Supplemental Oil and Gas Disclosures (Tables)

12 Months Ended

Dec. 31, 2018

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

Capitalized Costs Relating to Oil and Gas Producing Activities Disclosure

(in millions)	2018		2017
Proved properties	$	22,425	$	22,073
Unproved properties		1,755		1,817
Total capitalized costs		24,180		23,890
Less:  Accumulated depreciation, depletion and amortization		(19,761)		(19,287)
Net capitalized costs	$	4,419	$	4,603

Composition of Net Unevaluated Costs Excluded from Amortization

(in millions)	2018		2017		2016		Prior		Total
Property acquisition costs	$	49	$	70	$	12	$	1,346	$	1,477
Exploration and development costs		42		23		6		23		94
Capitalized interest		77		45		28		34		184
	$	168	$	138	$	46	$	1,403	$	1,755

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

(in millions, except per Mcfe amounts)	2018		2017		2016
Unproved property acquisition costs	$	164	$	194	$	171
Exploration costs		5		22		17
Development costs		1,014		1,024		433
Capitalized costs incurred		1,183		1,240		621
Full cost pool amortization per Mcfe	$	0.51	$	0.45	$	0.38

Results of Operations for Oil and Gas Producing Activities Disclosure

(in millions)	2018		2017		2016
Sales	$	2,525	$	2,086	$	1,413
Production (lifting) costs		(974)		(891)		(839)
Depreciation, depletion and amortization		(514)		(440)		(371)
Impairment of natural gas and oil properties		–		–		(2,321)
		1,037		755		(2,118)
Provision (benefit) for income taxes (1)		–		–		–
Results of operations (2)	$	1,037	$	755	$	(2,118)

(1) Prior to the recognition of a valuation allowance, in 2018, 2017 and 2016 the Company recognized income tax provisions of $254 million,$287 million and $805 million, respectively.

(2) Results of operations exclude the gain (loss) on unsettled commodity derivative instruments.  See Note 5 – “Derivatives and Risk Management”.

Summary of Changes in Reserves

	Appalachia		Fayetteville
(in Bcfe)	Northeast	Southwest	Shale (1)	Other (2)	Total
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
Net revisions
Price revisions	41	106	6	1	154
Performance and production revisions	107	272	(6)	(1)	372
Total net revisions	148	378	–	–	526
Extensions, discoveries and other additions
Proved developed	154	22	1	–	177
Proved undeveloped	397	435	–	–	832
Total reserve additions	551	457	1	–	1,009
Production	(459)	(243)	(243)	(1)	(946)
Acquisition of reserves in place	–	–	–	–	–
Disposition of reserves in place	–	–	(3,437)	(6)	(3,443)
December 31, 2018	4,366	7,554	–	1	11,921

(1) The Fayetteville Shale E&P assets and associated reserves were divested December 3, 2018.

(2) Other includes properties outside of the Appalachian Basin and Fayetteville Shale.

Standardized Measure of Discounted Future Cash Flows Relating to Proved Reserves Disclosure

(in millions)	2018		2017		2016
Future cash inflows	$	34,523	$	36,576	$	9,064
Future production costs		(15,347)		(18,390)		(5,880)
Future development costs (1)		(4,095)		(4,676)		(485)
Future income tax expense (2)		(2,079)		(1,342)		–
Future net cash flows		13,002		12,168		2,699
10% annual discount for estimated timing of cash flows		(7,003)		(6,606)		(1,034)
Standardized measure of discounted future net cash flows	$	5,999	$	5,562	$	1,665

(1) Includes abandonment costs.

(2) The December 31, 2016 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

(in millions)	2018		2017		2016
Natural gas (per MMBtu)	$	3.10	$	2.98	$	2.48
Oil (per Bbl)		65.56		47.79		39.25
NGLs (per Bbl)		17.64		14.41		6.74

Schedule of Analysis of Changes in Standardized Measure

(in millions)	2018		2017		2016
Standardized measure, beginning of year	$	5,562	$	1,665	$	2,417
Sales and transfers of natural gas and oil produced, net of production costs		(1,564)		(1,191)		(574)
Net changes in prices and production costs		2,162		1,963		(415)
Extensions, discoveries, and other additions, net of future production and development costs		335		1,715		45
Acquisition of reserves in place		–		–		–
Sales of reserves in place		(2,022)		–		(10)
Revisions of previous quantity estimates		361		1,721		(140)
Net change in income taxes		(304)		(222)		–
Changes in estimated future development costs		(166)		(6)		71
Previously estimated development costs incurred during the year		536		55		114
Changes in production rates (timing) and other		521		(304)		(85)
Accretion of discount		578		166		242
Standardized measure, end of year	$	5,999	$	5,562	$	1,665

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, 2015	5,917	8,753	40,947	6,215
Revisions of previous estimates due to price	(983)	(582)	(8,337)	(1,037)
Revisions of previous estimates other than price	537	2,146	22,131	683
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 due to price	1,327	3,197	57,447	1,691
Revisions of previous estimates other than price	571	(1,529)	13,102	641
Extensions, discoveries and other additions (1)	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
Revisions of previous estimates due to price	96	788	8,912	154
Revisions of previous estimates other than price	316	410	8,855	372
Extensions, discoveries and other additions	753	5,830	36,823	1,009
Production	(807)	(3,407)	(19,706)	(946)
Acquisition of reserves in place	–	–	–	–
Disposition of reserves in place (2)	(3,440)	(250)	(276)	(3,443)
December 31, 2018	8,044	69,007	577,063	11,921

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

(2) The 2018 disposition is primarily associated with the Fayetteville Shale sale.

	Natural
	Gas	Oil	NGL	Total
	(Bcf)	(MBbls)	(MBbls)	(Bcfe)
Proved developed reserves as of:
December 31, 2016	4,789	10,523	53,931	5,176
December 31, 2017	6,979	14,513	142,213	7,920
December 31, 2018	4,395	18,037	175,480	5,557
Proved undeveloped reserves as of:
December 31, 2016	77	–	–	77
December 31, 2017	4,147	51,123	400,242	6,855
December 31, 2018	3,649	50,970	401,583	6,364