Supplemental Oil And Gas Disclosures (Tables)

12 Months Ended

Dec. 31, 2016

Oil and Gas Exploration and Production Industries Disclosures [Line Items]

Capitalized Costs Relating To Oil And Gas Producing Activities Disclosure

	2016		2015
	(in millions)
Proved properties	$	20,548	$	18,751
Unproved properties		2,105		3,727
Total capitalized costs		22,653		22,478
Less:  Accumulated depreciation, depletion and amortization		(18,897)		(16,248)
Net capitalized costs	$	3,756	$	6,230

Composition Of Net Unevaluated Costs Excluded From Amortization

	2016		2015		2014		Prior		Total
	(in millions)
Property acquisition costs	$	22	$	213	$	1,501	$	54	$	1,790
Exploration and development costs		55		64		24		16		159
Capitalized interest		70		55		10		21		156
	$	147	$	332	$	1,535	$	91	$	2,105

Cost Incurred In Oil And Gas Property Acquisition, Exploration, And Development Activities Disclosure

	2016		2015		2014
	(in millions, except per Mcfe amounts)
Proved property acquisition costs	$	–	$	81	$	1,455
Unproved property acquisition costs		171		692		3,934
Exploration costs		17		50		232
Development costs		433		1,417		1,600
Capitalized costs incurred		621		2,240		7,221
Full cost pool amortization per Mcfe	$	0.38	$	1.00	$	1.10

Results Of Operations For Oil And Gas Producing Activities Disclosure

	2016			2015		2014
	(in millions)
Sales	$	1,413		$	2,074	$	2,862
Production (lifting) costs		(839)			(989)		(776)
Depreciation, depletion and amortization		(371)			(1,028)		(884)
Impairment of natural gas and oil properties		(2,321)			(6,950)		–
		(2,118)			(6,893)		1,202
Provision (benefit) for income taxes		–	(1)		(2,619)		457
Results of operations (2)	$	(2,118)		$	(4,274)	$	745

(1) Prior to the Company’s recognition of a valuation allowance in 2016, the Company recognized an income tax benefit of $805 million.

(2) Results of operations exclude the gain (loss) on unsettled commodity derivative instruments.  See Note 4 - Derivatives and Risk Management

Summary Of Changes in Reserves

		Appalachia		Fayetteville
	Total	Northeast	Southwest	Shale	Other(1)
	(in Bcfe)
December 31, 2013	6,976	1,963	–	4,795	218
Production	(768)	(254)	(3)	(494)	(17)
Disposition of reserves in place	–	–	–	–	–
Acquisition of reserves in place	2,303	1	2,300	–	2
Net revisions
Price revisions	54	10	–	38	6
Performance and production revisions	489	636	–	(126)	(21)
Total net revisions	543	646	–	(88)	(15)
Reserve additions
Proved developed	531	246	–	283	2
Proved undeveloped	1,162	589	–	573	–
Total reserve additions	1,693	835	–	856	2
December 31, 2014	10,747	3,191	2,297	5,069	190
Production	(976)	(360)	(143)	(465)	(8)
Disposition of reserves in place	(180)	–	–	–	(180)
Acquisition of reserves in place	115	80	35	–	–
Net revisions
Price revisions	(5,718)	(2,315)	(1,875)	(1,496)	(32)
Performance and production revisions	1,635	1,383	209	10	33
Total net revisions	(4,083)	(932)	(1,666)	(1,486)	1
Reserve additions
Proved developed	416	202	84	129	1
Proved undeveloped	176	138	4	34	–
Total reserve additions	592	340	88	163	1
December 31, 2015	6,215	2,319	611	3,281	4
Production	(875)	(350)	(148)	(375)	(2)
Disposition of reserves in place	(15)	–	(15)	–	–
Acquisition of reserves in place	–	–	–	–	–
Net revisions
Price revisions	(1,037)	(794)	(127)	(116)	–
Performance and production revisions	683	318	199	163	3
Total net revisions	(354)	(476)	72	47	3
Reserve additions
Proved developed	257	81	157	19	–
Proved undeveloped	25	–	–	25	–
Total reserve additions	282	81	157	44	–
December 31, 2016	5,253	1,574	677	2,997	5

(1) Other includes properties outside of the Appalachian Basin and Fayetteville Shale along with Ark-La-Tex properties divested in May 2015.

