated financial statements included in this Quarterly Report for further details.  Our commodity hedging activities are subject to the credit risk of our counterparties being financially unable to complete 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.

Additionally, our short-term cash flows are dependent on the timely collection of receivables from our customers and joint interest partners.  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 or rearrange some or all of our outstanding debt or preferred stock 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.

Capital Investments

Our capital investments were $290 million and $122 million for the three months ended March 31, 2017 and 2016, respectively.  Our E&P segment investments were $283 million and $120 million for the three months ended March 31, 2017 and 2016, respectively.  Our E&P segment capitalized internal costs of $32 million for the three months ended March 31, 2017 compared to $27 million for the same period in 2016.  These internal costs were directly related to acquisition, exploration and development activities and are included as part of the cost of natural gas and oil properties.

Although our 2017 capital investment program is expected to be funded through cash flow from operations along with our cash and cash equivalents, we have the financial flexibility to utilize borrowings under our revolving credit facilities.

Financing Requirements

Our total debt outstanding was $4.6 billion as ofMarch 31, 2017 and December 31, 2016.   Our total debt, net of cash and cash equivalents of $1.4  billion, was $3.2 billion at March 31, 2017 and December 31, 2016.  Our actions to reduce and extend our total debt outstanding are further discussed below.

At April 25, 2017, we had a long-term issuer credit rating of Ba3 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 downgrades in our public debt ratings by Moody’s or S&P could increase our cost of funds and decrease our liquidity under our revolving credit facilities.

At March 31, 2017, our capital structure consisted of 78% debt (excluding $1.4 billion in cash and cash equivalents) and 22% equity, compared to 84% debt(excluding $1.4billion in cash and cash equivalents) and 16% equity at December 31, 2016.

In July 2016, we consummated an underwritten offering of 98,900,000 shares of our common stock pursuant to an effective registration statement filed with the Securities and Exchange Commission, with net proceeds of the offering totaling approximately $1,247 million after underwriting discounts and offering expenses.  A portion of the proceeds from the offering were used to repay $375 million of the $750 million term loan entered into in November 2015 and to settle certain tender offers by purchasing an aggregate principal amount of approximately $700 million of our outstanding senior notes due in the first quarter of 2018.  The remaining net proceeds of the offering will be used for general corporate purposes, including the completion of wells already drilled or the funding of other capital projects.

In June 2016, we reduced our existing $2.0 billion unsecured revolving credit facility to $66 million and entered into a new credit agreement for $1,934 million, consisting of a $1,191 million secured term loan and a new unsecured $743

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million revolving credit facility, which matures in December 2020.The maturity date will accelerate to October 2019 if, by that date, we have not amended, redeemed or refinanced at least $765 million of oursenior notes due in January 2020.  The $1,191 million secured term loan is fully drawn, with approximately $285 million of this balance used to pay down the existing revolving credit facility balance in its entirety.  As of March 31, 2017, there were no borrowings under either revolving credit facility; however, there was $327 million in letters of credit outstanding against the 2016 revolving credit facility. 

Loans under the 2016 credit agreement 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 London Interbank Offer Rate (“LIBOR”) plus applicable margins ranging from 1.750% to 2.500%.  Alternate base rate loans bear interest at the alternate base rate plus the applicable margin ranging from 0.750% to 1.500%.  The interest rate on the term loan facility is determined based upon our public debt ratings and was 250 basis points over LIBOR as of March 31, 2017.

Our 2016 credit agreement contains financial covenants that impose certain restrictions on us.  Under our revolving credit and term loan facilities, we must keep a minimum interest coverage of 1.00x in 2017, increasing by 0.25x increments per year to 1.50x in 2019 and 2020.  We are also subject to a minimum liquidity requirement of $300 million, which could be increased up to $500 million upon certain conditions, as well as an anti-hoarding provision, requiring unrestricted cash in excess of $100 million to pay down any amounts borrowed under the new revolving credit facility.  The financial covenant with respect to minimum interest coverage consists of EBITDAX divided by consolidated interest expense.  EBITDAX, as defined in our 2016 credit agreement, excludes the effects of interest expense, income taxes, depreciation, depletion and amortization, 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.  Collateral for the new secured term loan is principally our E&P properties in the Fayetteville Shale area, the equity of its subsidiaries and cash and marketable securities on hand.  This collateral also may support all or a part of revolving credit extensions depending on restrictions in our senior notes indentures, and requires a minimum collateral coverage ratio of 1.50x.

The existing unsecured 2013 revolving credit facility includes a financial covenant under which we may not issue total debt in excess of 60% of our total adjusted book capital, as defined in that agreement.  This financial covenant with respect to capitalization percentages excludes the effects of any full cost ceiling impairments, certain hedging activities and our pension and other postretirement liabilities.  We are in compliance with this covenant. As of March 31, 2017, the maximum amount available under this credit facility was $66 million,  with no amounts outstanding.

In November 2015, we entered into a $750 million unsecured three-year term loan credit agreement with various lenders that was used to repay borrowings under the existing revolving credit facility.  The interest rate on the term loan facility is determined based upon our public debt ratings from Moody’s and S&P and was 250 basispoints over LIBOR as of March 31, 2017.  The term loan facility requires prepayment under certain circumstances from the net cash proceeds of sales of equity or certain assets and borrowings outside the ordinary course of business.  In June 2016, the 2015 term loan agreement was amended to extend the maturity date, provided at least 50% would be paid down by June 2017. After our July 2016 equity offering, we repaid $375 million of the $750 million term loan, which had the effect of extending its maturity from November 2018 to December 2020.The maturity date will accelerate to October 2019 if, by that date, we have not amended, redeemed or refinanced at least $765 million of oursenior notes due January 2020.  In September 2016, we repaid an additional $48 million of the term loan with proceeds from the sale of our West Virginia acreage.

As of March 31, 2017, we were in compliance with all of the covenants of the term loans and revolving credit facilities.  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.

Our mandatory convertible preferred stock, issued in January 2015, entitles the holders to a proportional fractional interest in the rights and preferences of the convertible preferred stock, including conversion, dividend, liquidation and voting rights.  Dividends are to be paid at a rate of 6.25% per annum on the liquidation preference of $1,000 per share and can be paid in cash, common stock or a combination of both.  Since inception, and as of April 25, 2017, we have made four of the quarterly dividend payments in cash and five of the quarterly dividend payments in stock.  Unless converted earlier at the option of the holders, on or around January 15, 2018 each share of convertible preferred stock will automatically convert into between 37.0028 and 43.4782 shares of our common stock (correspondingly, each depositary share will convert into between 1.85014 and 2.17391 shares of our common stock), subject to customary anti-dilution

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adjustments, depending on the volume-weighted average price of our common stock over a 20 trading-day period immediately prior to that date.

Our mandatory convertible preferred stock has 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 as such, is considered a participating security.  As such, it is 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, participating securities are allocated earnings based on actual dividend distributions received plus a proportionate share of undistributed net income attributable to common shareholders, if any, after recognizing distributed earnings.

In January 2015, we completed a public offering of $350 million aggregate principal amount of our 3.30% senior notes due 2018 (the “2018 Notes”), $850 million aggregate principal amount of our 4.05% senior notes due 2020 (the “2020 Notes”) and $1.0 billion aggregate principal amount of our 4.95% senior notes due 2025 (the “2025 Notes” and together with the 2018 and 2020 Notes, the “Notes”), with net proceeds from the offering totaling approximately $2.2 billion after underwriting discounts and offering expenses.  The Notes were sold to the public at a price of 99.949% of their face value for the 2018 Notes, 99.897% of their face value for the 2020 Notes and 99.782% of their face value for the 2025 Notes.  The interest rates on the Notes are determined based on our public bond ratings from Moody’s and S&P.  Downgrades on the Notes from either rating agency increase our interest costs by 25 basis points per downgrade level on the following semi-annual bond interest payment.  Based on the February and June 2016 downgrades from Moody’s and S&P, our interest rates on these Notes increased by 175 basis points in July 2016.  In July2016,we used a portion of the proceeds from the July 2016 equity offering to settle certain tender offersby purchasing an aggregate principal amount of approximately $700 million of our outstanding senior notes due in the first quarter of 2018.

Our derivative contracts allow us to ensure a certain level of cash flow to fund our operations.  Excluding basis swaps, at April 25, 2017, we had commodity price derivatives in place on 429 Bcf of our remaining targeted 2017 natural gas production, and 336 Bcf and 99 Bcf on our targeted 2018 and 2019 natural gas production, respectively.  We also had commodity derivatives in place on 138  MBbls of our remaining targeted 2017 ethane production and 183 MBbls of our targeted ethane production for our 2018.

Off-Balance Sheet Arrangements

We may enter into off-balance sheet arrangements and transactions that can give rise to material off-balance sheet obligations.  As of March 31, 2017, our material off-balance sheet arrangements and transactions include operating lease arrangementsand $327 million in letters of credit outstanding against our 2016 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 2016 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 2016 Annual Report on Form 10-K.

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Contingent Liabilities and Commitments

As of March 31, 2017, our contractual obligations for demand and similar charges under firm transport and gathering agreements to guarantee access capacity on natural gas and liquids pipelines and gathering systems totaled approximately $8.7 billion, $3.7 billion 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 $821 million.  As of March 31, 2017, future payments under non-cancelable firm transportation and gathering agreements are as follows:

	Payments Due by Period
	Total		Less than 1 Year		1 to 3 Years		3 to 5 Years		5 to 8 Years		More than 8 Years
		(in millions)
Infrastructure Currently in Service	$	5,011	$	592	$	1,139	$	791	$	832	$	1,657
Pending Regulatory Approval and/or Construction (1)		3,661		35		371		474		730		2,051
Total Transportation Charges	$	8,672	$	627	$	1,510	$	1,265	$	1,562	$	3,708

(1)     Based on the estimated in-service dates as of March 31, 2017.

Substantially all of our employees are covered by defined benefit and postretirement benefit plans. For the three months endedMarch 31, 2017, we have contributed $5 million to the pension and postretirement benefit plans.  We expect to contribute an additional $9 million to our pension and postretirement benefit plans during the remainder of 2017. As ofMarch 31, 2017 and December 31, 2016, we recognized liabilitiesof $47 million and $49 million, respectively, as a result of the underfunded status of our pension and other postretirement benefit plans.  See Note 11 to the unaudited condensed 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 and pollution, contamination or nuisance.  We accrue for such items when a liability is both probable and the amount can be reasonably estimated.  Management believes thatcurrent 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. For further information, we refer you to “Litigation”and “Environmental Risk”in Note 10 to the unaudited condensed consolidated financial statements included in Item 1 of Part I of this Quarterly Report.

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 or results of operations.  

Working Capital

We maintain access to funds that may be needed to meet capital requirements through our cash and cash equivalents and our revolving credit facilities, described in “Financing Requirements” above.  We had positive working capital of $668 million at March 31, 2017 and positive working capital of $808 million at December 31, 2016.  The positive working capital as of March 31, 2017 and December 31, 2016 was primarily due to $1.4 billion of cash and cash equivalents.

37

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, fixed price 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 and 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 financial instruments that are exposed to concentrations of credit risk consist 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 physical commodity purchasers and their dispersion across geographic areas.  No single purchaser accounted for greater than 10% of revenues for the three months ended March 31, 2017.  See “Commodities Risk” below for discussion of credit risk associated with commodities trading.

Interest Rate Risk

As of March 31, 2017, we had approximately $3.1 billion of outstanding senior notes with a weighted average interest rate of 5.67% and $1.5 billion of term loan facility debt with a variable interest rate of 3.45%.  We currently have an interest rate swap in effect to mitigate a portion of our exposure to volatility in interest rates.

	Expected Maturity Date
		2017			2018			2019			2020			2021			Thereafter			Total
Fixed Rate Payments (1)	$	41		$	250		$	–		$	850		$	–		$	2,000		$	3,141
Weighted Average Interest Rate		7.21	%		7.09	%		–	%		5.80	%		–	%		5.40	%		5.67	%
Variable Rate Payments (1)		–			–			–			1,518	(2)		–			–			1,518
Weighted Average Interest Rate		–	%		–	%		–	%		3.45	%		–	%		–	%		3.45	%

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

(2)     The maturity date will accelerate to October 2019 if, by that date, we have not amended, redeemed or refinanced at least $765 million of our 2020 Senior Notes.

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).  For additional information on our derivatives and risk management, see Note 6 in the unaudited condensed consolidated financial statements included in this Quarterly Report.

The primary market risks relating to our derivative contracts are the volatility in market prices and basis differentials for natural gas.  However, the market price risk is offset by the gain or loss recognized upon the related sale or purchase of the natural gas 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.

38

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 March 31, 2017 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 March 31, 2017 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 10 to the unaudited condensed 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 2016 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.

Amended and Restated Bylaws

On April 25, 2017, the Company’s Board of Directors amended the Company’s amended and restated Bylaws, effective as of such date.

The amendments to the Bylaws:

· eliminate the current requirement that the number of directors be six to ten and that any change in size of more than 30% receive stockholder approval;

39

· eliminate the concept of director emeritus going forward;

· revise the provision on compensation for directors to reflect current procedures, including elimination of director emeritus going forward;

· add a provision stating that amendments to the Bylaws for director and officer indemnity may not reduce protections in effect at the time of the underlying alleged act or omission, reflecting a change in the Delaware general Corporation Law;

· eliminate the requirement that proposed amendments to the Bylaws be specified in the notice of meetings of the Board of Directors, while retaining that requirement for meetings of stockholders; and

· make other technical and conforming changes.

The foregoing description is a summary and does not purport to be a complete description of the amendments to the Company’s Bylaws and is qualified in its entirety by reference to the text of the Company’s Bylaws, as amended through April 25, 2017, a conformed copy of which are attached to this Quarterly Report as Exhibit 3.1 and are incorporated herein by reference.

ITEM 6. EXHIBITS.

(3.1)*	Amended and Restated Bylaws of Southwestern Energy Company, as amended on April 25, 2017
(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:	April 27, 2017	/s/ R. CRAIG OWEN
		R. Craig Owen
		Senior Vice President
		and Chief Financial Officer

40

EX-31

Exhibit 31.1

CERTIFICATION

I, William J. Way, certify that:
	1. I have reviewed this Quarterly Report on Form 10-Q of Southwestern Energy Company;
	2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
	3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
	4. The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
		(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
		(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
		(c) Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
		(d) Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and
	5. The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):
		(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and
		(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.
Date:	April 27, 2017		/s/ WILLIAM J. WAY
				William J. Way
				Director, President and Chief Executive Officer

EX-31

Exhibit 31.2

CERTIFICATION

I, R. Craig Owen, certify that:
	1. I have reviewed this Quarterly Report on Form 10-Q of Southwestern Energy Company;
	2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
	3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
	4. The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
		(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
		(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
		(c) Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
		(d) Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and
	5. The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):
		(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and
		(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.
Date:	April 27, 2017		/s/ R. CRAIG OWEN
				R. Craig Owen
				Senior Vice President and Chief Financial Officer

EX-32

Exhibit 32.1

CERTIFICATION
Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
(Subsections (a) and (b) of Section 1350, Chapter 63 of Title 18, United States Code)

In connection with the Quarterly Report of Southwestern Energy Company, a Delaware corporation (the “Corporation”) on Form 10-Q for the quarter ended March 31, 2017 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, William J. Way, Director, President and Chief Executive Officer of the Corporation, certify to my knowledge, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (18 U.S.C. Section 1350), that:

1. The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and    

2. The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Corporation.

Dated:      April 27, 2017	/s/ WILLIAM J. WAY
	William J. Way
	Director, President and Chief Executive Officer

EX-32

Exhibit 32.2

CERTIFICATION
Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
(Subsections (a) and (b) of Section 1350, Chapter 63 of Title 18, United States Code)

In connection with the Quarterly Report of Southwestern Energy Company, a Delaware corporation (the “Corporation”) on Form 10-Q for the quarter ended March 31, 2017 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, R. Craig Owen, Senior Vice President and Chief Financial Officer of the Corporation, certify to my knowledge, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (18 U.S.C. Section 1350), that:

1. The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and    

2. The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Corporation.

Dated:      April 27, 2017	/s/ R. CRAIG OWEN
	R. Craig Owen
	Senior Vice President and Chief Financial Officer

EX-95

EXHIBIT 95.1

Mine Safety Disclosure

The following disclosure is provided pursuant to Section 1503(a) of the Dodd-Frank Wall Street Reform and Consumer Protection Act, which requires certain disclosures by companies required to file periodic reports under the Securities Exchange Act of 1934, as amended, that operate mines regulated under the Federal Mine Safety and Health Act of 1977.  

The table that follows reflects citations, orders, violations and proposed assessments issued by the Mine Safety and Health Administration (the “MSHA”) to SWN Production (Arkansas), LLC, an indirect wholly owned subsidiary of Southwestern Energy Company.  The disclosure is with respect to the three months ended March 31, 2017.  Due to timing and other factors, the data may not agree with the mine data retrieval system maintained by the MSHA at www.MSHA.gov.

Southwestern Energy Company
Mine Safety Disclosure
Three Months Ended March 31, 2017
(Unaudited)

Section 104(d) Citations and Orders

Received Notice of Pattern of Violations Under Section 104(e)

Section 104 S&S Citations

Section 104(b) Orders

Section 110(b)(2) Violations

Section 107(a) Orders

Total Dollar Value of Proposed MSHA Assessments(2)

Total Number of Mining Related  Fatalities

Received Notice of Potential to Have Pattern Under Section 104(e)

Legal Actions Pending as of the Last Day of  Period

Operation(1)

Legal Actions Initiated During Period

Legal Actions Resolved During Period

SWN Production (Arkansas), LLC

0

0

0

0

0

$0

0

0

0

0

Total

$0

No

No

(1)

The definition of mine under section 3 of the Mine Act includes the mine, as well as other items used in, or to be used in, or resulting from, the work of extracting minerals, such as land, structures, facilities, equipment, machines, tools, and preparation facilities. Unless otherwise indicated, any of these other items associated with a single mine have been aggregated in the totals for that mine.

