Natural Gas Producing Activities (Unaudited) (Tables)

12 Months Ended

Dec. 31, 2017

Oil and Gas Exploration and Production Industries Disclosures [Abstract]

Schedule of cost incurred relating to property acquisition, exploration and development

The following tables present the total aggregate capitalized costs and the costs incurred relating to natural gas, NGLs and oil production activities (a):

	For the Years Ended December 31,
	2017		2016		2015
	(Thousands)
At December 31:
Capitalized Costs:
Proved properties	$	18,920,855	$	12,179,833	$	10,918,499
Unproved properties	5,016,299		1,698,826		898,270
Total capitalized costs	23,937,154		13,878,659		11,816,769
Accumulated depreciation and depletion	5,121,646		4,217,154		3,425,618
Net capitalized costs	$	18,815,508	$	9,661,505	$	8,391,151

	For the Years Ended December 31,
	2017		2016		2015
	(Thousands)
Costs incurred: (a)
Property acquisition:
Proved properties (b)	$	5,251,711	$	403,314	$	23,890
Unproved properties (c)	3,310,995		880,545		158,405
Exploration (d)	15,505		6,047		53,463
Development	1,365,615		777,787		1,633,498
Geological and geophysical	—		—		—

(a)Amounts exclude capital expenditures for facilities and information technology.

(b)Amounts in 2017 include $2,530.4 million and $1,192.0 million for the purchase of Marcellus wells and leases, respectively, acquired in the 2017 transactions discussed in Notes 2 and 10. The purchase of Marcellus leases includes measurement period adjustments to the 2016 acquisitions. Amounts in 2017 also include $1,228.6 million and $0.3 million for the purchase of Utica wells and leases, respectively, acquired in the 2017 transactions discussed in Notes 2 and 10. Amounts in 2016 include $256.2 million and $112.2 million for the purchase of Marcellus wells and leases, respectively, acquired in the 2016 transactions discussed in Note 10.

(c)Amounts in 2017 include $2,625.1 million and $0.5 million for the purchase of Marcellus leases and Utica leases, respectively, acquired in the 2017 transactions discussed in Notes 2 and 10. Amounts in 2016 include $770.4 million for the purchase of Marcellus leases acquired in the 2016 transactions discussed in Note 10.

(d)Amounts include capitalizable exploratory costs and exploration expense, excluding impairments.

Results of operations related to natural gas, NGL and oil producing Activities

The following table presents the results of operations related to natural gas, NGLs and oil production:

	For the Years Ended December 31,
	2017		2016			2015
	(Thousands)
Revenues:
Nonaffiliated	$	2,651,318	$	1,594,997		$	1,690,360
Production costs	1,338,069		1,055,017			877,194
Exploration costs	25,117		13,410			61,970
Depreciation, depletion and accretion	982,103		859,018			765,298
Impairment of long-lived assets	—		6,939			122,469
Amortization of intangible assets	5,540		—			—
Income tax expense (benefit)	117,984		(136,323		)	(54,857		)
Results of operations from producing activities (excluding corporate overhead)	$	182,505	$	(203,064	)	$	(81,714	)

Schedule of the entity's proved reserves

	Years Ended December 31,
	2017		2016		2015
	(Millions of Cubic Feet)
Total - Natural Gas, Oil, and NGLs (a)
Proved developed and undeveloped reserves:
Beginning of year	13,508,407		9,976,597		10,738,948
Revision of previous estimates	(2,766,981	)	(472,285	)	(2,194,675	)
Purchase of hydrocarbons in place	9,389,638		2,395,776		—
Sale of hydrocarbons in place	(2,646	)	—		(61	)
Extensions, discoveries and other additions	2,225,141		2,384,682		2,051,071
Production	(907,892	)	(776,363	)	(618,686	)
End of year	21,445,667		13,508,407		9,976,597
Proved developed reserves:
Beginning of year	6,842,958		6,279,557		4,826,387
End of year	11,297,956		6,842,958		6,279,557
Proved undeveloped reserves:
Beginning of year	6,665,449		3,697,040		5,912,561
End of year	10,147,711		6,665,449		3,697,040

(a)         Oil and NGLs were converted at the rate of one thousand Bbl equal to approximately 6 million cubic feet (MMcf).

