Natural Gas Producing Activities (Unaudited) (Tables)

12 Months Ended

Dec. 31, 2015

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, NGL and oil production activities (a):

	For the Years Ended December 31,
	2015		2014		2013
	(Thousands)
At December 31:
Capitalized Costs:
Proved properties	$	10,918,499	$	9,258,298	$	7,702,724
Unproved properties	898,270		824,527		450,227
Total capitalized costs	11,816,769		10,082,825		8,152,951
Accumulated depreciation and depletion	3,425,618		2,693,535		2,134,953
Net capitalized costs	$	8,391,151	$	7,389,290	$	6,017,998

	For the Years Ended December 31,
	2015		2014		2013
	(Thousands)
Costs incurred:
Property acquisition:
Proved properties (b)	$	23,890	$	231,322	$	90,390
Unproved properties (c)	158,405		493,067		95,861
Exploration (d)	53,463		16,023		4,285
Development	1,633,498		1,697,501		1,230,301

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

(b)Amounts include $198.2 million and $1.1 million for the purchase of Permian wells and leases, respectively, acquired in the Range transaction in 2014 and $57.0 million and $15.3 million for the purchase of Marcellus wells and leases, respectively, acquired in the Chesapeake transaction in 2013.

(c)Amounts include $317.2 million for the purchase of Permian leases acquired in the Range transaction in 2014. Amounts include $41.9 million for the purchase of Marcellus leases acquired in the Chesapeake transaction in 2013.

(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, NGL and oil production:

	For the Years Ended December 31,
	2015			2014		2013
	(Thousands)
Revenues:
Affiliated	$	1,412		$	4,761	$	5,912
Nonaffiliated	1,154,422			1,724,771		1,305,026
Production costs	398,044			334,050		250,372
Exploration costs	61,970			21,665		18,483
Depreciation, depletion and accretion	723,448			592,855		578,641
Impairment of long-lived assets	118,268			267,339		—
Income tax (benefit) expense	(58,603		)	202,881		183,060
Results of operations from producing activities (excluding corporate overhead)	$	(87,293	)	$	310,742	$	280,382

Schedule of the entity's proved reserves

	Years Ended December 31,
	2015		2014		2013
	(Millions of Cubic Feet)
Total - Natural Gas, Oil, and NGLs (a)
Proved developed and undeveloped reserves:
Beginning of year	10,738,948		8,348,269		6,004,952
Revision of previous estimates	(2,194,675	)	(301,351	)	191,509
Purchase of hydrocarbons in place	—		102,713		472,798
Sale of hydrocarbons in place	(61	)	(198,657	)	(455	)
Extensions, discoveries and other additions	2,051,071		3,276,054		2,046,578
Production	(618,686	)	(488,080	)	(367,113	)
End of year	9,976,597		10,738,948		8,348,269
Proved developed reserves:
Beginning of year	4,826,387		3,985,687		2,798,381
End of year	6,279,557		4,826,387		3,985,687
Proved undeveloped reserves:
Beginning of year	5,912,561		4,362,582		3,206,571
End of year	3,697,040		5,912,561		4,362,582

(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,
	2015		2014		2013
	(Millions of Cubic Feet)
Natural Gas
Proved developed and undeveloped reserves:
Beginning of year	9,775,954		7,561,561		5,985,758
Revision of previous estimates	(2,059,531	)	(228,085	)	(375,887	)
Purchase of natural gas in place	—		44,867		472,798
Sale of natural gas in place	(61	)	(198,531	)	(455	)
Extensions, discoveries and other additions	1,955,935		3,040,938		1,844,840
Production	(561,986	)	(444,796	)	(365,493	)
End of year	9,110,311		9,775,954		7,561,561
Proved developed reserves:
Beginning of year	4,257,377		3,567,313		2,779,187
End of year	5,652,989		4,257,377		3,567,313
Proved undeveloped reserves:
Beginning of year	5,518,577		3,994,248		3,206,571
End of year	3,457,322		5,518,577		3,994,248

	Years Ended December 31,
	2015		2014		2013
	(Thousands of Bbls)
Oil (a)
Proved developed and undeveloped reserves:
Beginning of year	5,005		3,956		3,199
Revision of previous estimates	1,219		(905	)	270
Purchase of oil in place	—		2,165		—
Sale of oil in place	—		(3	)	—
Extensions, discoveries and other additions	419		241		757
Production	(743	)	(449	)	(270	)
End of year	5,900		5,005		3,956
Proved developed reserves:
Beginning of year	5,005		3,892		3,199
End of year	5,900		5,005		3,892
Proved undeveloped reserves:
Beginning of year	—		64		—
End of year	—		—		64