(2)

The whole-dollar amounts included are the total dollar value of proposed or outstanding assessments received from MSHA on or before March 31, 2017 regardless of whether the assessment has been challenged or appealed, for alleged violations occurring during the three month period ended March 31, 2017. Citations and orders can be contested and appealed, and as part of that process, are sometimes reduced in severity and amount, and are sometimes dismissed. The number of citations, orders, and proposed assessments vary by inspector and also vary depending on the size and type of the operation.

XML

Document and Entity Information - shares	3 Months Ended
	Mar. 31, 2017	Apr. 25, 2017
Document And Entity Information [Abstract]
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Mar. 31, 2017
Document Fiscal Year Focus	2017
Document Fiscal Period Focus	Q1
Entity Registrant Name	SOUTHWESTERN ENERGY CO
Entity Central Index Key	0000007332
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Entity Common Stock, Shares Outstanding		505,869,805
Trading Symbol	SWN

XML

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016
Operating Revenues:
Gas sales	$ 503	$ 315
Oil sales	23	11
NGL sales	40	17
Marketing	253	198
Gas gathering	27	38
Total Operating Revenues	846	579
Operating Costs and Expenses:
Marketing purchases	251	196
Operating expenses	147	165
General and administrative expenses	50	54
Restructuring charges		64
Depreciation, depletion and amortization	106	143
Impairment of natural gas and oil properties		1,034
Taxes, other than income taxes	26	23
Total Operating Costs and Expenses	580	1,679
Operating Income (Loss)	266	(1,100)
Interest Expense:
Interest on debt	58	53
Other interest charges	2	2
Interest capitalized	(28)	(41)
Total Interest Expense	32	14
Gain (Loss) on Derivatives	116	(14)
Loss on Early Extinguishment of Debt	(1)
Other Income (Loss), Net	2	(3)
Income (Loss) Before Income Taxes	351	(1,131)
Provision (Benefit) for Income Taxes:
Deferred		1
Provision (Benefit) for Income Taxes		1
Net Income (Loss)	351	(1,132)
Mandatory convertible preferred stock dividend	27	27
Participating securities - mandatory convertible preferred stock	43
Net Income (Loss) Attributable to Common Stock	$ 281	$ (1,159)
Earnings (Loss) Per Common Share:
Basic	$ 0.57	$ (3.03)
Diluted	$ 0.57	$ (3.03)
Weighted Average Common Shares Outstanding:
Basic	493,068,000	382,870,847
Diluted	494,494,995	382,870,847

XML

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) - USD ($) $ in Millions		3 Months Ended
		Mar. 31, 2017	Mar. 31, 2016
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) [Abstract]
Net income (loss)		$ 351	$ (1,132)
Change in value of pension and other postretirement liabilities:
Amortization of prior service cost and net loss included in net periodic pension cost	[1]		1
Change in currency translation adjustment			3
Comprehensive income (loss)		$ 351	$ (1,128)

[1] Net of $1 million in taxes for the three months ended March 31, 2017 and 2016.

XML

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) (Parenthetical) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) [Abstract]
Amortization of prior service cost and net loss included in net periodic pension cost, tax	$ 1	$ 1

XML

CONDENSED CONSOLIDATED BALANCE SHEETS - USD ($) $ in Millions	Mar. 31, 2017	Dec. 31, 2016
Current assets:
Cash and cash equivalents	$ 1,382	$ 1,423
Accounts receivable, net	310	363
Derivative assets	58	51
Other current assets	39	35
Total current assets	1,789	1,872
Natural gas and oil properties, using the full cost method, including $2,078 million as of March 31, 2017 and $2,105 million as of December 31, 2016 excluded from amortization	22,942	22,653
Gathering systems	1,306	1,299
Other	536	537
Less: Accumulated depreciation, depletion and amortization	(19,641)	(19,534)
Total property and equipment, net	5,143	4,955
Other long-term assets	264	249
TOTAL ASSETS	7,196	7,076
Current liabilities:
Short-term debt	266	41
Accounts payable	436	473
Taxes payable	50	59
Interest payable	29	74
Dividends payable	27	27
Derivative liabilities	280	355
Other current liabilities	33	35
Total current liabilities	1,121	1,064
Long-term debt	4,364	4,612
Pension and other postretirement liabilities	47	49
Other long-term liabilities	386	434
Total long-term liabilities	4,797	5,095
Commitments and contingencies (Note 10)
Equity:
Common stock, $0.01 par value; 1,250,000,000 shares authorized; issued 502,497,469 shares as of March 31, 2017 (does not include 3,348,214 shares issued on April 17, 2017 on account of a dividend declared on March 21, 2017) and 495,248,369 as of December 31, 2016	5	5
Preferred stock, $0.01 par value, 10,000,000 shares authorized, 6.25% Series B Mandatory Convertible, $1,000 per share liquidation preference, 1,725,000 shares issued and outstanding as of March 31, 2017 and December 31, 2016, conversion in January 2018
Additional paid-in capital	4,687	4,677
Accumulated deficit	(3,374)	(3,725)
Accumulated other comprehensive loss	(39)	(39)
Common stock in treasury, 31,269 shares as of March 31, 2017 and December 31, 2016	(1)	(1)
Total equity	1,278	917
TOTAL LIABILITIES AND EQUITY	$ 7,196	$ 7,076

XML

CONDENSED CONSOLIDATED BALANCE SHEETS (Parenthetical) - USD ($) $ in Millions	3 Months Ended	12 Months Ended
	Mar. 31, 2017	Dec. 31, 2016
Natural gas and oil properties, using the full cost method, costs excluded from amortization	$ 2,078	$ 2,105
Common stock, par value	$ 0.01	$ 0.01
Common stock, shares authorized	1,250,000,000	1,250,000,000
Common stock, shares issued	502,497,469	495,248,369
Common stock, date dividend to be paid	Apr. 17, 2017
Common stock, date dividend declared	Mar. 21, 2017
Treasury stock, shares	31,269	31,269
Series B Preferred Stock [Member]
Preferred stock, par value	$ 0.01	$ 0.01
Preferred stock, shares authorized	10,000,000	10,000,000
Preferred stock, dividend rate	6.25%	6.25%
Liquidation preference per share	$ 1,000	$ 1,000
Preferred stock, shares issued	1,725,000	1,725,000
Preferred stock, shares outstanding	1,725,000	1,725,000

XML

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016
Cash Flows From Operating Activities:
Net income (loss)	$ 351	$ (1,132)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization	106	143
Impairment of natural gas and oil properties		1,034
Amortization of debt issuance costs	2	2
Deferred income taxes		1
(Gain) loss on derivatives, unsettled	(146)	21
Stock-based compensation	6	9
Restructuring charges		42
Loss on early extinguishment of debt	1
Other	(2)	5
Change in assets and liabilities:
Accounts receivable	53	103
Accounts payable	(13)	(124)
Taxes payable	(8)	(12)
Interest payable	(24)	(11)
Other assets and liabilities	(14)	11
Net cash provided by operating activities	312	92
Cash Flows From Investing Activities:
Capital investments	(340)	(196)
Proceeds from sale of property and equipment	2
Other	4
Net cash used in investing activities	(334)	(196)
Cash Flows From Financing Activities:
Payments on short-term debt	(25)
Payments on revolving credit facility		(864)
Borrowings under revolving credit facility		2,600
Payments on commercial paper		(242)
Borrowings under commercial paper		242
Change in bank drafts outstanding	6	(19)
Preferred stock dividend		(27)
Other		(4)
Net cash provided by (used in) financing activities	(19)	1,686
Increase (decrease) in cash and cash equivalents	(41)	1,582
Cash and cash equivalents at beginning of year	1,423	15
Cash and cash equivalents at end of period	$ 1,382	$ 1,597

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CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY - 3 months ended Mar. 31, 2017 - USD ($) $ in Millions		Common Stock [Member]	Preferred Stock [Member]	Additional Paid-In Capital [Member]	Accumulated Deficit [Member]	[1]	Accumulated Other Comprehensive Income (Loss) [Member]	Common Stock in Treasury [Member]	Total
Balance, shares at Dec. 31, 2016		495,248,369	1,725,000
Balance at Dec. 31, 2016		$ 5		$ 4,677	$ (3,725)		$ (39)	$ (1)	$ 917
Comprehensive income:
Net income					351				351
Other comprehensive income
Comprehensive income (loss)									351
Stock-based compensation				10					10
Preferred stock dividend, shares	[2]	2,751,410
Issuance of restricted stock, shares		4,549,122
Cancellation of restricted stock, shares		(113,185)
Performance units vested, shares		121,208
Tax withholding - stock compensation, shares		(59,455)
Balance, shares at Mar. 31, 2017		502,497,469	1,725,000
Balance at Mar. 31, 2017		$ 5		$ 4,687	$ (3,374)		$ (39)	$ (1)	$ 1,278

[1] Includes a net cumulative-effect adjustment of $59 million related to the recognition of previously unrecognized windfall tax benefits resulting from the adoption of ASU 2016-09 as of the beginning of 2017. This adjustment was offset by an increase in net deferred tax assets and the related income tax valuation allowance of the same amount.

[2] Does not include 3,346,865 shares issued on April 17, 2017 and distributed to holders of the Company's mandatory convertible preferred stock.

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CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY (Parenthetical) - USD ($) $ in Millions		3 Months Ended
	Apr. 17, 2017	Mar. 31, 2017
Net cumulative-effect adjustment		$ 59
Common stock, date dividend to be paid		Apr. 17, 2017
Subsequent Event [Member]
Common stock, shares issued as stock dividend	3,346,865

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Basis Of Presentation

3 Months Ended

Mar. 31, 2017

Basis Of Presentation [Abstract]

Basis Of Presentation

(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 natural gas gathering and marketing businesses (“Midstream Services”).  Southwestern conducts most of its businesses through subsidiaries and operates principally in two segments: E&P and Midstream Services.

Exploration and Production.  Southwestern’s primary business is the exploration for and production of natural gas, oil and NGLs, with current operations principally focused on the development of unconventional natural gas reservoirs located in Pennsylvania, West Virginia and Arkansas.  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.”  The Company’s operations in Arkansas are primarily focused on an unconventional natural gas reservoir known as the Fayetteville Shale.  Southwestern has activities ongoing in Colorado and Louisiana, along with other areas in which it is currently assessing new development opportunities.  The Company also has drilling rigs located in Pennsylvania, West Virginia and Arkansas, as well as in other operating areas, and provides oilfield products and services, principally serving its E&P operations.

Midstream Services.Through the Company’s affiliated midstream subsidiaries, Southwestern engages in natural gas gathering activities in Arkansas and Louisiana. These activities primarily support the Company’s E&P operations and generate revenue from fees associated with the gathering of natural gas.Southwestern’s marketing activities capture opportunities that arise through the marketing and transportation of the natural gas, oil and NGLs produced in its E&P operations.

The accompanying unaudited condensed 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 unaudited condensed 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 unaudited condensed consolidated financial statements be read in conjunction with the consolidated financial statements and the notes thereto included in the Company’s Annual Report for the year ended December 31, 2016 (“2016 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 2016 Annual Report.

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Cash And Cash Equivalents

3 Months Ended

Mar. 31, 2017

Cash And Cash Equivalents [Abstract]

Cash And Cash Equivalents

(2) CASH AND CASH EQUIVALENTS

The following table presents a summary of cash and cash equivalents as of March 31, 2017 and December 31, 2016:

	March 31,		December 31,
	2017		2016
	(in millions)
Cash	$	265	$	254
Marketable securities (1)		1,117		1,169
Total cash and cash equivalents	$	1,382	$	1,423

(1) Consists ofgovernment stable value money market funds.

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Reduction In Workforce

3 Months Ended

Mar. 31, 2017

Reduction In Workforce [Abstract]

Reduction In Workforce

(3) REDUCTION IN WORKFORCE

In January 2016, the Company announced a 40% workforce reduction as a result of lower anticipated drilling activity.  This reduction was substantially completedin the first quarter of 2016.  In April 2016, the Company also partially restructured executive management, which was substantially completed in the second quarter of 2016.

The following table presents a summary of the restructuring charges for the threemonths ended March 31, 2016:

	For the three months ended
	March 31, 2016
	(in millions)
Severance (including payroll taxes)	$	42
Stock-based compensation		18
Pension and other postretirement benefits		3
Outplacement services, other		1
Total restructuring charges (1)	$	64

(1) Total restructuring charges were $61 million and $3 million for the Company’s E&P and Midstream Services segments, respectively.

Severance payments and other separation costs related to restructuring were substantially completed by the end of 2016.

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Natural Gas And Oil Properties

3 Months Ended

Mar. 31, 2017

Natural Gas And Oil Properties [Abstract]

Natural Gas And Oil Properties

(4) 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 costsare 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 designatedfor 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 $2.73 per MMBtu, West Texas Intermediate oil of $44.10 per barrel and NGLs of $10.17 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 and did not result in a ceiling test impairmentat March 31, 2017. The Company had no hedge positionsthat were designated for hedge accountingas of March 31, 2017.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 $2.40 per MMBtu, West Texas Intermediate oil of $42.77 per barrel and NGLs of $5.76 per barrel, adjusted for differentials, the net book value of the Company’s United States natural gas and oil properties exceeded the ceiling by $641 million (net of tax) at March 31, 2016 and resulted in a non-cash ceiling test impairment.The Company had no hedge positions that were designated for hedge accounting as of March 31, 2016.

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Earnings Per Share

3 Months Ended

Mar. 31, 2017

Earnings Per Share [Abstract]

Earnings Per Share

(5) EARNINGS PER SHARE

Basic earnings per common share is computed by dividing net income (loss) 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 July 2016, the Company completed an underwritten public offering of 98,900,000 shares of its common stock, with an offering price to the public of $13.00 per share.  Net proceeds from the common stock offering were approximately $1,247 million, after underwriting discount and offering expenses.  The proceeds from the offering were used to repay $375 million of the $750 million term loan entered into in November 2015 and to settle certain tender offers by purchasing an aggregate principal amount of approximately $700 million of the Company’s outstanding senior notes due in the first quarter of 2018.  The remaining proceeds of the offering have been used for general corporate purposes.

The mandatory convertible preferred stock issued in January 2015 entitles the holder to a proportional fractional interest in the rights and preferences of the convertible preferred stock, including conversion, dividend, liquidation and voting rights. Unless converted earlier at the option of the holders, on or around January 15, 2018 each share of convertible preferred stock will automatically convert into between 37.0028 and 43.4782 shares of the Company’s common stock (correspondingly, each depositary share will convert into between 1.85014 and 2.17391 shares of the Company’s common stock), subject to customary anti-dilution adjustments, depending on the volume-weighted average price of the Company’s common stock over a 20 trading day averaging period immediately prior to that date.  The total potential shares of common stock resulting from the conversion will range from 63,829,830 to 74,999,895 shares.

The mandatory convertible preferred stock has 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 as such, is considered a participating security.Accordingly, it is 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, participating securities are allocated earnings 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.

The following table presents the computation of earnings per share for the threemonths ended March 31, 2017 and 2016:

	For the three months ended March 31,
	2017		2016
	(in millions, except share/per share amounts)
Net income (loss)	$	351	$	(1,132)
Mandatory convertible preferred stock dividend		27		27
Participating securities - mandatory convertible preferred stock		43		–
Net income (loss) attributable to common stock	$	281	$	(1,159)
Number of common shares:
Weighted average outstanding		493,068,000		382,870,847
Issued upon assumed exercise of outstanding stock options		82,845		–
Effect of issuance of non-vested restricted common stock		770,429		–
Effect of issuance of non-vested performance units		573,721		–
Effect of issuance of mandatory convertible preferred stock		–		–
Weighted average and potential dilutive outstanding		494,494,995		382,870,847
Earnings (Loss) per common share:
Basic	$	0.57	$	(3.03)
Diluted	$	0.57	$	(3.03)

The following table presents the common stock shares equivalent excluded from the calculation of diluted earnings per share for the three months ended March 31, 2017 and 2016, as they would have had an antidilutive effect:

	For the three months ended March 31,
	2017	2016
Unvested stock options	1,854,004	5,732,521
Unvested share-based payment	1,212,396	5,779,820
Performance units	–	297,297
Mandatory convertible preferred stock	74,999,895	74,999,895
Total	78,066,295	86,809,533

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Derivatives And Risk Management

3 Months Ended

Mar. 31, 2017

Derivatives And Risk Management [Abstract]

Derivatives And Risk Management

(6) DERIVATIVES AND RISK MANAGEMENT

The Company is exposed to volatility in market prices and basis differentials for natural gas, oil and NGLs which impacts the predictability of its cash flows related to the sale of those commodities.  These risks are managed by the Company’s use of certain derivative financial instruments.  As of March 31, 2017 and December 31, 2016, the Company’s derivative financial instruments consisted of fixed price swaps, two-way costless collars, three-way costless collars,basis swaps, put and call options, and interest rate swaps.  A description of the Company’s derivative financial instruments is provided below:

Fixed price swaps	The Company receives a fixed price for the contract and pays a floating market price to the counterparty.
Purchased put options	The Company purchases put options based on an index price from the counterparty by payment of a cash premium.  If the index price is lower than the put’s strike price at the time of settlement, the Company receives from the counterparty such difference between the index price and the purchased put strike price.  If the market price settles above the put’s strike price, no payment is due from either party.
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.  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.
Sold call options	The Company sells call options in exchange for a premium.  If the market price exceeds the strike price of the call option at the time of settlement, the Company pays the counterparty such excess on sold call options. If the market price settles 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 utilizes counterparties for its derivative instruments that it believes are creditworthy at the time the transactions are entered into, and the Company closely monitors the credit ratings of these counterparties. Additionally, the Company performs both quantitative and qualitative assessments of these counterparties based on their credit ratings and credit default swap rates where applicable. However, the events in the financial markets in recent years demonstrate there can be no assurance that a counterparty will be able to meet its obligations to the Company.