	Years Ended December 31,
	2017		2016		2015
	(Millions of Cubic Feet)
Natural Gas
Proved developed and undeveloped reserves:
Beginning of year	12,331,867		9,110,311		9,775,954
Revision of previous estimates	(2,760,467	)	(607,171	)	(2,059,531	)
Purchase of natural gas in place	8,890,145		2,288,166		—
Sale of natural gas in place	(1,210	)	—		(61	)
Extensions, discoveries and other additions	2,164,578		2,241,528		1,955,935
Production	(794,677	)	(700,967	)	(561,986	)
End of year	19,830,236		12,331,867		9,110,311
Proved developed reserves:
Beginning of year	6,074,958		5,652,989		4,257,377
End of year	10,152,543		6,074,958		5,652,989
Proved undeveloped reserves:
Beginning of year	6,256,909		3,457,322		5,518,577
End of year	9,677,693		6,256,909		3,457,322

	Years Ended December 31,
	2017		2016		2015
	(Thousands of Bbls)
Oil (a)
Proved developed and undeveloped reserves:
Beginning of year	6,395		5,900		5,005
Revision of previous estimates	5,103		1,159		1,219
Purchase of oil in place	355		3		—
Sale of oil in place	(139	)	—		—
Extensions, discoveries and other additions	9		62		419
Production	(992	)	(729	)	(743	)
End of year	10,731		6,395		5,900
Proved developed reserves:
Beginning of year	6,395		5,900		5,005
End of year	10,731		6,395		5,900
Proved undeveloped reserves:
Beginning of year	—		—		—
End of year	—		—		—

(a) One thousand Bbl equals approximately 6 million cubic feet (MMcf).

	Years Ended December 31,
	2017		2016		2015
	(Thousands of Bbls)
NGLs (a)
Proved developed and undeveloped reserves:
Beginning of year	189,695		138,481		155,494
Revision of previous estimates	(6,189	)	21,322		(23,743	)
Purchase of NGLs in place	82,894		17,932		—
Sale of NGLs in place	(100	)	—		—
Extensions, discoveries and other additions	10,084		23,797		15,437
Production	(17,877	)	(11,837	)	(8,707	)
End of year	258,507		189,695		138,481
Proved developed reserves:
Beginning of year	121,605		98,528		89,830
End of year	180,170		121,605		98,528
Proved undeveloped reserves:
Beginning of year	68,090		39,953		65,664
End of year	78,337		68,090		39,953

(a) One thousand Bbl equals approximately 6 million cubic feet (MMcf).

Schedule of estimated future net cash flows from natural gas and oil reserves

Estimated future net cash flows from natural gas and oil reserves are as follows at December 31:

	2017			2016			2015
	(Thousands)
Future cash inflows (a)	$	51,423,920		$	24,011,281		$	17,619,037
Future production costs	(18,379,892		)	(14,864,126		)	(10,963,285		)
Future development costs	(5,637,676		)	(3,778,698		)	(2,377,650		)
Future income tax expenses	(5,811,125		)	(1,753,067		)	(1,333,989		)
Future net cash flow	21,595,227			3,615,390			2,944,113
10% annual discount for estimated timing of cash flows	(12,593,293		)	(2,626,636		)	(1,966,559		)
Standardized measure of discounted future net cash flows	$	9,001,934		$	988,754		$	977,554

