Supplemental Oil and Gas Disclosures (Tables)

12 Months Ended

Dec. 31, 2017

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

Capitalized Costs Relating to Oil and Gas Producing Activities Disclosure

(in millions)	2017		2016
Proved properties	$	22,073	$	20,548
Unproved properties		1,817		2,105
Total capitalized costs		23,890		22,653
Less:  Accumulated depreciation, depletion and amortization		(19,287)		(18,897)
Net capitalized costs	$	4,603	$	3,756

Composition of Net Unevaluated Costs Excluded from Amortization

(in millions)	2017		2016		2015		Prior		Total
Property acquisition costs	$	80	$	18	$	145	$	1,295	$	1,538
Exploration and development costs		67		7		32		14		120
Capitalized interest		67		41		33		18		159
	$	214	$	66	$	210	$	1,327	$	1,817

Cost Incurred in Oil and Gas Property Acquisition, Exploration, and Development Activities Disclosure

(in millions, except per Mcfe amounts)	2017		2016		2015
Proved property acquisition costs	$	–	$	–	$	81
Unproved property acquisition costs		194		171		692
Exploration costs		22		17		50
Development costs		1,024		433		1,417
Capitalized costs incurred		1,240		621		2,240
Full cost pool amortization per Mcfe	$	0.45	$	0.38	$	1.00

Results of Operations for Oil and Gas Producing Activities Disclosure

(in millions)	2017		2016		2015
Sales	$	2,086	$	1,413	$	2,074
Production (lifting) costs		(891)		(839)		(989)
Depreciation, depletion and amortization		(440)		(371)		(1,028)
Impairment of natural gas and oil properties		–		(2,321)		(6,950)
		755		(2,118)		(6,893)
Provision (benefit) for income taxes (1)		–		–		(2,619)
Results of operations (2)	$	755	$	(2,118)	$	(4,274)

(1) Prior to the recognition of a valuation allowance, in 2017 and 2016 the Company recognized income tax provisions of $287 million and $805 million, respectively.

(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
(in Bcfe)	Northeast	Southwest	Shale	Other(1)	Total
December 31, 2014	3,191	2,297	5,069	190	10,747
Net revisions
Price revisions	(2,315)	(1,875)	(1,496)	(32)	(5,718)
Performance and production revisions	1,383	209	10	33	1,635
Total net revisions	(932)	(1,666)	(1,486)	1	(4,083)
Extensions, discoveries and other additions
Proved developed	202	84	129	1	416
Proved undeveloped	138	4	34	–	176
Total reserve additions	340	88	163	1	592
Production	(360)	(143)	(465)	(8)	(976)
Acquisition of reserves in place	80	35	–	–	115
Disposition of reserves in place	–	–	–	(180)	(180)
December 31, 2015	2,319	611	3,281	4	6,215
Net revisions
Price revisions	(794)	(127)	(116)	–	(1,037)
Performance and production revisions	318	199	163	3	683
Total net revisions	(476)	72	47	3	(354)
Extensions, discoveries and other additions
Proved developed	81	157	19	–	257
Proved undeveloped	–	–	25	–	25
Total reserve additions	81	157	44	–	282
Production	(350)	(148)	(375)	(2)	(875)
Acquisition of reserves in place	–	–	–	–	–
Disposition of reserves in place	–	(15)	–	–	(15)
December 31, 2016	1,574	677	2,997	5	5,253
Net revisions
Price revisions	903	738	49	1	1,691
Performance and production revisions	154	125	358	4	641
Total net revisions	1,057	863	407	5	2,332
Extensions, discoveries and other additions
Proved developed	790	419	48	1	1,258
Proved undeveloped	1,100	5,186	543	–	6,829
Total reserve additions	1,890	5,605	591	1	8,087
Production	(395)	(183)	(316)	(3)	(897)
Acquisition of reserves in place	–	–	–	–	–
Disposition of reserves in place	–	–	–	–	–
December 31, 2017	4,126	6,962	3,679	8	14,775