The following table provides 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 table presents the notional amount in Bcf, the weighted average contract prices and the fair value by expected maturity dates as of March 31, 2017:

		Weighted Average Price per MMBtu
	Volume (Bcf)	Swaps		Sold Puts		Purchased Puts		Sold Calls		Basis Differential		Fair value at March 31, 2017 (in millions)
Financial protection on production
2017
Fixed price swaps	262	$	3.07	$	–	$	–	$	–	$	–	$	(58)
Two-way costless-collars	65		–		–		2.92		3.34		–		(11)
Three-way costless-collars	102		–		2.29		2.97		3.30		–		(16)
Basis swaps	138		–		–		–		–		(1.04)		(73)
Total	567											$	(158)
2018
Fixed price swaps	68	$	3.02	$	–	$	–	$	–	$	–	$	(1)
Two-way costless-collars	23		–		–		2.97		3.56		–		(6)
Three-way costless-collars	245		–		2.39		2.97		3.37		–		(6)
Basis swaps	20		–		–		–		–		(0.95)		(15)
Total	356											$	(28)
2019
Three-way costless-collars	99	$	–	$	2.50	$	2.95	$	3.31	$	–	$	(2)
Total	99											$	(2)

		Weighted Average Price per MMBtu
	Volume (Bcf)	Sold Calls		Fair value at March 31, 2017 (in millions)
Call options
2017	64	$	3.54	$	(10)	(1)
2018	63		3.50		(14)
2019	52		3.50		(10)
2020	32		3.75		(5)
Total	211			$	(39)

(1) Excludes$5 million in premiums paid related to certain call options recognized as a component of derivative assets within current assets on the unaudited condensed consolidated balance sheet.  As certain call options settle, the premium will be amortized and recognized as a component of gain (loss) on derivatives on the unaudited condensed consolidated statement of operations.

The balance sheet classification of the assets and liabilities related to derivative financial instruments (none of which are designated for hedge accounting treatment) are summarized below as of March 31, 2017 and December 31, 2016:

	Derivative Assets
	Balance Sheet Classification		Fair Value
			March 31, 2017			December 31, 2016
		(in millions)
Derivatives not designated as hedging instruments:
Fixed price swaps	Derivative assets		$	2		$	–
Two-way costless collars	Derivative assets			11			8
Three-way costless collars	Derivative assets			23			11
Basis swaps	Derivative assets			2			32
Call options	Derivative assets			15			–
Fixed price swaps	Other long-term assets			7			1
Two-way costless collars	Other long-term assets			–			2
Three-way costless collars	Other long-term assets			120			100
Basis swaps	Other long-term assets			–			1
Total derivative assets			$	180	(1)	$	155
	Derivative Liabilities
	Balance Sheet Classification		Fair Value
			March 31, 2017			December 31, 2016
			(in millions)
Derivatives not designated as hedging instruments:
Fixed price swaps	Derivative liabilities		$	68		$	175
Two-way costless collars	Derivative liabilities			28			49
Three-way costless collars	Derivative liabilities			62			70
Basis swaps	Derivative liabilities			89			13
Call options	Derivative liabilities			32			46
Interest rate swaps	Derivative liabilities			1			2
Fixed price swaps	Other long-term liabilities			–			3
Two-way costless collars	Other long-term liabilities			–			9
Three-way costless collars	Other long-term liabilities			105			122
Basis swaps	Other long-term liabilities			1			5
Call options	Other long-term liabilities			22			35
Interest rate swaps	Other long-term liabilities			1			1
Total derivative liabilities			$	409		$	530

(1) Does not include $5 million in premiums paid related to certain call options currently recognized as a component of derivative assets within current assets on the unaudited condensed consolidated balance sheet.  As certain call options settle, the premium will be amortized and recognized as a component of gain (loss) on derivatives on the unaudited condensed consolidated statement of operations.

At March 31, 2017, the net fair value of the Company’s financial instruments related to natural gas was a $227million liability.  The net fair value of the Company’s interest rate swaps was a $2 million liability as of March 31, 2017.

Derivative Contracts Not Designated for Hedge Accounting

As of March 31, 2017, the Company had no positions designated for hedge accounting treatment.  Gains and losses on derivatives that are not designated for hedge accounting treatment, or that do not meet hedge accounting requirements, are recorded as a component of gain (loss) on derivatives on the unaudited condensed consolidated statements of operations.  Accordingly, the gain (loss) on derivatives component of the statements of operations reflects the gains 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 unaudited condensed consolidated statements of operations.

The following tables summarize the before tax effect of fixed price swaps, purchased put options, two-way costless collars, three-way costless collars, basis swaps, call optionsand interest rate swaps not designated for hedge accounting on the unaudited condensed consolidated statements of operations for the three months ended March 31, 2017 and 2016:

		Gain (Loss) on Derivatives, Unsettled
		Recognized in Earnings
	Consolidated Statement of Operations	For the three months ended
	Classification of Gain (Loss)	March 31,
Derivative Instrument	on Derivatives, Unsettled	2017		2016
		(in millions)
Fixed price swaps	Gain (Loss) on Derivatives	$	118	$	20
Purchased put options	Gain (Loss) on Derivatives		–		15
Two-way costless-collars	Gain (Loss) on Derivatives		31		–
Three-way costless- collars	Gain (Loss) on Derivatives		57		–
Basis swaps	Gain (Loss) on Derivatives		(103)		(3)
Call options	Gain (Loss) on Derivatives		42		(50)
Interest rate swaps	Gain (Loss) on Derivatives		1		(3)
Total gain (loss) on unsettled derivatives		$	146	$	(21)
		Gain (Loss) on Derivatives, Settled (1)
		Recognized in Earnings
	Consolidated Statement of Operations	For the three months ended
	Classification of Gain (Loss)	March 31,
Derivative Instrument	on Derivatives, Settled	2017		2016
		(in millions)
Fixed price swaps	Gain (Loss) on Derivatives	$	(16)	$	4
Two-way costless-collars	Gain (Loss) on Derivatives		(3)		–
Three-way costless-collars	Gain (Loss) on Derivatives		(4)		–
Basis swaps	Gain (Loss) on Derivatives		(1)		4
Call options	Gain (Loss) on Derivatives		(6)		–
Interest rate swaps	Gain (Loss) on Derivatives		–		(1)
Total gain (loss) on settled derivatives (2)		$	(30)	$	7
Total gain (loss) on derivatives		$	116	$	(14)

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

(2) Excluding interest rate swaps, these amounts are included, along with gas sales revenues, in the calculation of the Company’s realized natural gas price.

Derivative Contracts Designated for Hedge Accounting

All derivatives are recognized in the balance sheet as either an asset or liability and are measured at fair value, other than transactions for which normal purchase/normal sale is applied. Certain criteria must be satisfied in order for derivative financial instruments to be designated for hedge accounting.  Unrealized gains and losses related to unsettled derivatives that have been designated for hedge accounting treatment are recorded in either earnings or as a component of other comprehensive income until settled.  In the period of settlement, the Company recognizes the gains and losses from these qualifying hedges in gas sales revenues.As of March 31, 2017 and 2016, the Company had no positions designated for hedge accounting treatment.  

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Reclassifications From Accumulated Other Comprehensive Income (Loss)

3 Months Ended

Mar. 31, 2017

Reclassifications From Accumulated Other Comprehensive Income (Loss) [Abstract]

Reclassifications From Accumulated Other Comprehensive Income (Loss)

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

The following tables detail the components of accumulated other comprehensive income (loss) and the related tax effects for the three months ended March 31, 2017:

	March 31, 2017
	Pension and Other Postretirement		Foreign Currency		Total
	(in millions)
Beginning balance, December 31, 2016	$	(19)	$	(20)	$	(39)
Other comprehensive income (loss) before reclassifications		–		–		–
Amounts reclassified from other comprehensive income (loss) (1)		–		–		–
Net current-period other comprehensive income (loss)		–		–		–
Ending balance, March 31, 2017	$	(19)	$	(20)	$	(39)

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

1

Details about Accumulated Other Comprehensive Income	Affected Line Item in the Consolidated Statement of Operations	Amount Reclassified from Accumulated Other Comprehensive Income
		For the three months ended March 31, 2017
		(in millions)
Pension and other postretirement:
Amortization of prior service cost and net loss (1)	General and administrative expenses	$	1
	Provision for income taxes		1
	Net income (loss)	$	–
Total reclassifications for the period	Net income (loss)	$	–

(1)     See Note 11 for additional details regarding the Company’s retirement and employee benefit plans.

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Fair Value Measurements

3 Months Ended

Mar. 31, 2017

Fair Value Measurements [Abstract]

Fair Value Measurements

(8) FAIR VALUE MEASUREMENTS

The carrying amounts and estimated fair values of the Company’s financial instruments as of March 31, 2017 and December 31, 2016 were as follows:

	March 31, 2017				December 31, 2016
	Carrying		Fair		Carrying		Fair
	Amount		Value		Amount		Value
	(in millions)
Cash and cash equivalents	$	1,382	$	1,382	$	1,423	$	1,423
Credit facility		–		–		–		–
Term loan facility due December 2020 (1)		327		327		327		327
Term loan facility due December 2020 (1)		1,191		1,191		1,191		1,191
Senior notes		3,141		3,088		3,166		3,182
Derivative instruments, net (2)		(229)		(229)		(375)		(375)

(1) The maturity date will accelerate to October 2019 if, by that date, the Company has not amended, redeemed or refinanced at least $765 million of its senior notes due in January 2020.

(2) Does not include $5 million in premiums paid related to certain call options currently recognized as a component of derivative assets within current assets on the unaudited condensed consolidated balance sheet.

The carrying values of cash and cash equivalents, accounts receivable, other current assets,accounts payable and other current liabilities on the unaudited condensed 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 yield of the Company’s senior notes.

The carrying values of the borrowings under the Company’s term loan facilities and unsecured revolving credit facility approximate fair value because the interest rate is variable and reflective of market rates. The Company considers the fair value of its debt to be a Level 2 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 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 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. The Company utilized discounted cash flow models for valuing its interest rate derivatives (Level 2). The net derivative values attributable to the Company’s interest rate derivative contracts as of March 31, 2017 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, purchased put options, two-way costless collars and three-way costless collars (Level 3) 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 futures index, interest rates, volatility and credit worthiness.  The Company’s basis swaps (Level 3) are estimated using third-party calculations based upon forward commodity price curves.

Inputs to the Black-Scholes model, including the volatility input, which is the significant unobservable input for Level 3 fair value measurements, 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.

Assets and liabilities measured at fair value on a recurring basis are summarized below (in millions):

	March 31, 2017
	Fair Value Measurements Using:
	Quoted Prices in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Assets (Liabilities) at Fair Value
Fixed price swap assets	$	–	$	9	$	–	$	9
Two-way costless collars assets		–		–		11		11
Three-way costless collars assets		–		–		143		143
Basis swap assets		–		–		2		2
Call option assets (1)		–		–		15		15
Fixed price swap liabilities		–		(68)		–		(68)
Two-way costless collars liabilities		–		–		(28)		(28)
Three-way costless collars liabilities		–		–		(167)		(167)
Basis swap liabilities		–		–		(90)		(90)
Call option liabilities		–		–		(54)		(54)
Interest rate swap liabilities		–		(2)		–		(2)
Total	$	–	$	(61)	$	(168)	$	(229)

(1) Does not include $5 million in premiums paid related to certain call options currently recognized as a component of derivative assets within current assets on the unaudited condensed consolidated balance sheet.

	December 31, 2016
	Fair Value Measurements Using:
	Quoted Prices in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Assets (Liabilities) at Fair Value
Fixed price swap assets	$	–	$	1	$	–	$	1
Two-way costless collars assets		–		–		10		10
Three-way costless collars assets		–		–		111		111
Basis swap assets		–		–		33		33
Fixed price swap liabilities		–		(178)		–		(178)
Two-way costless collars liabilities		–		–		(58)		(58)
Three-way costless collars liabilities		–		–		(192)		(192)
Basis swap liabilities		–		–		(18)		(18)
Call option liabilities		–		–		(81)		(81)
Interest rate swap liabilities		–		(3)		–		(3)
Total	$	–	$	(180)	$	(195)	$	(375)

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 months ended March 31, 2017and 2016.  The fair values of Level 3 derivative instruments are estimated using proprietary valuation models that utilize both market observable and unobservable parameters.  Level 3 instruments presented in the table consist of net derivatives valued using pricing models incorporating assumptions that, in the Company’s judgment, reflect reasonable assumptions a marketplace participant would have used as of March 31, 2017 and 2016.

	For the three months ended
	March 31,
	2017		2016
	(in millions)
Balance at beginning of period	$	(195)	$	3
Total gains (losses):
Included in earnings		13		(34)
Settlements		14		(4)
Transfers into/out of Level 3		–		–
Balance at end of period	$	(168)	$	(35)
Change in gains (losses) included in earnings relating to derivatives still held as of March 31	$	27	$	(38)

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Debt

3 Months Ended

Mar. 31, 2017

Debt [Abstract]

Debt

(9) DEBT

The components of debt as of March 31, 2017 and December 31, 2016 consisted of the following:

	March 31, 2017
	Debt Instrument		Unamortized Issuance Expense		Unamortized Debt Discount		Total
		(in millions)
Short-term debt:
7.35% Senior Notes due October 2017	$	15	$	–	$	–	$	15
7.125% Senior Notes due October 2017		25		–		–		25
3.30% Senior Notes due January 2018 (1)		38		–		–		38
7.50% Senior Notes due February 2018 (2)		187		–		–		187
7.15% Senior Notes due June 2018		1		–		–		1
Total short-term debt	$	266	$	–	$	–	$	266
Long-term debt:
Variable rate (3.450% at March 31, 2017) term loan facility, due December 2020(3)		327		(2)		–		325
Variable rate (3.450% at March 31, 2017) term loan facility, due December 2020(3)		1,191		(10)		–		1,181
7.15% Senior Notes due June 2018		25		–		–		25
4.05% Senior Notes due January 2020(1)		850		(4)		–		846
4.10% Senior Notes due March 2022		1,000		(4)		(1)		995
4.95% Senior Notes due January 2025(1)		1,000		(6)		(2)		992
Total long-term debt	$	4,393	$	(26)	$	(3)	$	4,364
Total debt	$	4,659	$	(26)	$	(3)	$	4,630

	December 31, 2016
	Debt Instrument		Unamortized Issuance Expense		Unamortized Debt Discount		Total
		(in millions)
Short-term debt:
7.35% Senior Notes due October 2017	$	15	$	–	$	–	$	15
7.125% Senior Notes due October 2017		25		–		–		25
7.15% Senior Notes due June 2018		1		–		–		1
Total short-term debt	$	41	$	–	$	–	$	41
Long-term debt:
Variable rate (3.220% at December 31, 2016) term loan facility, due December 2020 (3)		327		(2)		–		325
Variable rate (3.220% at December 31, 2016) term loan facility, due December 2020 (3)		1,191		(10)		–		1,181
3.30% Senior Notes due January 2018(1)		38		–		–		38
7.50% Senior Notes due February 2018		212		–		–		212
7.15% Senior Notes due June 2018		25		–		–		25
4.05% Senior Notes due January 2020 (1)		850		(5)		–		845
4.10% Senior Notes due March 2022		1,000		(4)		(1)		995
4.95% Senior Notes due January 2025 (1)		1,000		(7)		(2)		991
Total long-term debt	$	4,643	$	(28)	$	(3)	$	4,612
Total debt	$	4,684	$	(28)	$	(3)	$	4,653

(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 5.05% for the 2018 Notes, 5.80% for the 2020 Notes and 6.70% for the 2025 Notes.

(2) In March 2017, the Company repurchased$25 million of its 7.50% Senior Notes due February 2018 andrecognized a  $1 million loss on the extinguishment of debt.

(3) The maturity date will accelerate to October 2019 if, by that date, the Company has not amended, redeemed or refinanced at least $765 million of its senior notes due in January 2020.

2016 Credit Facility

In June 2016, the Company reduced its existing $2.0 billion unsecured revolving credit facility to $66 million and entered into a new credit agreement for $1,934 million, consisting of a $1,191 million secured term loan and a new $743 million unsecured revolving credit facility, which matures in December 2020.  The maturity date will accelerate to October 2019 if, by that date, the Company has not amended, redeemed or refinanced at least $765 million of its senior notes due January 2020.  The $1,191 million secured term loan is fully drawn, with approximately $285 million of this balance used to pay down the previous revolving credit facility balance in its entirety.  As of March 31, 2017, there were no borrowings under either revolving credit facility; however, $327 million in letters of credit was outstanding against the 2016 revolving credit facility. 

Loans under the 2016 credit agreement 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 plus applicable margins ranging from 1.750% to 2.500%.  Alternate base rate loans bear interest at the alternate base rate plus the applicable margin ranging from 0.750% to 1.500%.  The interest rate on the term loan facility is determined based upon the Company’s public debt ratings and was 250 basis points over LIBOR as of March 31, 2017.

The new term loan and revolving credit facility contain financial covenants that impose certain restrictions on the Company.  Under the new credit agreement, the Company must maintain a minimum interest coverage of 1.00x in 2017, increasing by 0.25x increments per year to 1.50x in 2019 and 2020.  The Company is also subject to a minimum liquidity requirement of $300 million, which could be increased up to $500 million upon certain conditions, as well as an anti-hoarding provision, requiring unrestricted cash in excess of $100 million to pay down any amounts borrowed under the new revolving credit facility.  The financial covenant with respect to minimum interest coverage consists of EBITDAX divided by consolidated interest expense.  EBITDAX, as defined in our 2016 credit agreement, excludes the effects of interest expense, income taxes, depreciation, depletion and amortization, 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.  Collateral for the new secured term loan is principally the Company’s E&P properties in the Fayetteville Shale area, the equity of its subsidiaries and cash and marketable securities on hand, and the new credit agreement requires a minimum collateral coverage ratio of 1.50x for the 2016 secured term loan.  This collateral also may support all or a part of revolving credit extensions depending on restrictions in the Company’s senior notes indentures.