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

	Years Ended December 31,
	2015		2014		2013
	(Thousands of Bbls)
NGLs (a)
Proved developed and undeveloped reserves:
Beginning of year	155,494		127,162		—
Revision of previous estimates	(23,743	)	(11,306	)	94,296
Purchase of NGLs in place	—		7,476		—
Sale of NGLs in place	—		(18	)	—
Extensions, discoveries and other additions	15,437		38,945		32,866
Production	(8,707	)	(6,765	)	—
End of year	138,481		155,494		127,162
Proved developed reserves:
Beginning of year	89,830		65,837		—
End of year	98,528		89,830		65,837
Proved undeveloped reserves:
Beginning of year	65,664		61,325		—
End of year	39,953		65,664		61,325

(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:

	2015			2014			2013
	(Thousands)
Future cash inflows (a)	$	10,071,465		$	30,428,815		$	25,912,542
Future production costs	(3,415,715		)	(4,868,079		)	(4,180,136		)
Future development costs	(2,377,650		)	(5,052,195		)	(4,199,722		)
Future income tax expenses	(1,333,989		)	(7,718,407		)	(6,533,817		)
Future net cash flow	2,944,111			12,790,134			10,998,867
10% annual discount for estimated timing of cash flows	(1,966,557		)	(7,980,106		)	(7,047,588		)
Standardized measure of discounted future net cash flows	$	977,554		$	4,810,028		$	3,951,279

(a)	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 West Texas Intermediate (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, NGL pricing using arithmetic averages of the closing prices on the first day of each month during 2015 for NGL components and adjusted using the regional component makeup of produced NGLs resulted in prices of $17.60 per Bbl of NGLs from West Virginia Marcellus reserves in Doddridge, Ritchie, and Wetzel counties, $21.69 per Bbl of NGLs from certain Kentucky reserves, $16.84 per Bbl for Utica reserves, and $17.51 per Bbl for Permian reserves.
	For 2014, the reserves were computed using unweighted arithmetic averages of the closing prices on the first day of each month during 2014 of $94.99 per Bbl of oil (first day of each month closing price for WTI less regional adjustments), $4.278 per Dth for Columbia Gas Transmission Corp., $3.191 per Dth for Dominion Transmission, Inc., $4.350 per Dth for the East Tennessee Natural Gas Pipeline, $3.258 per Dth for Texas Eastern Transmission Corp., $2.286 per Dth for the Tennessee, zone 4-300 Leg of Tennessee Gas Pipeline Company, $4.170 per Dth for the Tennessee LA 500 Leg of Tennessee Gas Pipeline Company, $4.152 per Dth for Waha, and $4.243 per Dth for Houston Ship Channel. For 2014, NGL pricing using arithmetic averages of the closing prices on the first day of each month during 2014 for NGL components and adjusted using the regional component makeup of produced NGLs resulted in prices of $49.22 per Bbl of NGLs from West Virginia Marcellus reserves in Doddridge, Ritchie, and Wetzel counties, $49.47 per Bbl of NGLs from certain Kentucky reserves, $47.11 per Bbl for Utica reserves, and $31.92 per Bbl for Permian reserves.
	For 2013, the reserves were computed using unweighted arithmetic averages of the closing prices on the first day of each month during 2013 of $89.22 per Bbl of oil (first day of each month closing price for WTI less regional adjustments), $3.653 per Dth for Columbia Gas Transmission Corp., $3.447 per Dth for Dominion Transmission, Inc., $3.693 per Dth for the East Tennessee Natural Gas Pipeline, $3.495 per Dth for Texas Eastern Transmission Corp., $2.842 per Dth for the Tennessee, zone 4-300 Leg of Tennessee Gas Pipeline Company and $3.521 per Dth for the Tennessee LA 500 Leg of Tennessee Gas Pipeline Company. For 2013, NGL pricing using arithmetic averages of the closing prices on the first day of each month during 2013 for NGL components and adjusted using the regional component makeup of produced NGLs resulted in prices of $51.91 per Bbl of NGLs from West Virginia Marcellus reserves in Doddridge, Ritchie, and Wetzel counties, $49.38 per Bbl of NGLs from certain Kentucky reserves, and $48.14 per Bbl for Utica 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:

	2015			2014			2013
	(Thousands)
Sales and transfers of natural gas and oil produced – net	$	(757,789	)	$	(1,479,242	)	$	(1,060,566	)
Net changes in prices, production and development costs	(5,566,232		)	(1,525,944		)	(292,533		)
Extensions, discoveries and improved recovery, less related costs	264,735			2,300,923			1,509,002
Development costs incurred	971,186			1,023,075			1,319,135
Purchase of minerals in place – net	—			72,139			348,608
Sale of minerals in place – net	(43		)	(146,476		)	(252		)
Revisions of previous quantity estimates	(1,541,419		)	(222,195		)	106,170
Accretion of discount	600,099			578,676			343,502
Net change in income taxes	2,424,200			(529,337		)	(1,031,105		)
Timing and other	(227,211		)	787,130			554,159
Net (decrease) increase	(3,832,474		)	858,749			1,796,120
Beginning of year	4,810,028			3,951,279			2,155,159
End of year	$	977,554		$	4,810,028		$	3,951,279