(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

(in millions)	2017		2016		2015
Future cash inflows	$	36,576	$	9,064	$	11,887
Future production costs		(18,390)		(5,880)		(7,376)
Future development costs (1)		(4,676)		(485)		(792)
Future income tax expense (2)		(1,342)		–		–
Future net cash flows		12,168		2,699		3,719
10% annual discount for estimated timing of cash flows		(6,606)		(1,034)		(1,302)
Standardized measure of discounted future net cash flows	$	5,562	$	1,665	$	2,417

(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 Prices used for Standardized Measure of Discounted Future Cash Flows Relating to Proved Reserves Disclosure

	2017		2016		2015
Natural gas (per MMBtu)	$	2.98	$	2.48	$	2.59
Oil (per Bbl)	$	47.79	$	39.25	$	46.79
NGLs (per Bbl)	$	14.41	$	6.74	$	6.82

Schedule of Analysis of Changes in Standardized Measure

(in millions)	2017		2016		2015
Standardized measure, beginning of year	$	1,665	$	2,417	$	7,543
Sales and transfers of natural gas and oil produced, net of production costs		(1,191)		(574)		(1,082)
Net changes in prices and production costs		1,963		(415)		(8,075)
Extensions, discoveries, and other additions, net of future production and development costs		1,715		45		162
Acquisition of reserves in place		–		–		28
Sales of reserves in place		–		(10)		(244)
Revisions of previous quantity estimates		1,721		(140)		(1,385)
Net change in income taxes		(222)		–		1,915
Changes in estimated future development costs		(6)		71		2,007
Previously estimated development costs incurred during the year		55		114		875
Changes in production rates (timing) and other		(304)		(85)		(273)
Accretion of discount		166		242		946
Standardized measure, end of year	$	5,562	$	1,665	$	2,417

United States [Member]

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

Summary of Changes in Reserves

	Natural
	Gas	Oil	NGL	Total
	(Bcf)	(MBbls)	(MBbls)	(Bcfe)
December 31, 2014	9,809	37,615	118,699	10,747
Revisions of previous estimates (1)	(3,458)	(28,394)	(75,664)	(4,083)
Extensions, discoveries and other additions	546	1,367	6,274	592
Production	(899)	(2,265)	(10,702)	(976)
Acquisition of reserves in place	97	525	2,340	115
Disposition of reserves in place	(178)	(95)	–	(180)
December 31, 2015	5,917	8,753	40,947	6,215
Revisions of previous estimates	(446)	1,564	13,794	(354)
Extensions, discoveries and other additions	198	2,417	11,576	282
Production	(788)	(2,192)	(12,372)	(875)
Acquisition of reserves in place	–	–	–	–
Disposition of reserves in place	(15)	(19)	(14)	(15)
December 31, 2016	4,866	10,523	53,931	5,253
Revisions of previous estimates	1,898	1,668	70,549	2,332
Extensions, discoveries and other additions  (2)	5,159	55,772	432,220	8,087
Production	(797)	(2,327)	(14,245)	(897)
Acquisition of reserves in place	–	–	–	–
Disposition of reserves in place	–	–	–	–
December 31, 2017	11,126	65,636	542,455	14,775

(1) The significant revisions of previous estimates in 2015 was primarily due to price revision, as a result of lower average commodity prices in 2015.

(2) The 2017 PUD additions are primarily associated with the increase in commodity prices.

	Natural
	Gas	Oil	NGL	Total
	(Bcf)	(MBbls)	(MBbls)	(Bcfe)
Proved developed reserves as of:
December 31, 2015	5,474	8,753	40,947	5,772
December 31, 2016	4,789	10,523	53,931	5,176
December 31, 2017	6,979	14,513	142,213	7,920
Proved undeveloped reserves as of:
December 31, 2015	443	–	–	443
December 31, 2016	77	–	–	77
December 31, 2017	4,147	51,123	400,242	6,855