As of March 31, 2017, the Company was in compliance with all of the covenants of this credit agreement.  Although the Company does not anticipate any violations of the financial covenants, its ability to comply with these covenants is dependent upon the success of its exploration and development program and upon factors beyond the Company’s control, such as the market prices for natural gas, oil and NGLs.

2013 Credit Facility

In December 2013, the Company entered into a credit agreement that exchanged its previous revolving credit facility.  Under the revolving credit facility, the Company had a borrowing capacity of $2.0 billion.  The revolving credit facility was unsecured and was not guaranteed by any subsidiaries.  On March 30, 2016, the Company borrowed $1.55 billion on the revolving credit facility with the proceeds invested in marketable securities.  The $1.55 billion borrowing was repaid on April 1, 2016.  In June 2016, this credit facility was substantially exchanged for a new credit facility comprised of a $1,191million secured term loan and a new $743million revolving credit facility.  The borrowing capacity of the original 2013 credit agreement was reduced from $2.0 billion to $66 million, remains unsecured and the maturity remainsDecember 2018.  As of March 31, 2017, there were no borrowings under this facility.

The existing unsecured 2013 revolving credit facility includes a financial covenant under which the Company may not have total debt in excess of 60% of its total adjusted book capital.  This financial covenant with respect to capitalization percentages excludes the effects of any full cost ceiling impairments, certain hedging activities and the Company’s pension and other postretirement liabilities.  At March 31, 2017, debt constituted 34%of the Company’s adjusted book capital.

2015 Term Facility

In November 2015, the Company entered into a $750 million unsecured three-year term loan credit agreement with various lenders that was utilized to repay borrowings under the revolving credit facility.  The interest rate on the term loan facility is determined based upon the Company’s public debt ratings from Moody’s and S&P and was 250 basis points over LIBOR as of March 31, 2017.  The term loan facility requires prepayment under certain circumstances from the net cash proceeds of sales of equity or certain assets and borrowings outside the ordinary course of business. In June 2016, this term loan agreement was amended to extend the maturity date upon a repayment threshold.  From the net proceeds of the July 2016 equity offering, the Company repaid $375 million of the $750 million unsecured term loan, which had the effect of extending the term loan maturity from November 2018 to December 2020, which will accelerate to October 2019 if, by that date, the Company has not amended, redeemed or refinanced at least $765 million of its senior notes due in January 2020.  In September 2016, the Company repaid an additional $48 million from the proceeds received from the closing of the sale of approximately 55,000 net acres in West Virginia.

Senior Notes

In January 2015, the Company completed a public offering of $350 million aggregate principal amount of its 3.30% senior notes due 2018 (the “2018 Notes”), $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 2018 and 2020 Notes, the “Notes”), with net proceeds from the offering totaling approximately $2.2 billion after underwriting discounts and offering expenses.  The Notes were sold to the public at a price of 99.949% of their face value for the 2018 Notes, 99.897% of their face value for the 2020 Notes and 99.782% of their face value for the 2025 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 5.05% for the 2018 Notes, 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 5.30%,  6.05% and 6.95%, respectively.  The first coupon payment at the higher interest rateswas paid in January 2017.

In July2016,the Company used a portion of the proceeds from the July 2016 equity offering to settle certain tender offersby purchasing an aggregate principal amount of approximately $700 million of its outstanding senior notes due in the first quarter of 2018.

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Commitments And Contingencies

3 Months Ended

Mar. 31, 2017

Commitments And Contingencies [Abstract]

Commitments And Contingencies

(10) COMMITMENTS AND CONTINGENCIES

Operating Commitments and Contingencies

As of March 31, 2017, 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 $8.7 billion, $3.7 billion 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 $821 million of that amount.  As of March 31, 2017, future payments under non-cancelable firm transportation and gathering agreements are as follows:

	Payments Due by Period
	Total		Less than 1 Year		1 to 3 Years		3 to 5 Years		5 to 8 Years		More than 8 Years
		(in millions)
Infrastructure currently in service	$	5,011	$	592	$	1,139	$	791	$	832	$	1,657
Pending regulatory approval and/or construction (1)		3,661		35		371		474		730		2,051
Total transportation charges	$	8,672	$	627	$	1,510	$	1,265	$	1,562	$	3,708

(1) Based on the estimated in-service dates as of March  31, 2017.

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 or results of operations 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 and pollution, contamination or nuisance. The Company accrues for such items when a liability is both probable and the amount can be reasonably estimated.Management believes that current litigation, claims and proceedings, individually or in aggregate and after taking into account insurance, are not likely to have a material adverse impact on the Company’s financial position, results of operations or cash flows, although it is possible that adverse outcomes could have a material adverse effect on the Company’s 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

Certain of the Company’s subsidiaries are defendants in three cases, two filed in Arkansas state court in 2010 and 2013 and one in federal court in 2014, on behalf of putative classes of royalty owners on some of the Company’s leases located in Arkansas.  The chief complaint in all three cases is that one of the Company’s subsidiaries underpaid the royalty owners by, among other things, deducting from royalty payments costs for gathering, transportation, and compression of natural gas in excess of what is permitted by the relevant leases.  In September and October 2014, the judges in the two Arkansas state actions entered orders certifying classes of royalty owners who are citizens of Arkansas. 

In November 2015, the court in the federal case denied the plaintiff’s motion to certify a class of royalty owners not included in either of the two state cases.  In April 2016, the court certified a broader class that includes Arkansas residents and citizens.  Class members were notified of the pending action in late 2016, and the period to “opt out” of the class has expired.  The plaintiff in the federal case presented two alternative damages theories.  Under one theory, plaintiffs have asserted that obligations to affiliates are not “incurred” and therefore the exploration and production subsidiary was not entitled to deduct any post-production costs; the federal court has granted partial summary judgment for the Company’s subsidiaries on this theory.  Under another theory, plaintiffs assert that the gathering and treating rates the Company deducted from royalty payments exceeded the affiliates’ actual costs or otherwise were not reasonable.  The class representative’s expert’s report alleges class-wide damages in this case of approximately $98 million, before interest and statutory amounts.  The class is also seeking punitive damages.  The Company moved for summary judgment on all claims.  The court granted the motion in part and denied it in part and has set a trial date in the second quarter of 2017.

The Company’s subsidiaries appealed the class certification order in the state cases. In December 2016, the Arkansas Supreme Court affirmed the certifications.  These cases are now before the Arkansas trial judges.  The precise configuration of the classes has not been determined, particularly in light of the overlapping composition of the class in the federal case.  One of the state cases has been set for trial in the third quarter of 2017.  No date for trial has been set in the other state case.

In addition, in September 2015 three cases were filed in Arkansas state court on behalf of a total of 248 individually named plaintiffs.  Each case asserts complaints that are in substance virtually identical to the above-described case.  The Company and its subsidiaries have removed two of the cases to federal court, and those cases have been assigned to the court in which the above-described federal case is pending.  All three cases have been stayed.

Management believes that, in all of the above cases, the deductions from royalty payments as calculated are permitted and is vigorously defending the cases.  The Company’s assessment may change in the future due to the occurrence of certain events, such as adverse judgments, and such a re-assessment could lead to the determination that the potential liability is probable and could be material to the Company’s results of operations, financial position or cash flows.

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.No liability has been recognized in connection with these indemnifications.

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Pension Plan And Other Postretirement Benefits

3 Months Ended

Mar. 31, 2017

Pension Plan And Other Postretirement Benefits [Abstract]

Pension Plan And Other Postretirement Benefits

(11) PENSION PLAN AND OTHER POSTRETIREMENT BENEFITS

The Company has defined pension and postretirement benefit plans which cover substantially all of the Company’s employees. Net periodic pension costs include the following components for the three months ended March 31, 2017 and 2016:  

	Pension Benefits
	For the three months ended
	March 31,
	2017		2016
	(in millions)
Service cost	$	2	$	4
Interest cost		1		2
Expected return on plan assets		(1)		(2)
Amortization of prior service cost		–		–
Amortization of net loss		1		–
Net periodic benefit cost	$	3	$	4

The Company’s other postretirement benefit plan had a net periodic benefit cost of $1 million for the three months ended March 31, 2017 and 2016.  

As of March 31, 2017, the Company has contributed $5million to the pension and other postretirement benefit plans in 2017.  The Company expects to contribute an additional $9 million to its pension plan during the remainder of 2017.  The Company recognized a liability of $34 million and $13 million related to its pension and other postretirement benefits, respectively, as of March 31, 2017, compared to a liability of $36 million and $13 million as of December 31, 2016.  The Company used an assumption of 4.60%during the first quarter of 2016 for both the pension and other postretirement benefit plans.In January 2016, the Company initiated a reduction in workforce that was substantially completed by the end of the first quarter of 2016.  The impact of the workforce reduction on the Company’s pension and other postretirement benefit costs was not recognized until subsequent quarters in 2016 due to the delayed timing of actuarial data available.  The Company updated the discount rate currently used in the measurement of the benefit obligation of the pension plan and other postretirement benefits plan to 4.20% in the second quarter of 2016. 

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 plan. Shares of the Company’s common stock purchased under the terms of the Non-Qualified Plan are presented as treasury stock and totaled 11,686 shares at March 31, 2017, compared to 31,269shares at December 31, 2016.

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Stock-Based Compensation

3 Months Ended

Mar. 31, 2017

Stock-Based Compensation [Abstract]

Stock-Based Compensation

(12) STOCK-BASED COMPENSATION

The Company recognized the following amounts in employee stock-based compensation costs for the three months ended March 31, 2017 and 2016:

	For the three months ended
	March 31,
	2017		2016
	(in millions)
Stock-based compensation cost – expensed (1)	$	6	$	23
Stock-based compensation cost – capitalized	$	4	$	3

(1) Includes $18 million related to the reduction in workforce for the three months ended March 31, 2016.

In January 2016, the Company announced a 40% workforce reduction that was substantially completed by the end of March 2016.  In April 2016, the Company also partially restructured executive management, which was substantially completed in the second quarter of 2016.  Affected employees were offered a severance package that included, if applicable, amendments to certain outstanding equity awards that modified forfeiture provisions on separation from the Company.  As a result, certain unvested stock-based equity awards became fully vested at the time of separation.  These shares were revalued and recognized immediately as a component of restructuring charges on the Company’s unaudited condensed consolidated statements of operations.  The unvested portion of equity-based performance units was forfeited upon separation from the Company.

As of March 31, 2017, there was $96 million of total unrecognized compensation cost related to the Company’s unvested stock option grants, restricted stock grants and performance units.  This cost is expected to be recognized over a weighted-average period of 3years.

Stock Options

The following table summarizes stock option activity for the three months ended March 31, 2017 and provides information for options outstanding and options exercisable as of March 31, 2017:

	Number		Weighted Average
	of Options		Exercise Price
	(in thousands)		(per share)
Outstanding at December 31, 2016		5,416	$	23.46
Granted		1,322		8.59
Exercised		–		–
Forfeited or expired		(17)		45.57
Outstanding at March 31, 2017		6,721		20.48
Exercisable at March 31, 2017		3,537	$	29.34

Restricted Stock

The following table summarizes restricted stock activity for the three months ended March 31, 2017 and provides information for unvested shares as of March 31, 2017:  

	Number		Weighted Average
	of Shares		Fair Value
	(in thousands)		(per share)
Unvested shares at December 31, 2016		3,321	$	11.85
Granted		4,549		8.59
Vested		(70)		13.45
Forfeited		(113)		10.05
Unvested shares at March 31, 2017		7,687	$	9.93

Equity-Classified Performance Units

The following table summarizes performance unit activity for the three months ended March 31, 2017 to be paid out in Company stock and provides information for unvested units as of March 31, 2017.  The performance units awarded in 2013 and 2014 included a market condition based on relative Total Shareholder Return (“TSR”) and a performance condition based on the Company's Present Value Index (“PVI”), collectively the “Performance Measures.”The fair value of the TSR market conditionis based on a Monte Carlo model and is amortized to compensation expense on a straight-line basis over the vesting period of the award. The fair value of the PVI performance condition is based on economic analysis for each investment opportunity based upon the expected present value added for each dollar to be invested and amortized to compensation expense on a straight line basis over the vesting period of the award. The performance unit awards granted in 2015, 2016 and during the first quarter of 2017 are based exclusively on TSR.  The grant date fair value is calculated using the applicable Performance Measures and the closing price of the Company’s common stock at the grant date.

	Number		Weighted Average
	of Units (1)		Fair Value
	(in thousands)		(per share)
Unvested units at December 31, 2016		719	$	11.46
Granted		1,197		10.47
Vested		–		–
Forfeited		–		–
Unvested units at March 31, 2017		1,916	$	10.84

(1) These amounts reflect the number of performance units granted in thousands.  The actual payout of shares may range from a minimum of zero shares to a maximum of two shares contingent upon the actual performance against the Performance Measures. 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 Performance Units

Prior to 2013, certain employees were provided performance units vesting equally over three years, payable in cash.  The payout of these units was based on certain metrics, such as total shareholder return and reserve replacement efficiency, compared to a predetermined group of peer companies and Company goals.  At the end of each performance period, the value of the vested performance units, if any, would bepaid in cash.  In the first quarter of 2016, the Companycompleted the final payout under these performance unit agreements.

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Segment Information

3 Months Ended

Mar. 31, 2017

Segment Information [Abstract]

Segment Information

(13) 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 Services segment generates revenue through the marketing of both Company and third-party produced natural gas and liquids volumes and through gathering fees associated with the transportation of natural gas to market.

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 2016 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.

	Exploration and Production			Midstream Services			Other			Total
	(in millions)
Three months ended March 31, 2017:
Revenues from external customers	$	566		$	280		$	–		$	846
Intersegment revenues		(3)			578			–			575
Depreciation, depletion and amortization expense		90			16			–			106
Operating income		225			41			–			266
Interest expense (1)		32			–			–			32
Gain on derivatives		116			–			–			116
Loss on early extinguishment of debt		–			–			(1)			(1)
Other income, net		2			–			–			2
Assets		4,413			1,268			1,515	(2)		7,196
Capital investments (3)		283			6			1			290
Three months ended March 31, 2016:
Revenues from external customers	$	343		$	236		$	–		$	579
Intersegment revenues		(7)			385			–			378
Depreciation, depletion and amortization expense		127			16			–			143
Impairment of natural gas and oil properties		1,034			–			–			1,034
Operating income (loss)		(1,160)	(4)		60	(5)		–			(1,100)
Interest expense (1)		14			–			–			14
Loss on derivatives		(13)			(1)			–			(14)
Other loss, net		(2)			(1)			–			(3)
Provision for income taxes (1)		1			–			–			1
Assets		5,538			1,220			1,760	(2)		8,518
Capital investments (3)		120			2			–			122

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

(2) Other assets represent corporate assets not allocated to segments and assets for non-reportable segments.  At March 31, 2017 and 2016, other assets includes approximately $1.4 billion and $1.6 billion in cash and cash equivalents, respectively.

(3) Capital investments includes decreases of $52 million and $78 million for the three months ended March 31, 2017 and 2016, respectively, relating to the change in accrued expenditures between periods.

(4) Operating income (loss) for the E&P segment includes $61 million related to restructuring charges for the three months ended March 31, 2016.

(5) Operating income (loss) for the Midstream segment includes $3 million related to restructuring charges for the three months ended March 31, 2016.

Included in intersegment revenues of the Midstream Services segment are $524 million and $319 million for the three months ended March 31, 2017 and 2016, respectively, for marketing of the Company’s E&P sales. Corporate assets include cash and cash equivalents, furniture and fixtures and other costs. Corporate general and administrative costs, depreciation expense and taxes other than income are allocated to the segments.

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Income Taxes

3 Months Ended

Mar. 31, 2017

Income Taxes [Abstract]

Income Taxes

(14)  INCOME TAXES

The Company’s effective tax rate was approximately 0% for the three months ended March 31, 2017 and 2016, primarily as a result of the recognition of a valuation allowance.  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.  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.

The Company maintained its net deferred tax asset position at March 31, 2017 primarily due to the write-downs of the carrying value of natural gas and oil propertiesin 2015 and 2016.  The Company recorded a $75  million decrease in our valuation allowance for the three months ended March 31, 2017 and  a$431 millionincrease in our valuation allowance for the three months ended March 31, 2016.  Management assesses the available positive and negative evidence to estimate whether sufficient future taxable income will be generated to permit the use of deferred tax assets.  In management’s view, the cumulative loss incurred over recent years outweighs any positive factors, such as the possibility of future growth.  The amount of the deferred tax asset considered realizable, however, could be adjusted if estimates of future taxable income are increased or if objective negative evidence in the form of cumulative losses is no longer present and additional weight is given to subjective evidence such as future expected growth.