(a)	The majority of the Company’s production is sold through liquid trading points on interstate pipelines. For 2017, the reserves were computed using unweighted arithmetic averages of the closing prices on the first day of each month during 2017 of $51.34 per Bbl of oil (first day of each month closing price for West Texas Intermediate (WTI)) less regional adjustments, $2.801 per Dth for Columbia Gas Transmission Corp., $2.100 per Dth for Dominion Transmission, Inc., $2.914 per Dth for the East Tennessee Natural Gas Pipeline, $2.058 per Dth for Texas Eastern Transmission Corp., $1.995 per Dth for the Tennessee, zone 4-300 Leg of Tennessee Gas Pipeline Company, $2.321 per Dth for the Tennessee LA 500 Leg of Tennessee Gas Pipeline Company, $2.665 per Dth for Waha, and $2.840 per Dth for the Rockies Express Pipeline Zone 3. For 2017, NGL pricing using arithmetic averages of the closing prices on the first day of each month during 2017 for NGL components and adjusted using the regional component makeup of produced NGLs resulted in prices of $23.07 per Bbl of NGLs from certain West Virginia Marcellus reserves, $31.11 per Bbl of NGLs from certain Kentucky reserves, $29.47 per Bbl for Ohio Utica reserves, and $27.93 per Bbl for Permian reserves.
	The majority of the Company’s production is sold through liquid trading points on interstate pipelines. For 2016, the reserves were computed using unweighted arithmetic averages of the closing prices on the first day of each month during 2016 of $42.75 per Bbl of oil (first day of each month closing price for WTI) less regional adjustments, $2.342 per Dth for Columbia Gas Transmission Corp., $1.348 per Dth for Dominion Transmission, Inc., $2.334 per Dth for the East Tennessee Natural Gas Pipeline, $1.325 per Dth for Texas Eastern Transmission Corp., $1.305 per Dth for the Tennessee, zone 4-300 Leg of Tennessee Gas Pipeline Company, $1.862 per Dth for the Tennessee LA 500 Leg of Tennessee Gas Pipeline Company, $2.343 per Dth for Waha, and $2.402 per Dth for the Rockies Express Pipeline Zone 3. For 2016, NGL pricing using arithmetic averages of the closing prices on the first day of each month during 2016 for NGL components and adjusted using the regional component makeup of produced NGLs resulted in prices of $13.87 per Bbl of NGLs from certain West Virginia Marcellus reserves, $17.27 per Bbl of NGLs from certain Kentucky reserves, $14.71 per Bbl for Ohio Utica reserves, and $18.91 per Bbl for Permian reserves.
	The majority of the Company’s production is sold through liquid trading points on interstate pipelines. For 2015, the reserves were computed using unweighted arithmetic averages of the closing prices on the first day of each month during 2015 of $50.28 per Bbl of oil (first day of each month closing price for WTI) less regional adjustments, $2.506 per Dth for Columbia Gas Transmission Corp., $1.394 per Dth for Dominion Transmission, Inc., $2.552 per Dth for the East Tennessee Natural Gas Pipeline, $1.428 per Dth for Texas Eastern Transmission Corp., $1.079 per Dth for the Tennessee, zone 4-300 Leg of Tennessee Gas Pipeline Company, $2.430 per Dth for the Tennessee LA 500 Leg of Tennessee Gas Pipeline Company, $2.473 per Dth for Waha, and $2.549 per Dth for Houston Ship Channel.  For 2015, NGLs pricing using arithmetic averages of the closing prices on the first day of each month during 2015 for NGLs components and adjusted using the regional component makeup of produced NGLs resulted in prices of $17.60 per Bbl of NGLs from certain West Virginia Marcellus reserves, $21.69 per Bbl of NGLs from certain Kentucky reserves, $16.84 per Bbl for Ohio Utica reserves, and $17.51 per Bbl for Permian reserves.

Schedule of changes in the standardized measure of discounted net cash flows from natural gas and oil reserves

Summary of changes in the standardized measure of discounted future net cash flows for the years ended December 31:

	2017			2016			2015
	(Thousands)
Sales and transfers of natural gas and oil produced – net	$	(1,313,249	)	$	(539,980	)	$	(813,166	)
Net changes in prices, production and development costs	2,236,183			(1,129,026		)	(5,546,405		)
Extensions, discoveries and improved recovery, less related costs	1,269,712			590,885			264,735
Development costs incurred	712,635			402,891			971,186
Purchase of minerals in place – net	5,357,921			592,078			—
Sale of minerals in place – net	(284		)	—			(43		)
Revisions of previous quantity estimates	(297,437		)	(60,959		)	(1,541,418		)
Accretion of discount	115,437			122,674			600,099
Net change in income taxes	(1,477,603		)	(91,823		)	2,424,200
Timing and other (a)	1,409,865			124,460			(191,662		)
Net increase (decrease)	8,013,180			11,200			(3,832,474		)
Beginning of year	988,754			977,554			4,810,028
End of year	$	9,001,934		$	988,754		$	977,554

(a) Increase in 2017 primarily driven by timing changes to the Company’s development plan as a result of the Rice Merger.