Standardized Measure Of Discounted Future Cash Flows Relating To Proved Reserves Disclosure

	2016		2015		2014
	(in millions)
Future cash inflows	$	9,064	$	11,887	$	41,812
Future production costs		(5,880)		(7,376)		(16,477)
Future development costs (1)		(485)		(792)		(5,750)
Future income tax expense (2)		–		–		(4,743)
Future net cash flows		2,699		3,719		14,842
10% annual discount for estimated timing of cash flows		(1,034)		(1,302)		(7,299)
Standardized measure of discounted future net cash flows	$	1,665	$	2,417	$	7,543

(1) Includes abandonment costs.

(2) The December 31, 2016 and 2015 standardized measure computation does not have future income taxes because the Company’s tax basis in the associated oil and gas properties exceeded expected pre-tax cash inflows. Future net cash flows are not permitted to be increased by excess tax basis.

Schedule Of Analysis Of Changes In Standardized Measure

	2016		2015		2014
	(in millions)
Standardized measure, beginning of year	$	2,417	$	7,543	$	3,736
Sales and transfers of natural gas and oil produced, net of production costs		(574)		(1,082)		(2,084)
Net changes in prices and production costs		(415)		(8,075)		1,192
Extensions, discoveries, and other additions, net of future production and development costs		45		162		1,049
Acquisition of reserves in place		–		28		1,897
Sales of reserves in place		(10)		(244)		–
Revisions of previous quantity estimates		(140)		(1,385)		622
Accretion of discount		242		946		513
Net change in income taxes		–		1,915		(522)
Changes in estimated future development costs		71		2,007		110
Previously estimated development costs incurred during the year		114		875		815
Changes in production rates (timing) and other		(85)		(273)		215
Standardized measure, end of year	$	1,665	$	2,417	$	7,543

United States [Member]

Oil and Gas Exploration and Production Industries Disclosures [Line Items]

Summary Of Changes in Reserves

	2016			2015			2014
	Natural			Natural			Natural
	Gas	Oil	NGL	Gas	Oil	NGL	Gas	Oil	NGL
	(Bcf)	(MBbls)	(MBbls)	(Bcf)	(MBbls)	(MBbls)	(Bcf)	(MBbls)	(MBbls)
Proved reserves, beginning of year	5,917	8,753	40,947	9,809	37,615	118,699	6,974	373	–
Revisions of previous estimates	(446)	1,564	13,794	(3,458)	(28,394)	(75,664)	542	(14)	66
Extensions, discoveries and other additions	198	2,417	11,576	546	1,367	6,274	1,692	250	48
Production	(788)	(2,192)	(12,372)	(899)	(2,265)	(10,702)	(766)	(235)	(231)
Acquisition of reserves in place	–	–	–	97	525	2,340	1,367	37,246	118,816
Disposition of reserves in place	(15)	(19)	(14)	(178)	(95)	–	–	(5)	–
Proved reserves, end of year	4,866	10,523	53,931	5,917	8,753	40,947	9,809	37,615	118,699
Proved developed reserves:
Beginning of year	5,474	8,753	40,947	5,675	7,445	38,632	4,237	372	–
End of year	4,789	10,523	53,931	5,474	8,753	40,947	5,675	7,445	38,632
Proved undeveloped reserves:
Beginning of year	443	–	–	4,134	30,170	80,067	2,737	1	–
End of year	77	–	–	443	–	–	4,134	30,170	80,067