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New Accounting Pronouncements

3 Months Ended

Mar. 31, 2017

New Accounting Pronouncements [Abstract]

New Accounting Pronouncements

(15)  NEW ACCOUNTING PRONOUNCEMENTS

New Accounting Standards Implemented

In March 2016, the FASB issued Accounting Standards Update No. 2016-09, Compensation – Stock Compensation (Topic 718) (“Update 2016-09”), to simplify accounting for share-based payment transactions including income tax consequences, classification of awards as either equity or liabilities, and the classification on the statement of cash flows.  For public entities, Update 2016-09 became effective for fiscal years beginning after December 15, 2016, including interim periods within those fiscal years, with early adoption permitted.  The Company adopted Update 2016-09 during the first quarter with an effective date of January 1, 2017.  The recognition of previously unrecognized windfall tax benefits resulted in a net cumulative-effect adjustment of $59 million, which increased net deferred tax assets and the relatedincome tax valuation allowance by the same amount as of the beginning of 2017.The amendments within Update 2016-09 related to the recognition of excess tax benefits and tax shortfalls in the income statement and presentation within the operating section of the statement of cash flows were adopted prospectively, with no adjustments made to prior periods.  The Company has elected to account for forfeitures as they occur.  The remaining provisions of this amendment did not have a material effect on itsunaudited condensed consolidated results of operations, financial position or cash flows.

New Accounting Standards Not Yet Implemented

In August 2016, the FASB issued Accounting Standards Update No. 2016-15, Statement of Cash Flows (Topic 230) (“Update 2016-15”), which seeks to reduce the existing diversity in practice in how certain cash receipts and cash payments are presented and classified in the statement of cash flows. For public entities, Update 2016-15 becomes effective for fiscal years beginning after December 15, 2017, including interim periods within those fiscal years, with early adoption permitted. The Company is currently evaluating the provisions of Update 2016-15 and assessing the impact, if any, it may have on its consolidated results of operations, financial position or cash flows.

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.  Through March 2017, the Company made progress on contract reviews, drafting its accounting policies and evaluating the new disclosure requirements.  The Company will continue assessing the effect that the updated standard may have on its consolidated financial statements and related disclosures, and anticipates that its assessment will be complete in 2018.  For public entities, Update 2016-02 becomes effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years, with early adoption permitted.

In May 2014, the FASB issued Accounting Standards Update No. 2014-09, Revenue from Contracts with Customers (Topic 606) (“Update 2014-09”), which seeks to provide clarity for recognizing revenue.  The new standard removes inconsistencies in existing standards, changes the way companies recognize revenue from contracts with customers and increases disclosure requirements.  The codification was amended through additional ASUs and, as amended, requires an entity to recognize revenue when it transfers promised goods or services to customers in an amount that reflects the consideration the entity expects to be entitled to in exchange for those goods or services.  The standard is required to be adopted using either the full retrospective approach, with all prior periods presented adjusted, or the modified retrospective approach, with a cumulative adjustment to retained earnings on the opening balance sheet.  The Company has not yet selected a transition method.  The Company has a team in place to analyze the impact of Update 2014-09, and the related ASU's, across all revenue streams to evaluate the impact of the new standard on revenue contracts.  This includes reviewing current accounting policies and practices to identify potential differences that would result from applying the requirements under the new standard.  Through March 2017, the Company made progress on contract reviews, drafting its accounting policies and evaluating the new disclosure requirements.  The Company expects to complete its evaluations of the impacts of the accounting and disclosure requirements on its business processes, controls and systems in the second half of 2017.  For public entities, the new standard is effective for annual reporting periods beginning after December 15, 2017, including interim periods within that reporting period.

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Cash And Cash Equivalents (Tables)

3 Months Ended

Mar. 31, 2017

Cash And Cash Equivalents [Abstract]

Summary Of Cash And Cash Equivalents

	March 31,		December 31,
	2017		2016
	(in millions)
Cash	$	265	$	254
Marketable securities (1)		1,117		1,169
Total cash and cash equivalents	$	1,382	$	1,423

(1) Consists ofgovernment stable value money market funds.

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Reduction In Workforce (Tables)

3 Months Ended

Mar. 31, 2017

Reduction In Workforce [Abstract]

Summary Of Restructuring Charges

	For the three months ended
	March 31, 2016
	(in millions)
Severance (including payroll taxes)	$	42
Stock-based compensation		18
Pension and other postretirement benefits		3
Outplacement services, other		1
Total restructuring charges (1)	$	64

(1) Total restructuring charges were $61 million and $3 million for the Company’s E&P and Midstream Services segments, respectively.

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Earnings Per Share (Tables)

3 Months Ended

Mar. 31, 2017

Earnings Per Share [Abstract]

Schedule Of Earnings Per Share

	For the three months ended March 31,
	2017		2016
	(in millions, except share/per share amounts)
Net income (loss)	$	351	$	(1,132)
Mandatory convertible preferred stock dividend		27		27
Participating securities - mandatory convertible preferred stock		43		–
Net income (loss) attributable to common stock	$	281	$	(1,159)
Number of common shares:
Weighted average outstanding		493,068,000		382,870,847
Issued upon assumed exercise of outstanding stock options		82,845		–
Effect of issuance of non-vested restricted common stock		770,429		–
Effect of issuance of non-vested performance units		573,721		–
Effect of issuance of mandatory convertible preferred stock		–		–
Weighted average and potential dilutive outstanding		494,494,995		382,870,847
Earnings (Loss) per common share:
Basic	$	0.57	$	(3.03)
Diluted	$	0.57	$	(3.03)

Schedule Of Antidilutive Securities Excluded From Computation Of Earnings Per Share

	For the three months ended March 31,
	2017	2016
Unvested stock options	1,854,004	5,732,521
Unvested share-based payment	1,212,396	5,779,820
Performance units	–	297,297
Mandatory convertible preferred stock	74,999,895	74,999,895
Total	78,066,295	86,809,533

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Derivatives And Risk Management (Tables)

3 Months Ended

Mar. 31, 2017

Derivatives And Risk Management [Abstract]

Schedule Of Derivative Instruments, Notional Amount In BCF, Weighted Average Contract Prices And Fair Value

		Weighted Average Price per MMBtu
	Volume (Bcf)	Swaps		Sold Puts		Purchased Puts		Sold Calls		Basis Differential		Fair value at March 31, 2017 (in millions)
Financial protection on production
2017
Fixed price swaps	262	$	3.07	$	–	$	–	$	–	$	–	$	(58)
Two-way costless-collars	65		–		–		2.92		3.34		–		(11)
Three-way costless-collars	102		–		2.29		2.97		3.30		–		(16)
Basis swaps	138		–		–		–		–		(1.04)		(73)
Total	567											$	(158)
2018
Fixed price swaps	68	$	3.02	$	–	$	–	$	–	$	–	$	(1)
Two-way costless-collars	23		–		–		2.97		3.56		–		(6)
Three-way costless-collars	245		–		2.39		2.97		3.37		–		(6)
Basis swaps	20		–		–		–		–		(0.95)		(15)
Total	356											$	(28)
2019
Three-way costless-collars	99	$	–	$	2.50	$	2.95	$	3.31	$	–	$	(2)
Total	99											$	(2)

		Weighted Average Price per MMBtu
	Volume (Bcf)	Sold Calls		Fair value at March 31, 2017 (in millions)
Call options
2017	64	$	3.54	$	(10)	(1)
2018	63		3.50		(14)
2019	52		3.50		(10)
2020	32		3.75		(5)
Total	211			$	(39)

(1) Excludes$5 million in premiums paid related to certain call options recognized as a component of derivative assets within current assets on the unaudited condensed consolidated balance sheet.  As certain call options settle, the premium will be amortized and recognized as a component of gain (loss) on derivatives on the unaudited condensed consolidated statement of operations.

Balance Sheet Classification Of Derivative Financial Instruments

	Derivative Assets
	Balance Sheet Classification		Fair Value
			March 31, 2017			December 31, 2016
		(in millions)
Derivatives not designated as hedging instruments:
Fixed price swaps	Derivative assets		$	2		$	–
Two-way costless collars	Derivative assets			11			8
Three-way costless collars	Derivative assets			23			11
Basis swaps	Derivative assets			2			32
Call options	Derivative assets			15			–
Fixed price swaps	Other long-term assets			7			1
Two-way costless collars	Other long-term assets			–			2
Three-way costless collars	Other long-term assets			120			100
Basis swaps	Other long-term assets			–			1
Total derivative assets			$	180	(1)	$	155
	Derivative Liabilities
	Balance Sheet Classification		Fair Value
			March 31, 2017			December 31, 2016
			(in millions)
Derivatives not designated as hedging instruments:
Fixed price swaps	Derivative liabilities		$	68		$	175
Two-way costless collars	Derivative liabilities			28			49
Three-way costless collars	Derivative liabilities			62			70
Basis swaps	Derivative liabilities			89			13
Call options	Derivative liabilities			32			46
Interest rate swaps	Derivative liabilities			1			2
Fixed price swaps	Other long-term liabilities			–			3
Two-way costless collars	Other long-term liabilities			–			9
Three-way costless collars	Other long-term liabilities			105			122
Basis swaps	Other long-term liabilities			1			5
Call options	Other long-term liabilities			22			35
Interest rate swaps	Other long-term liabilities			1			1
Total derivative liabilities			$	409		$	530

(1) Does not include $5 million in premiums paid related to certain call options currently recognized as a component of derivative assets within current assets on the unaudited condensed consolidated balance sheet.  As certain call options settle, the premium will be amortized and recognized as a component of gain (loss) on derivatives on the unaudited condensed consolidated statement of operations.

Summary Of Before Tax Effect Of Fair Value Hedges Not Designated For Hedge Accounting

		Gain (Loss) on Derivatives, Unsettled
		Recognized in Earnings
	Consolidated Statement of Operations	For the three months ended
	Classification of Gain (Loss)	March 31,
Derivative Instrument	on Derivatives, Unsettled	2017		2016
		(in millions)
Fixed price swaps	Gain (Loss) on Derivatives	$	118	$	20
Purchased put options	Gain (Loss) on Derivatives		–		15
Two-way costless-collars	Gain (Loss) on Derivatives		31		–
Three-way costless- collars	Gain (Loss) on Derivatives		57		–
Basis swaps	Gain (Loss) on Derivatives		(103)		(3)
Call options	Gain (Loss) on Derivatives		42		(50)
Interest rate swaps	Gain (Loss) on Derivatives		1		(3)
Total gain (loss) on unsettled derivatives		$	146	$	(21)
		Gain (Loss) on Derivatives, Settled (1)
		Recognized in Earnings
	Consolidated Statement of Operations	For the three months ended
	Classification of Gain (Loss)	March 31,
Derivative Instrument	on Derivatives, Settled	2017		2016
		(in millions)
Fixed price swaps	Gain (Loss) on Derivatives	$	(16)	$	4
Two-way costless-collars	Gain (Loss) on Derivatives		(3)		–
Three-way costless-collars	Gain (Loss) on Derivatives		(4)		–
Basis swaps	Gain (Loss) on Derivatives		(1)		4
Call options	Gain (Loss) on Derivatives		(6)		–
Interest rate swaps	Gain (Loss) on Derivatives		–		(1)
Total gain (loss) on settled derivatives (2)		$	(30)	$	7
Total gain (loss) on derivatives		$	116	$	(14)

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

(2) Excluding interest rate swaps, these amounts are included, along with gas sales revenues, in the calculation of the Company’s realized natural gas price.

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Reclassifications From Accumulated Other Comprehensive Income (Loss) (Tables)

3 Months Ended

Mar. 31, 2017

Reclassifications From Accumulated Other Comprehensive Income (Loss) [Abstract]

Components Of Accumulated Other Comprehensive Income (Loss)

	March 31, 2017
	Pension and Other Postretirement		Foreign Currency		Total
	(in millions)
Beginning balance, December 31, 2016	$	(19)	$	(20)	$	(39)
Other comprehensive income (loss) before reclassifications		–		–		–
Amounts reclassified from other comprehensive income (loss) (1)		–		–		–
Net current-period other comprehensive income (loss)		–		–		–
Ending balance, March 31, 2017	$	(19)	$	(20)	$	(39)

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

Amounts Reclassified From Accumulated Other Comprehensive Income (Loss)

Details about Accumulated Other Comprehensive Income	Affected Line Item in the Consolidated Statement of Operations	Amount Reclassified from Accumulated Other Comprehensive Income
		For the three months ended March 31, 2017
		(in millions)
Pension and other postretirement:
Amortization of prior service cost and net loss (1)	General and administrative expenses	$	1
	Provision for income taxes		1
	Net income (loss)	$	–
Total reclassifications for the period	Net income (loss)	$	–

(1)     See Note 11 for additional details regarding the Company’s retirement and employee benefit plans.

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Fair Value Measurements (Tables)

3 Months Ended

Mar. 31, 2017

Fair Value Measurements [Abstract]

Carrying Amount And Estimated Fair Values Of Financial Instruments

	March 31, 2017				December 31, 2016
	Carrying		Fair		Carrying		Fair
	Amount		Value		Amount		Value
	(in millions)
Cash and cash equivalents	$	1,382	$	1,382	$	1,423	$	1,423
Credit facility		–		–		–		–
Term loan facility due December 2020 (1)		327		327		327		327
Term loan facility due December 2020 (1)		1,191		1,191		1,191		1,191
Senior notes		3,141		3,088		3,166		3,182
Derivative instruments, net (2)		(229)		(229)		(375)		(375)

(1) The maturity date will accelerate to October 2019 if, by that date, the Company has not amended, redeemed or refinanced at least $765 million of its senior notes due in January 2020.

(2) Does not include $5 million in premiums paid related to certain call options currently recognized as a component of derivative assets within current assets on the unaudited condensed consolidated balance sheet.

Summary Of Assets And Liabilities Measured At Fair Value On Recurring Basis

	March 31, 2017
	Fair Value Measurements Using:
	Quoted Prices in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Assets (Liabilities) at Fair Value
Fixed price swap assets	$	–	$	9	$	–	$	9
Two-way costless collars assets		–		–		11		11
Three-way costless collars assets		–		–		143		143
Basis swap assets		–		–		2		2
Call option assets (1)		–		–		15		15
Fixed price swap liabilities		–		(68)		–		(68)
Two-way costless collars liabilities		–		–		(28)		(28)
Three-way costless collars liabilities		–		–		(167)		(167)
Basis swap liabilities		–		–		(90)		(90)
Call option liabilities		–		–		(54)		(54)
Interest rate swap liabilities		–		(2)		–		(2)
Total	$	–	$	(61)	$	(168)	$	(229)

(1) Does not include $5 million in premiums paid related to certain call options currently recognized as a component of derivative assets within current assets on the unaudited condensed consolidated balance sheet.

	December 31, 2016
	Fair Value Measurements Using:
	Quoted Prices in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Assets (Liabilities) at Fair Value
Fixed price swap assets	$	–	$	1	$	–	$	1
Two-way costless collars assets		–		–		10		10
Three-way costless collars assets		–		–		111		111
Basis swap assets		–		–		33		33
Fixed price swap liabilities		–		(178)		–		(178)
Two-way costless collars liabilities		–		–		(58)		(58)
Three-way costless collars liabilities		–		–		(192)		(192)
Basis swap liabilities		–		–		(18)		(18)
Call option liabilities		–		–		(81)		(81)
Interest rate swap liabilities		–		(3)		–		(3)
Total	$	–	$	(180)	$	(195)	$	(375)

Reconciliations For 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 months ended
	March 31,
	2017		2016
	(in millions)
Balance at beginning of period	$	(195)	$	3
Total gains (losses):
Included in earnings		13		(34)
Settlements		14		(4)
Transfers into/out of Level 3		–		–
Balance at end of period	$	(168)	$	(35)
Change in gains (losses) included in earnings relating to derivatives still held as of March 31	$	27	$	(38)

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Debt (Tables)

3 Months Ended

Mar. 31, 2017

Debt [Abstract]

Components Of Debt

	March 31, 2017
	Debt Instrument		Unamortized Issuance Expense		Unamortized Debt Discount		Total
		(in millions)
Short-term debt:
7.35% Senior Notes due October 2017	$	15	$	–	$	–	$	15
7.125% Senior Notes due October 2017		25		–		–		25
3.30% Senior Notes due January 2018 (1)		38		–		–		38
7.50% Senior Notes due February 2018 (2)		187		–		–		187
7.15% Senior Notes due June 2018		1		–		–		1
Total short-term debt	$	266	$	–	$	–	$	266
Long-term debt:
Variable rate (3.450% at March 31, 2017) term loan facility, due December 2020(3)		327		(2)		–		325
Variable rate (3.450% at March 31, 2017) term loan facility, due December 2020(3)		1,191		(10)		–		1,181
7.15% Senior Notes due June 2018		25		–		–		25
4.05% Senior Notes due January 2020(1)		850		(4)		–		846
4.10% Senior Notes due March 2022		1,000		(4)		(1)		995
4.95% Senior Notes due January 2025(1)		1,000		(6)		(2)		992
Total long-term debt	$	4,393	$	(26)	$	(3)	$	4,364
Total debt	$	4,659	$	(26)	$	(3)	$	4,630

	December 31, 2016
	Debt Instrument		Unamortized Issuance Expense		Unamortized Debt Discount		Total
		(in millions)
Short-term debt:
7.35% Senior Notes due October 2017	$	15	$	–	$	–	$	15
7.125% Senior Notes due October 2017		25		–		–		25
7.15% Senior Notes due June 2018		1		–		–		1
Total short-term debt	$	41	$	–	$	–	$	41
Long-term debt:
Variable rate (3.220% at December 31, 2016) term loan facility, due December 2020 (3)		327		(2)		–		325
Variable rate (3.220% at December 31, 2016) term loan facility, due December 2020 (3)		1,191		(10)		–		1,181
3.30% Senior Notes due January 2018(1)		38		–		–		38
7.50% Senior Notes due February 2018		212		–		–		212
7.15% Senior Notes due June 2018		25		–		–		25
4.05% Senior Notes due January 2020 (1)		850		(5)		–		845
4.10% Senior Notes due March 2022		1,000		(4)		(1)		995
4.95% Senior Notes due January 2025 (1)		1,000		(7)		(2)		991
Total long-term debt	$	4,643	$	(28)	$	(3)	$	4,612
Total debt	$	4,684	$	(28)	$	(3)	$	4,653

(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 5.05% for the 2018 Notes, 5.80% for the 2020 Notes and 6.70% for the 2025 Notes.

(2) In March 2017, the Company repurchased$25 million of its 7.50% Senior Notes due February 2018 andrecognized a  $1 million loss on the extinguishment of debt.

(3) The maturity date will accelerate to October 2019 if, by that date, the Company has not amended, redeemed or refinanced at least $765 million of its senior notes due in January 2020.

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Commitments And Contingencies (Tables)

3 Months Ended

Mar. 31, 2017

Commitments And Contingencies [Abstract]

Schedule Of Future Obligation Under Transportation Agreements

	Payments Due by Period
	Total		Less than 1 Year		1 to 3 Years		3 to 5 Years		5 to 8 Years		More than 8 Years
		(in millions)
Infrastructure currently in service	$	5,011	$	592	$	1,139	$	791	$	832	$	1,657
Pending regulatory approval and/or construction (1)		3,661		35		371		474		730		2,051
Total transportation charges	$	8,672	$	627	$	1,510	$	1,265	$	1,562	$	3,708

(1) Based on the estimated in-service dates as of March  31, 2017.

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Pension Plan And Other Postretirement Benefits (Tables)

3 Months Ended

Mar. 31, 2017

Pension Plan And Other Postretirement Benefits [Abstract]

Pension And Other Postretirement Benefit Costs

	Pension Benefits
	For the three months ended
	March 31,
	2017		2016
	(in millions)
Service cost	$	2	$	4
Interest cost		1		2
Expected return on plan assets		(1)		(2)
Amortization of prior service cost		–		–
Amortization of net loss		1		–
Net periodic benefit cost	$	3	$	4

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Stock-Based Compensation (Tables)

3 Months Ended

Mar. 31, 2017

Stock-Based Compensation [Abstract]

Schedule Of Stock-Based Compensation Costs

	For the three months ended
	March 31,
	2017		2016
	(in millions)
Stock-based compensation cost – expensed (1)	$	6	$	23
Stock-based compensation cost – capitalized	$	4	$	3

(1) Includes $18 million related to the reduction in workforce for the three months ended March 31, 2016.

Summary Of Stock Option Activity

	Number		Weighted Average
	of Options		Exercise Price
	(in thousands)		(per share)
Outstanding at December 31, 2016		5,416	$	23.46
Granted		1,322		8.59
Exercised		–		–
Forfeited or expired		(17)		45.57
Outstanding at March 31, 2017		6,721		20.48
Exercisable at March 31, 2017		3,537	$	29.34

Summary Of Restricted Stock Activity

	Number		Weighted Average
	of Shares		Fair Value
	(in thousands)		(per share)
Unvested shares at December 31, 2016		3,321	$	11.85
Granted		4,549		8.59
Vested		(70)		13.45
Forfeited		(113)		10.05
Unvested shares at March 31, 2017		7,687	$	9.93

Summary Of Performance Unit Activity

	Number		Weighted Average
	of Units (1)		Fair Value
	(in thousands)		(per share)
Unvested units at December 31, 2016		719	$	11.46
Granted		1,197		10.47
Vested		–		–
Forfeited		–		–
Unvested units at March 31, 2017		1,916	$	10.84

(1) These amounts reflect the number of performance units granted in thousands.  The actual payout of shares may range from a minimum of zero shares to a maximum of two shares contingent upon the actual performance against the Performance Measures. 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.

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Segment Information (Tables)

3 Months Ended

Mar. 31, 2017

Segment Information [Abstract]

Summary Financial Information For Company's Reportable Segments

	Exploration and Production			Midstream Services			Other			Total
	(in millions)
Three months ended March 31, 2017:
Revenues from external customers	$	566		$	280		$	–		$	846
Intersegment revenues		(3)			578			–			575
Depreciation, depletion and amortization expense		90			16			–			106
Operating income		225			41			–			266
Interest expense (1)		32			–			–			32
Gain on derivatives		116			–			–			116
Loss on early extinguishment of debt		–			–			(1)			(1)
Other income, net		2			–			–			2
Assets		4,413			1,268			1,515	(2)		7,196
Capital investments (3)		283			6			1			290
Three months ended March 31, 2016:
Revenues from external customers	$	343		$	236		$	–		$	579
Intersegment revenues		(7)			385			–			378
Depreciation, depletion and amortization expense		127			16			–			143
Impairment of natural gas and oil properties		1,034			–			–			1,034
Operating income (loss)		(1,160)	(4)		60	(5)		–			(1,100)
Interest expense (1)		14			–			–			14
Loss on derivatives		(13)			(1)			–			(14)
Other loss, net		(2)			(1)			–			(3)
Provision for income taxes (1)		1			–			–			1
Assets		5,538			1,220			1,760	(2)		8,518
Capital investments (3)		120			2			–			122

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

(2) Other assets represent corporate assets not allocated to segments and assets for non-reportable segments.  At March 31, 2017 and 2016, other assets includes approximately $1.4 billion and $1.6 billion in cash and cash equivalents, respectively.

(3) Capital investments includes decreases of $52 million and $78 million for the three months ended March 31, 2017 and 2016, respectively, relating to the change in accrued expenditures between periods.

(4) Operating income (loss) for the E&P segment includes $61 million related to restructuring charges for the three months ended March 31, 2016.

(5) Operating income (loss) for the Midstream segment includes $3 million related to restructuring charges for the three months ended March 31, 2016.

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Basis Of Presentation (Narrative) (Details)	3 Months Ended
	Mar. 31, 2017 segment
Basis Of Presentation [Abstract]
Number of segments	2

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Cash And Cash Equivalents (Summary Of Cash And Cash Equivalents) (Details) - USD ($) $ in Millions	Mar. 31, 2017	Dec. 31, 2016	Mar. 31, 2016	Dec. 31, 2015
Cash And Cash Equivalents [Abstract]
Cash	$ 265	$ 254
Marketable securities	1,117	1,169
Total	$ 1,382	$ 1,423	$ 1,597	$ 15

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Reduction In Workforce (Narrative) (Details)	1 Months Ended
	Jan. 31, 2016
Workforce Reduction [Member]
Restructuring Cost and Reserve [Line Items]
Positions eliminated, percent	40.00%

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Reduction In Workforce (Summary Of Restructuring Charges) (Details) $ in Millions	3 Months Ended
	Mar. 31, 2016 USD ($)
Restructuring Cost and Reserve [Line Items]
Total restructuring charges	$ 64
Exploration and Production [Member]
Restructuring Cost and Reserve [Line Items]
Total restructuring charges	61
Midstream Services [Member]
Restructuring Cost and Reserve [Line Items]
Total restructuring charges	3
Workforce Reduction [Member]
Restructuring Cost and Reserve [Line Items]
Severance (including payroll taxes)	42
Stock-based compensation	18
Pension and other postretirement benefits	3
Outplacement services, other	1
Total restructuring charges	64
Workforce Reduction [Member] | Exploration and Production [Member]
Restructuring Cost and Reserve [Line Items]
Total restructuring charges	61
Workforce Reduction [Member] | Midstream Services [Member]
Restructuring Cost and Reserve [Line Items]
Total restructuring charges	$ 3

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Natural Gas And Oil Properties (Narrative) (Details) $ in Millions	3 Months Ended
	Mar. 31, 2017 $ / bbl $ / MMBTU	Mar. 31, 2016 USD ($) $ / bbl $ / MMBTU
Natural Gas and Oil Properties [Line Items]
Natural gas, oil and NGL reserves discount	10.00%
Period of time needed to calculate ceiling value of reserves	12 months	12 months
Impairment of natural gas and oil properties, net of tax | $		$ 641
Natural Gas [Member] | Henry Hub [Member]
Natural Gas and Oil Properties [Line Items]
Full cost ceiling test, price | $ / MMBTU	2.73	2.40
Oil [Member] | West Texas Intermediate [Member]
Natural Gas and Oil Properties [Line Items]
Full cost ceiling test, price	44.10	42.77
NGL [Member]
Natural Gas and Oil Properties [Line Items]
Full cost ceiling test, price	10.17	5.76

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Earnings Per Share (Narrative) (Details) - USD ($) $ / shares in Units, $ in Millions		1 Months Ended	3 Months Ended
	Apr. 17, 2017	Jul. 31, 2016	Mar. 31, 2017	Dec. 31, 2016
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
Debt instrument			$ 4,659	$ 4,684
Common stock, date dividend to be paid			Apr. 17, 2017
Common Stock [Member]
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
Shares issued		98,900,000
Price per share		$ 13.00
Proceeds from issuance of shares		$ 1,247
Series B Preferred Stock [Member]
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
Liquidation preference per share			$ 1,000	$ 1,000
Trading day period			20 days
Long-term Debt [Member]
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
Debt instrument			$ 4,393	$ 4,643
Long-term Debt [Member] | 2015 Term Facility [Member]
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
Payments on long-term debt		375
Debt instrument			$ 750
Senior Notes [Member]
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
Purchase of note principal		$ 700
Minimum [Member] | Depositary Shares [Member]
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
Shares issued upon conversion			1.85014
Minimum [Member] | Series B Preferred Stock [Member]
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
Shares issued upon conversion			37.0028
Potential number of shares issued upon conversion			63,829,830
Maximum [Member] | Depositary Shares [Member]
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
Shares issued upon conversion			2.17391
Maximum [Member] | Series B Preferred Stock [Member]
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
Shares issued upon conversion			43.4782
Potential number of shares issued upon conversion			74,999,895
Subsequent Event [Member]
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
Common stock, shares issued as stock dividend	3,346,865

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Earnings Per Share (Schedule Of Earnings Per Share) (Details) - USD ($) $ / shares in Units, $ in Millions	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016
Earnings Per Share [Abstract]
Net income (loss)	$ 351	$ (1,132)
Mandatory convertible preferred stock dividend	27	27
Participating securities - mandatory convertible preferred stock	43
Net Income (Loss) Attributable to Common Stock	$ 281	$ (1,159)
Number of common shares: Weighted average outstanding	493,068,000	382,870,847
Number of common shares: Issued upon assumed exercise of outstanding stock options	82,845
Number of common shares: Effect of issuance of non-vested restricted common stock	770,429
Number of common shares: Effect of issuance of non-vested performance units	573,721
Number of common shares: Effect of issuance of mandatory convertible preferred stock
Number of common shares: Weighted average and potential dilutive outstanding	494,494,995	382,870,847
Basic	$ 0.57	$ (3.03)
Diluted	$ 0.57	$ (3.03)

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Earnings Per Share (Schedule Of Antidilutive Securities Excluded From Computation Of Earnings Per Share) (Details) - shares	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Antidilutive securities excluded from computation of earnings per share, shares	78,066,295	86,809,533
Stock Options [Member]
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Antidilutive securities excluded from computation of earnings per share, shares	1,854,004	5,732,521
Unvested Share-Based Payment [Member]
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Antidilutive securities excluded from computation of earnings per share, shares	1,212,396	5,779,820
Performance Units [Member]
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Antidilutive securities excluded from computation of earnings per share, shares		297,297
Mandatory Convertible Preferred Stock [Member]
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Antidilutive securities excluded from computation of earnings per share, shares	74,999,895	74,999,895

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Derivatives And Risk Management (Narrative) (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2017	Dec. 31, 2016
Interest Rate Swaps [Member]
Derivative [Line Items]
Derivative liabilities	$ 2	$ 3
Not Designated as Hedging Instrument [Member] | Interest Rate Swaps [Member]
Derivative [Line Items]
Derivative liabilities	2
Notional amount	$ 170
Derivative, expiration	Jun. 30, 2020
Natural Gas [Member] | Not Designated as Hedging Instrument [Member]
Derivative [Line Items]
Derivative liabilities	$ 227

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Derivatives And Risk Management (Schedule Of Derivative Instruments, Notional Amount In BCF, Weighted Average Contract Prices And Fair Value) (Details) - Not Designated as Hedging Instrument [Member] $ in Millions, ft³ in Billions	3 Months Ended
	Mar. 31, 2017 USD ($) $ / MMBTU ft³
Fixed Price Swaps - 2017 [Member]
Derivative [Line Items]
Volume (Bcf) | ft³	262
Average price per MMBtu	3.07
Fair value | $	$ (58)
Two-way Costless-collars - 2017 [Member]
Derivative [Line Items]
Volume (Bcf) | ft³	65
Fair value | $	$ (11)
Two-way Costless-collars - 2017 Purchased Puts [Member]
Derivative [Line Items]
Floor price per MMBtu	2.92
Two-way Costless-collars - 2017 Sold Calls [Member]
Derivative [Line Items]
Cap price per MMBtu	3.34
Three-way Costless-collars - 2017 [Member]
Derivative [Line Items]
Volume (Bcf) | ft³	102
Fair value | $	$ (16)
Three-way Costless-collars - 2017 Sold Puts [Member]
Derivative [Line Items]
Floor price per MMBtu	2.29
Three-way Costless-collars - 2017 Purchased Puts [Member]
Derivative [Line Items]
Floor price per MMBtu	2.97
Three-way Costless-collars - 2017 Sold Calls [Member]
Derivative [Line Items]
Cap price per MMBtu	3.30
Basis Swaps - 2017 [Member]
Derivative [Line Items]
Volume (Bcf) | ft³	138
Basis differential per MMBtu	(1.04)
Fair value | $	$ (73)
Financial protection on production - 2017 [Member]
Derivative [Line Items]
Volume (Bcf) | ft³	567
Fair value | $	$ (158)
Fixed Price Swaps - 2018 [Member]
Derivative [Line Items]
Volume (Bcf) | ft³	68
Average price per MMBtu	3.02
Fair value | $	$ (1)
Two-way Costless-collars - 2018 [Member]
Derivative [Line Items]
Volume (Bcf) | ft³	23
Fair value | $	$ (6)
Two-way Costless-collars - 2018 Purchased Puts [Member]
Derivative [Line Items]
Floor price per MMBtu	2.97
Two-way Costless-collars - 2018 Sold Calls [Member]
Derivative [Line Items]
Cap price per MMBtu	3.56
Three-way Costless-collars - 2018 [Member]
Derivative [Line Items]
Volume (Bcf) | ft³	245
Fair value | $	$ (6)
Three-way Costless-collars - 2018 Sold Puts [Member]
Derivative [Line Items]
Floor price per MMBtu	2.39
Three-way Costless-collars - 2018 Purchased Puts [Member]
Derivative [Line Items]
Floor price per MMBtu	2.97
Three-way Costless-collars - 2018 Sold Calls [Member]
Derivative [Line Items]
Cap price per MMBtu	3.37
Basis Swaps - 2018 [Member]
Derivative [Line Items]
Volume (Bcf) | ft³	20
Basis differential per MMBtu	(0.95)
Fair value | $	$ (15)
Financial protection on production - 2018 [Member]
Derivative [Line Items]
Volume (Bcf) | ft³	356
Fair value | $	$ (28)
Three-way Costless-collars - 2019 [Member]
Derivative [Line Items]
Volume (Bcf) | ft³	99
Fair value | $	$ (2)
Three-way Costless-collars - 2019 Sold Puts [Member]
Derivative [Line Items]
Floor price per MMBtu	2.50
Three-way Costless-collars - 2019 Purchased Puts [Member]
Derivative [Line Items]
Floor price per MMBtu	2.95
Three-way Costless-collars - 2019 Sold Calls [Member]
Derivative [Line Items]
Cap price per MMBtu	3.31
Financial protection on production - 2019 [Member]
Derivative [Line Items]
Volume (Bcf) | ft³	99
Fair value | $	$ (2)
Sold Call Options - 2017 [Member]
Derivative [Line Items]
Volume (Bcf) | ft³	64
Floor price per MMBtu	3.54
Fair value | $	$ (10)
Premium paid | $	$ 5
Sold Call Options - 2018 [Member]
Derivative [Line Items]
Volume (Bcf) | ft³	63
Floor price per MMBtu	3.50
Fair value | $	$ (14)
Sold Call Options - 2019 [Member]
Derivative [Line Items]
Volume (Bcf) | ft³	52
Floor price per MMBtu	3.50
Fair value | $	$ (10)
Sold Call Options - 2020 [Member]
Derivative [Line Items]
Volume (Bcf) | ft³	32
Floor price per MMBtu	3.75
Fair value | $	$ (5)
Sold Call Options [Member]
Derivative [Line Items]
Volume (Bcf) | ft³	211
Fair value | $	$ (39)

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Derivatives And Risk Management (Balance Sheet Classification Of Derivative Financial Instruments) (Details) - Not Designated as Hedging Instrument [Member] - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2017	Dec. 31, 2016
Derivatives, Fair Value [Line Items]
Derivative assets	$ 180	$ 155
Derivative liabilities	409	530
Fixed Price Swaps [Member] | Derivative Assets [Member]
Derivatives, Fair Value [Line Items]
Derivative assets	2
Fixed Price Swaps [Member] | Other Long-Term Assets [Member]
Derivatives, Fair Value [Line Items]
Derivative assets	7	1
Fixed Price Swaps [Member] | Derivative Liabilities [Member]
Derivatives, Fair Value [Line Items]
Derivative liabilities	68	175
Fixed Price Swaps [Member] | Other Long-Term Liabilities [Member]
Derivatives, Fair Value [Line Items]
Derivative liabilities		3
Two-way Costless-collars [Member] | Derivative Assets [Member]
Derivatives, Fair Value [Line Items]
Derivative assets	11	8
Two-way Costless-collars [Member] | Other Long-Term Assets [Member]
Derivatives, Fair Value [Line Items]
Derivative assets		2
Two-way Costless-collars [Member] | Derivative Liabilities [Member]
Derivatives, Fair Value [Line Items]
Derivative liabilities	28	49
Two-way Costless-collars [Member] | Other Long-Term Liabilities [Member]
Derivatives, Fair Value [Line Items]
Derivative liabilities		9
Three-way Costless-collars [Member] | Derivative Assets [Member]
Derivatives, Fair Value [Line Items]
Derivative assets	23	11
Three-way Costless-collars [Member] | Other Long-Term Assets [Member]
Derivatives, Fair Value [Line Items]
Derivative assets	120	100
Three-way Costless-collars [Member] | Derivative Liabilities [Member]
Derivatives, Fair Value [Line Items]
Derivative liabilities	62	70
Three-way Costless-collars [Member] | Other Long-Term Liabilities [Member]
Derivatives, Fair Value [Line Items]
Derivative liabilities	105	122
Basis Swaps [Member] | Derivative Assets [Member]
Derivatives, Fair Value [Line Items]
Derivative assets	2	32
Basis Swaps [Member] | Other Long-Term Assets [Member]
Derivatives, Fair Value [Line Items]
Derivative assets		1
Basis Swaps [Member] | Derivative Liabilities [Member]
Derivatives, Fair Value [Line Items]
Derivative liabilities	89	13
Basis Swaps [Member] | Other Long-Term Liabilities [Member]
Derivatives, Fair Value [Line Items]
Derivative liabilities	1	5
Sold Call Options [Member] | Derivative Assets [Member]
Derivatives, Fair Value [Line Items]
Derivative assets	15
Sold Call Options [Member] | Derivative Liabilities [Member]
Derivatives, Fair Value [Line Items]
Derivative liabilities	32	46
Sold Call Options [Member] | Other Long-Term Liabilities [Member]
Derivatives, Fair Value [Line Items]
Derivative liabilities	22	35
Interest Rate Swaps [Member] | Derivative Liabilities [Member]
Derivatives, Fair Value [Line Items]
Derivative liabilities	1	2
Interest Rate Swaps [Member] | Other Long-Term Liabilities [Member]
Derivatives, Fair Value [Line Items]
Derivative liabilities	1	$ 1
Sold Call Options - 2017 [Member]
Derivatives, Fair Value [Line Items]
Premium paid	$ 5

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Derivatives And Risk Management (Summary Of Before Tax Effect Of Fair Value Hedges Not Designated For Hedge Accounting) (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016
Derivative Instruments, Gain (Loss) [Line Items]
Derivative Instrument, Gain (Loss) on Derivatives, Unsettled	$ 146	$ (21)
Derivative Instrument, Gain (Loss) on Derivatives, Settled	(30)	7
Total gain (loss) on derivatives	116	(14)
Fixed Price Swaps [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative Instrument, Gain (Loss) on Derivatives, Unsettled	118	20
Derivative Instrument, Gain (Loss) on Derivatives, Settled	(16)	4
Purchased Put Options [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative Instrument, Gain (Loss) on Derivatives, Unsettled		15
Two-way Costless-collars [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative Instrument, Gain (Loss) on Derivatives, Unsettled	31
Derivative Instrument, Gain (Loss) on Derivatives, Settled	(3)
Three-way Costless-collars [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative Instrument, Gain (Loss) on Derivatives, Unsettled	57
Derivative Instrument, Gain (Loss) on Derivatives, Settled	(4)
Basis Swaps [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative Instrument, Gain (Loss) on Derivatives, Unsettled	(103)	(3)
Derivative Instrument, Gain (Loss) on Derivatives, Settled	(1)	4
Sold Call Options [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative Instrument, Gain (Loss) on Derivatives, Unsettled	42	(50)
Derivative Instrument, Gain (Loss) on Derivatives, Settled	(6)
Interest Rate Swaps [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative Instrument, Gain (Loss) on Derivatives, Unsettled	$ 1	(3)
Derivative Instrument, Gain (Loss) on Derivatives, Settled		$ (1)

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Reclassifications From Accumulated Other Comprehensive Income (Loss) (Components Of Accumulated Other Comprehensive Income (Loss)) (Details) $ in Millions	3 Months Ended
	Mar. 31, 2017 USD ($)
Accumulated Other Comprehensive Income (Loss) [Line Items]
Beginning balance, December 31, 2016	$ (39)
Other comprehensive income (loss) before reclassifications
Amounts reclassified from other comprehensive income (loss)
Net current-period other comprehensive income (loss)
Ending balance, March 31, 2017	(39)
Pension And Other Postretirement [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Beginning balance, December 31, 2016	(19)
Other comprehensive income (loss) before reclassifications
Amounts reclassified from other comprehensive income (loss)
Net current-period other comprehensive income (loss)
Ending balance, March 31, 2017	(19)
Foreign Currency [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Beginning balance, December 31, 2016	(20)
Other comprehensive income (loss) before reclassifications
Amounts reclassified from other comprehensive income (loss)
Net current-period other comprehensive income (loss)
Ending balance, March 31, 2017	$ (20)

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Reclassifications From Accumulated Other Comprehensive Income (Loss) (Amounts Reclassified From Accumulated Other Comprehensive Income (Loss)) (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
General and administrative expenses	$ 50	$ 54
Provision for income taxes		1
Net Income (Loss)	351	$ (1,132)
Reclassification from Accumulated Other Comprehensive Income [Member]
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Net Income (Loss)
Pension And Other Postretirement [Member] | Reclassification from Accumulated Other Comprehensive Income [Member]
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
General and administrative expenses	1
Provision for income taxes	1
Net Income (Loss)

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Fair Value Measurements (Carrying Amount And Estimated Fair Values Of Financial Instruments) (Details) - USD ($) $ in Millions	3 Months Ended	6 Months Ended	12 Months Ended
	Mar. 31, 2017	Jun. 30, 2016	Dec. 31, 2016
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative instruments, net	$ (229)		$ (375)
Carrying Amount [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Cash and cash equivalents	1,382		1,423
Senior notes	3,141		3,166
Derivative instruments, net	(229)		(375)
Fair Value [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Cash and cash equivalents	1,382		1,423
Senior notes	3,088		3,182
Derivative instruments, net	$ (229)		$ (375)
Long-term Debt [Member] | Term Loan 1 due December 2020 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Maturity date, year and month	2020-12	2018-11	2020-12
Accelerated maturity date, year and month if not amended, redeemed or refinanced	2019-10
Long-term Debt [Member] | Term Loan 2 due December 2020 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Maturity date, year and month	2020-12		2020-12
Accelerated maturity date, year and month if not amended, redeemed or refinanced	2019-10
Long-term Debt [Member] | 2020 Senior Notes [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Maturity date, year and month	2020-01		2020-01
Amount to be amended, redeemed or refinanced to avoid acceleration	$ 765		$ 765
Long-term Debt [Member] | Carrying Amount [Member] | Term Loan 1 due December 2020 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Loans	327		327
Long-term Debt [Member] | Carrying Amount [Member] | Term Loan 2 due December 2020 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Loans	1,191		1,191
Long-term Debt [Member] | Fair Value [Member] | Term Loan 1 due December 2020 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Loans	327		327
Long-term Debt [Member] | Fair Value [Member] | Term Loan 2 due December 2020 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Loans	1,191		$ 1,191
Sold Call Options - 2017 [Member] | Not Designated as Hedging Instrument [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Premium paid	$ 5

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Fair Value Measurements (Summary Of Assets And Liabilities Measured At Fair Value On Recurring Basis) (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2017	Dec. 31, 2016
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total	$ (229)	$ (375)
Significant Other Observable Inputs (Level 2) [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total	(61)	(180)
Significant Unobservable Inputs (Level 3) [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total	(168)	(195)
Fixed Price Swaps [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	9	1
Derivative liabilities	(68)	(178)
Fixed Price Swaps [Member] | Significant Other Observable Inputs (Level 2) [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	9	1
Derivative liabilities	(68)	(178)
Two-way Costless-collars [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	11	10
Derivative liabilities	(28)	(58)
Two-way Costless-collars [Member] | Significant Unobservable Inputs (Level 3) [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	11	10
Derivative liabilities	(28)	(58)
Three-way Costless-collars [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	143	111
Derivative liabilities	(167)	(192)
Three-way Costless-collars [Member] | Significant Unobservable Inputs (Level 3) [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	143	111
Derivative liabilities	(167)	(192)
Basis Swaps [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	2	33
Derivative liabilities	(90)	(18)
Basis Swaps [Member] | Significant Unobservable Inputs (Level 3) [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	2	33
Derivative liabilities	(90)	(18)
Sold Call Options [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	15
Derivative liabilities	(54)	(81)
Sold Call Options [Member] | Significant Unobservable Inputs (Level 3) [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	15
Derivative liabilities	(54)	(81)
Interest Rate Swaps [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative liabilities	(2)	(3)
Interest Rate Swaps [Member] | Significant Other Observable Inputs (Level 2) [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative liabilities	(2)	$ (3)
Not Designated as Hedging Instrument [Member] | Interest Rate Swaps [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative liabilities	(2)
Not Designated as Hedging Instrument [Member] | Sold Call Options - 2017 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Premium paid	$ 5

XML

Fair Value Measurements (Reconciliations For Change In Net Fair Value Of Derivative Assets And Liabilities Measured At Fair Value On A Recurring Basis Using Significant Unobservable Inputs (Level 3)) (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016
Fair Value Measurements [Abstract]
Balance at beginning of period	$ (195)	$ 3
Included in earnings	13	(34)
Settlements	14	(4)
Balance at end of period	(168)	(35)
Change in gains (losses) included in earnings relating to derivatives still held as of March 31	$ 27	$ (38)

XML

Debt (2016 Credit Facility - Narrative) (Details)		1 Months Ended	3 Months Ended	12 Months Ended
	Apr. 01, 2016 USD ($)	Jun. 30, 2016 USD ($)	Mar. 31, 2017 USD ($)	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2016 USD ($)	Dec. 31, 2013 USD ($)
Debt Instrument [Line Items]
Debt instrument			$ 4,659,000,000			$ 4,684,000,000
Long-term Debt [Member]
Debt Instrument [Line Items]
Debt instrument			4,393,000,000			4,643,000,000
Long-term Debt [Member] | 2013 Credit Facility [Member]
Debt Instrument [Line Items]
Maximum borrowing capacity		$ 66,000,000					$ 2,000,000,000
Repayment of line of credit	$ 1,550,000,000	285,000,000
Amount outstanding			0
Long-term Debt [Member] | 2016 Credit Facility [Member]
Debt Instrument [Line Items]
Maximum borrowing capacity		743,000,000
Long-term Debt [Member] | 2013 & 2016 Credit Facilities [Member]
Debt Instrument [Line Items]
Amount outstanding			0
Long-term Debt [Member] | Letter of Credit [Member]
Debt Instrument [Line Items]
Amount outstanding			$ 327,000,000
Revolving Credit Facility And Term Loan Facility [Member] | Long-term Debt [Member]
Debt Instrument [Line Items]
Maximum borrowing capacity		$ 1,934,000,000
Maturity date, year and month		2020-12
Incremental increase EBITDAX to interest expense ratio			0.25
Revolving Credit Facility And Term Loan Facility [Member] | Long-term Debt [Member] | Minimum [Member]
Debt Instrument [Line Items]
EBITDAX to interest expense ratio			1.00
Liquidity requirement			$ 300,000,000
Anti-hoarding provision, required unrestricted cash			$ 100,000,000
Collateral coverage ratio			1.50
Revolving Credit Facility And Term Loan Facility [Member] | Long-term Debt [Member] | Minimum [Member] | Scenario, Forecast [Member]
Debt Instrument [Line Items]
EBITDAX to interest expense ratio				1.50	1.50
Revolving Credit Facility And Term Loan Facility [Member] | Long-term Debt [Member] | Maximum [Member]
Debt Instrument [Line Items]
Liquidity requirement			$ 500,000,000
Revolving Credit Facility And Term Loan Facility [Member] | Long-term Debt [Member] | Eurodollar [Member] | Minimum [Member]
Debt Instrument [Line Items]
Basis points			1.75%
Revolving Credit Facility And Term Loan Facility [Member] | Long-term Debt [Member] | Eurodollar [Member] | Maximum [Member]
Debt Instrument [Line Items]
Basis points			2.50%
Revolving Credit Facility And Term Loan Facility [Member] | Long-term Debt [Member] | Base Rate [Member] | Minimum [Member]
Debt Instrument [Line Items]
Basis points			0.75%
Revolving Credit Facility And Term Loan Facility [Member] | Long-term Debt [Member] | Base Rate [Member] | Maximum [Member]
Debt Instrument [Line Items]
Basis points			1.50%
Revolving Credit Facility And Term Loan Facility [Member] | Long-term Debt [Member] | Over LIBOR [Member]
Debt Instrument [Line Items]
Basis points			2.50%
Term Loan 2 due December 2020 [Member] | Long-term Debt [Member]
Debt Instrument [Line Items]
Debt instrument		$ 1,191,000,000	$ 1,191,000,000			$ 1,191,000,000
Maturity date, year and month			2020-12			2020-12
Accelerated maturity date, year and month if not amended, redeemed or refinanced			2019-10
2020 Senior Notes [Member] | Long-term Debt [Member]
Debt Instrument [Line Items]
Maturity date, year and month			2020-01			2020-01
Amount to be amended, redeemed or refinanced to avoid acceleration			$ 765,000,000			$ 765,000,000

XML

Debt (2013 Credit Facility - Narrative) (Details) - USD ($)			1 Months Ended	3 Months Ended
	Apr. 01, 2016	Mar. 30, 2016	Jun. 30, 2016	Mar. 31, 2017	Dec. 31, 2016	Dec. 31, 2013
Debt Instrument [Line Items]
Debt instrument				$ 4,659,000,000	$ 4,684,000,000
Adjusted debt capital structure, percentage				34.00%
Long-term Debt [Member]
Debt Instrument [Line Items]
Debt instrument				$ 4,393,000,000	4,643,000,000
Long-term Debt [Member] | 2013 Credit Facility [Member]
Debt Instrument [Line Items]
Maximum borrowing capacity			$ 66,000,000			$ 2,000,000,000
Line of credit, amount borrowed		$ 1,550,000,000
Repayment of line of credit	$ 1,550,000,000		285,000,000
Credit facility, maturity date				Dec. 01, 2018
Amount outstanding				$ 0
Debt percentage of adjusted book capital structure covenant				60.00%
Long-term Debt [Member] | 2016 Credit Facility [Member]
Debt Instrument [Line Items]
Maximum borrowing capacity			743,000,000
Term Loan 2 due December 2020 [Member] | Long-term Debt [Member]
Debt Instrument [Line Items]
Debt instrument			$ 1,191,000,000	$ 1,191,000,000	$ 1,191,000,000

XML

Debt (2015 Term Facility - Narrative) (Details) $ in Millions	1 Months Ended			3 Months Ended	6 Months Ended	12 Months Ended
	Sep. 30, 2016 USD ($) a	Jul. 31, 2016 USD ($)	Nov. 30, 2015 USD ($)	Mar. 31, 2017 USD ($)	Jun. 30, 2016	Dec. 31, 2016 USD ($)
Term Loan 1 due December 2020 [Member] | Long-term Debt [Member]
Debt Instrument [Line Items]
Loans payable			$ 750
Debt instrument, term			3 years
Payments on long-term debt		$ 375
Maturity date, year and month				2020-12	2018-11	2020-12
Accelerated maturity date, year and month if not amended, redeemed or refinanced				2019-10
2020 Senior Notes [Member] | Long-term Debt [Member]
Debt Instrument [Line Items]
Payments on long-term debt	$ 48
Maturity date, year and month				2020-01		2020-01
Amount to be amended, redeemed or refinanced to avoid acceleration				$ 765		$ 765
Over LIBOR [Member] | Term Loan 1 due December 2020 [Member] | Long-term Debt [Member]
Debt Instrument [Line Items]
Basis points				2.50%
West Virginia [Member]
Debt Instrument [Line Items]
Area of land sold | a	55,000

XML

Debt (Senior Notes - Narrative) (Details) - USD ($) $ in Millions	1 Months Ended		3 Months Ended
	Jul. 31, 2016	Jan. 31, 2015	Mar. 31, 2017	Dec. 31, 2016
Debt Instrument [Line Items]
Net loss on extinguishment of debt			$ (1)
Unamortized debt expense			26	$ 28
Long-term Debt [Member]
Debt Instrument [Line Items]
Unamortized debt expense			$ 26	$ 28
Senior Notes [Member]
Debt Instrument [Line Items]
Proceeds from issuance of debt		$ 2,200
Purchase of note principal	$ 700
Senior Notes [Member] | Over LIBOR [Member]
Debt Instrument [Line Items]
Incremental increase in basis points resulting from downgrades			0.25%
Incremental decrease in basis points resulting from upgrades			0.25%
Increase in basis spread	1.75%
3.30% Senior Notes due January 2018 [Member] | Long-term Debt [Member]
Debt Instrument [Line Items]
Senior notes		$ 350
Stated interest rate	5.05%	3.30%		3.30%
Maturity date, year		2018
Percentage of face amount, sold to public		99.949%
Unamortized debt expense
4.05% Senior Notes due January 2020 [Member] | Long-term Debt [Member]
Debt Instrument [Line Items]
Senior notes		$ 850
Stated interest rate	5.80%	4.05%	4.05%	4.05%
Maturity date, year		2020
Percentage of face amount, sold to public		99.897%
Unamortized debt expense			$ 4	$ 5
4.95% Senior Notes due January 2025 [Member] | Long-term Debt [Member]
Debt Instrument [Line Items]
Senior notes		$ 1,000
Stated interest rate	6.70%	4.95%	4.95%	4.95%
Maturity date, year		2025
Percentage of face amount, sold to public		99.782%
Unamortized debt expense			$ 6	$ 7
Maximum [Member] | 3.30% Senior Notes due January 2018 [Member] | Long-term Debt [Member]
Debt Instrument [Line Items]
Stated interest rate			5.30%
Maximum [Member] | 4.05% Senior Notes due January 2020 [Member] | Long-term Debt [Member]
Debt Instrument [Line Items]
Stated interest rate			6.05%
Maximum [Member] | 4.95% Senior Notes due January 2025 [Member] | Long-term Debt [Member]
Debt Instrument [Line Items]
Stated interest rate			6.95%

XML

Debt (Components Of Debt) (Details) - USD ($) $ in Millions	1 Months Ended			3 Months Ended	6 Months Ended	12 Months Ended
	Mar. 31, 2017	Sep. 30, 2016	Jul. 31, 2016	Mar. 31, 2017	Jun. 30, 2016	Dec. 31, 2016	Jan. 31, 2015
Debt Instrument [Line Items]
Debt Instrument	$ 4,659.0			$ 4,659.0		$ 4,684.0
Unamortized Issuance Cost	(26.0)			(26.0)		(28.0)
Unamortized Debt Discount	(3.0)			(3.0)		(3.0)
Total	4,630.0			4,630.0		4,653.0
Net loss on extinguishment of debt				(1.0)
Short-term Debt [Member]
Debt Instrument [Line Items]
Debt Instrument	266.0			266.0		41.0
Unamortized Issuance Cost
Unamortized Debt Discount
Total	266.0			266.0		41.0
Short-term Debt [Member] | 7.35% Senior Notes due October 2017 [Member]
Debt Instrument [Line Items]
Debt Instrument	15.0			15.0		15.0
Unamortized Issuance Cost
Unamortized Debt Discount
Total	$ 15.0			$ 15.0		$ 15.0
Stated interest rate	7.35%			7.35%		7.35%
Maturity date, year and month				2017-10		2017-10
Short-term Debt [Member] | 7.125% Senior Notes due October 2017 [Member]
Debt Instrument [Line Items]
Debt Instrument	$ 25.0			$ 25.0		$ 25.0
Unamortized Issuance Cost
Unamortized Debt Discount
Total	$ 25.0			$ 25.0		$ 25.0
Stated interest rate	7.125%			7.125%		7.125%
Maturity date, year and month				2017-10		2017-10
Short-term Debt [Member] | 3.30% Senior Notes due January 2018 [Member]
Debt Instrument [Line Items]
Debt Instrument	$ 38.0			$ 38.0
Total	$ 38.0			$ 38.0
Stated interest rate	3.30%			3.30%
Maturity date, year and month				2018-01
Short-term Debt [Member] | 7.50% Senior Notes due February 2018 [Member]
Debt Instrument [Line Items]
Debt Instrument	$ 187.0			$ 187.0
Total	$ 187.0			$ 187.0
Stated interest rate	7.50%			7.50%
Maturity date, year and month				2018-02
Short-term Debt [Member] | 7.15% Senior Notes due June 2018 [Member]
Debt Instrument [Line Items]
Debt Instrument	$ 1.0			$ 1.0		$ 1.0
Unamortized Issuance Cost
Unamortized Debt Discount
Total	$ 1.0			$ 1.0		$ 1.0
Stated interest rate	7.15%			7.15%		7.15%
Maturity date, year and month				2018-06		2018-06
Long-term Debt [Member]
Debt Instrument [Line Items]
Debt Instrument	$ 4,393.0			$ 4,393.0		$ 4,643.0
Unamortized Issuance Cost	(26.0)			(26.0)		(28.0)
Unamortized Debt Discount	(3.0)			(3.0)		(3.0)
Total	4,364.0			4,364.0		4,612.0
Long-term Debt [Member] | Term Loan 1 due December 2020 [Member]
Debt Instrument [Line Items]
Debt Instrument	327.0			327.0		327.0
Unamortized Issuance Cost	(2.0)			(2.0)		(2.0)
Unamortized Debt Discount
Total	325.0			$ 325.0		$ 325.0
Variable interest rate				3.45%		3.22%
Maturity date, year and month				2020-12	2018-11	2020-12
Payments on long-term debt			$ 375.0
Accelerated maturity date, year and month if not amended, redeemed or refinanced				2019-10
Long-term Debt [Member] | Term Loan 2 due December 2020 [Member]
Debt Instrument [Line Items]
Debt Instrument	1,191.0			$ 1,191.0	$ 1,191.0	$ 1,191.0
Unamortized Issuance Cost	(10.0)			(10.0)		(10.0)
Unamortized Debt Discount
Total	1,181.0			$ 1,181.0		$ 1,181.0
Variable interest rate				3.45%		3.22%
Maturity date, year and month				2020-12		2020-12
Accelerated maturity date, year and month if not amended, redeemed or refinanced				2019-10
Long-term Debt [Member] | 3.30% Senior Notes due January 2018 [Member]
Debt Instrument [Line Items]
Debt Instrument						$ 38.0
Unamortized Issuance Cost
Unamortized Debt Discount
Total						$ 38.0
Stated interest rate			5.05%			3.30%	3.30%
Maturity date, year and month						2018-01
Long-term Debt [Member] | 7.50% Senior Notes due February 2018 [Member]
Debt Instrument [Line Items]
Debt Instrument						$ 212.0
Unamortized Issuance Cost
Unamortized Debt Discount
Total						$ 212.0
Stated interest rate						7.50%
Maturity date, year and month						2018-02
Debt repurchased	25.0			$ 25.0
Net loss on extinguishment of debt	(1.0)
Long-term Debt [Member] | 7.15% Senior Notes due June 2018 [Member]
Debt Instrument [Line Items]
Debt Instrument	25.0			25.0		$ 25.0
Unamortized Issuance Cost
Unamortized Debt Discount
Total	$ 25.0			$ 25.0		$ 25.0
Stated interest rate	7.15%			7.15%		7.15%
Maturity date, year and month				2018-06		2018-06
Long-term Debt [Member] | 4.05% Senior Notes due January 2020 [Member]
Debt Instrument [Line Items]
Debt Instrument	$ 850.0			$ 850.0		$ 850.0
Unamortized Issuance Cost	(4.0)			(4.0)		(5.0)
Unamortized Debt Discount
Total	$ 846.0			$ 846.0		$ 845.0
Stated interest rate	4.05%		5.80%	4.05%		4.05%	4.05%
Maturity date, year and month				2020-01		2020-01
Long-term Debt [Member] | 4.10% Senior Notes due March 2022 [Member]
Debt Instrument [Line Items]
Debt Instrument	$ 1,000.0			$ 1,000.0		$ 1,000.0
Unamortized Issuance Cost	(4.0)			(4.0)		(4.0)
Unamortized Debt Discount	(1.0)			(1.0)		(1.0)
Total	$ 995.0			$ 995.0		$ 995.0
Stated interest rate	4.10%			4.10%		4.10%
Maturity date, year and month				2022-03		2022-03
Long-term Debt [Member] | 4.95% Senior Notes due January 2025 [Member]
Debt Instrument [Line Items]
Debt Instrument	$ 1,000.0			$ 1,000.0		$ 1,000.0
Unamortized Issuance Cost	(6.0)			(6.0)		(7.0)
Unamortized Debt Discount	(2.0)			(2.0)		(2.0)
Total	$ 992.0			$ 992.0		$ 991.0
Stated interest rate	4.95%		6.70%	4.95%		4.95%	4.95%
Maturity date, year and month				2025-01		2025-01
Long-term Debt [Member] | 2020 Senior Notes [Member]
Debt Instrument [Line Items]
Maturity date, year and month				2020-01		2020-01
Payments on long-term debt		$ 48.0
Amount to be amended, redeemed or refinanced to avoid acceleration				$ 765.0		$ 765.0
Over LIBOR [Member] | Senior Notes [Member]
Debt Instrument [Line Items]
Increase in basis spread			1.75%

XML

Commitments And Contingencies (Narrative) (Details)	1 Months Ended	3 Months Ended
	Sep. 30, 2015 plaintiff item	Mar. 31, 2017 USD ($) item
Commitments And Contingencies [Line Items]
Obligation under transportation agreements | $		$ 8,672,000,000
Guarantee obligations relative to the firms transportation agreements and gathering project and services | $		$ 821,000,000
Number of state cases set for trial		1
Indemnification liability | $		$ 0
Arkansas Royalty Litigation [Member]
Commitments And Contingencies [Line Items]
Number of cases		3
Arkansas Royalty Litigation [Member] | Arkansas State Court 2010 and 2013 [Member]
Commitments And Contingencies [Line Items]
Number of cases		2
Arkansas Royalty Litigation [Member] | Federal Court 2014 [Member]
Commitments And Contingencies [Line Items]
Number of cases		1
Arkansas Royalty Litigation [Member] | Arkansas State Court 2015 [Member]
Commitments And Contingencies [Line Items]
Number of cases	3
Number of plaintiffs | plaintiff	248
Arkansas Royalty Litigation [Member] | Federal Court [Member]
Commitments And Contingencies [Line Items]
Number of cases removed to federal court	2
Minimum [Member] | Arkansas Royalty Litigation [Member] | Federal Court 2014 [Member]
Commitments And Contingencies [Line Items]
Loss contingency, range of possible loss, minimum | $		$ 98,000,000
Pending Regulatory Approval and/or Construction [Member]
Commitments And Contingencies [Line Items]
Obligation under transportation agreements | $		$ 3,661,000,000

XML

Commitments And Contingencies (Schedule Of Future Obligation Under Transportation Agreements) (Details) $ in Millions	Mar. 31, 2017 USD ($)
Other Commitments [Line Items]
Less than 1 year	$ 627
1 to 3 years	1,510
3 to 5 years	1,265
5 to 8 years	1,562
More than 8 years	3,708
Total transportation charges	8,672
Infrastructure Currently in Service [Member]
Other Commitments [Line Items]
Less than 1 year	592
1 to 3 years	1,139
3 to 5 years	791
5 to 8 years	832
More than 8 years	1,657
Total transportation charges	5,011
Pending Regulatory Approval and/or Construction [Member]
Other Commitments [Line Items]
Less than 1 year	35
1 to 3 years	371
3 to 5 years	474
5 to 8 years	730
More than 8 years	2,051
Total transportation charges	$ 3,661

XML

Pension Plan And Other Postretirement Benefits (Narrative) (Details) - USD ($) $ in Millions	3 Months Ended		12 Months Ended
	Mar. 31, 2017	Mar. 31, 2016	Dec. 31, 2016	Jun. 30, 2016
Defined Benefit Plan Disclosure [Line Items]
Employer contributions	$ 5
Company's expected additional annual contribution	$ 9
Common Stock in Treasury, Shares	31,269		31,269
Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Net periodic benefit cost (gain)	$ 3	$ 4
Benefit obligation	34		$ 36
Discount rate		4.60%		4.20%
Other Postretirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Net periodic benefit cost (gain)	1	$ 1
Benefit obligation	$ 13		$ 13
Discount rate		4.60%		4.20%
Supplemental Employee Retirement Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Common stock purchased under the terms of the Non-Qualified Plan presented as treasury stock	11,686		31,269

XML

Pension Plan And Other Postretirement Benefits (Pension And Other Postretirement Benefit Costs) (Details) - Pension Benefits [Member] - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016
Defined Benefit Plan Disclosure [Line Items]
Service cost	$ 2	$ 4
Interest cost	1	2
Expected return on plan assets	(1)	(2)
Amortization of prior service cost
Amortization of net loss	1
Net periodic benefit cost	$ 3	$ 4

XML

Stock-Based Compensation (Narrative) (Details) - USD ($) $ in Millions	1 Months Ended	3 Months Ended
	Jan. 31, 2016	Mar. 31, 2017
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unrecognized compensation cost related to the Company's unvested stock option grants, restricted stock grants, and performance units		$ 96
Weighted average period over which cost is recognized, years		3 years
Stock Options [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock options, exercised, number of options
Performance Units [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting period for stock awards from grant date		3 years
Liability-Classified Performance Units [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting period for stock awards from grant date		3 years
Workforce Reduction [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Positions eliminated, percent	40.00%

XML

Stock-Based Compensation (Schedule Of Stock-Based Compensation Costs) (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016
Share-based Compensation Arrangement by Share-based Payment Award, Compensation Cost [Line Items]
Stock-based compensation cost - expensed	$ 6	$ 23
Stock-based compensation cost - capitalized	$ 4	3
Workforce Reduction [Member]
Share-based Compensation Arrangement by Share-based Payment Award, Compensation Cost [Line Items]
Stock-based compensation cost - expensed		$ 18

XML

Stock-Based Compensation (Summary Of Stock Option Activity) (Details) - Stock Options [Member] shares in Thousands	3 Months Ended
	Mar. 31, 2017 $ / shares shares
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock options, Outstanding at December 31, 2016, Number of Options | shares	5,416
Stock options, Granted, Number of Options | shares	1,322
Stock options, Exercised, Number of Options | shares
Stock options, Forfeited or expired, Number of Options | shares	(17)
Stock options, Outstanding at March 31, 2017, Number of Options | shares	6,721
Stock options, Exercisable at March 31, 2017, Number of Options | shares	3,537
Stock options, Outstanding at December 31, 2016, Weighted Average Exercise Price | $ / shares	$ 23.46
Stock options, Granted, Weighted Average Exercise Price | $ / shares	8.59
Stock options, Exercised, Weighted Average Exercise Price | $ / shares
Stock options, Forfeited or expired, Weighted Average Exercise Price | $ / shares	45.57
Stock options, Outstanding at March 31, 2017, Weighted Average Exercise Price | $ / shares	20.48
Stock options, Exercisable at March 31, 2017, - Weighted Average Exercise Price | $ / shares	$ 29.34

XML

Stock-Based Compensation (Summary Of Restricted Stock Activity) (Details) - Restricted Stock [Member] shares in Thousands	3 Months Ended
	Mar. 31, 2017 $ / shares shares
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unvested shares/units at December 31, 2016, Number of Shares | shares	3,321
Granted, Number of Shares/Units | shares	4,549
Vested, Number of Shares/Units | shares	(70)
Forfeited, Number of Shares/Units | shares	(113)
Unvested shares/units at March 31, 2017, Number of Shares | shares	7,687
Unvested shares/units at December 31, 2016, Weighted Average Fair Value | $ / shares	$ 11.85
Granted, Weighted Average Fair Value | $ / shares	8.59
Vested, Weighted Average Fair Value | $ / shares	13.45
Forfeited, Weighted Average Fair Value | $ / shares	10.05
Unvested shares at March 31, 2017, Weighted Average Fair Value | $ / shares	$ 9.93

XML

Stock-Based Compensation (Summary Of Performance Unit Activity) (Details) - Performance Units [Member]	3 Months Ended
	Mar. 31, 2017 $ / shares shares
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unvested shares/units at December 31, 2016, Number of Shares	719,000
Granted, Number of Shares/Units	1,197,000
Vested, Number of Shares/Units
Forfeited, Number of Shares/Units
Unvested shares/units at March 31, 2017, Number of Shares	1,916,000
Unvested shares/units at December 31, 2016, Weighted Average Fair Value | $ / shares	$ 11.46
Granted, Weighted Average Fair Value | $ / shares	10.47
Vested, Weighted Average Fair Value | $ / shares
Forfeited, Weighted Average Fair Value | $ / shares
Unvested shares at March 31, 2017, Weighted Average Fair Value | $ / shares	$ 10.84
Vesting period for stock awards from grant date	3 years
Minimum [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Granted, Number of Shares/Units	0
Maximum [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Granted, Number of Shares/Units	2

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Segment Information (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016	Dec. 31, 2016	Dec. 31, 2015
Segment Reporting Information [Line Items]
Revenues	$ 846	$ 579
Depreciation, depletion and amortization expense	106	143
Impairment of natural gas and oil properties		1,034
Operating income (loss)	266	(1,100)
Interest expense	32	14
Gain (loss) on derivatives	116	(14)
Loss on Early Extinguishment of Debt	(1)
Other income (loss), net	2	(3)
Provision for income taxes		1
Assets	7,196	8,518	$ 7,076
Capital investments	290	122
Restructuring charges		64
Cash and cash equivalents	1,382	1,597	$ 1,423	$ 15
Change in accrued expenditures	(52)	(78)
Intersegment Eliminations [Member]
Segment Reporting Information [Line Items]
Revenues	(575)	(378)
Exploration and Production [Member]
Segment Reporting Information [Line Items]
Revenues	566	343
Depreciation, depletion and amortization expense	90	127
Impairment of natural gas and oil properties		1,034
Operating income (loss)	225	(1,160)
Interest expense	32	14
Gain (loss) on derivatives	116	(13)
Other income (loss), net	2	(2)
Provision for income taxes		1
Assets	4,413	5,538
Capital investments	283	120
Restructuring charges		61
Exploration and Production [Member] | Intersegment Eliminations [Member]
Segment Reporting Information [Line Items]
Revenues	3	7
Midstream Services [Member]
Segment Reporting Information [Line Items]
Revenues	280	236
Depreciation, depletion and amortization expense	16	16
Operating income (loss)	41	60
Gain (loss) on derivatives		(1)
Other income (loss), net		(1)
Assets	1,268	1,220
Capital investments	6	2
Restructuring charges		3
Midstream Services [Member] | Intersegment Eliminations [Member]
Segment Reporting Information [Line Items]
Revenues	(578)	(385)
Other [Member]
Segment Reporting Information [Line Items]
Loss on Early Extinguishment of Debt	(1)
Assets	1,515	1,760
Capital investments	1
Cash and cash equivalents	1,400	1,600
Marketing [Member] | Midstream Services [Member] | Intersegment Eliminations [Member]
Segment Reporting Information [Line Items]
Revenues	$ (524)	$ (319)

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Income Taxes (Narrative) (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016
Income Taxes [Abstract]
Effective tax rate	0.00%	0.00%
Increase (decrease) in valuation allowance	$ (75)	$ 431

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New Accounting Pronouncements (Narrative) (Details) $ in Millions	3 Months Ended
	Mar. 31, 2017 USD ($)
New Accounting Pronouncements [Abstract]
Net cumulative-effect adjustment	$ 59