Supplemental Oil and Natural Gas Data (Unaudited) (Tables)

12 Months Ended

Dec. 31, 2015

Oil and Gas Exploration and Production Industries Disclosures [Abstract]

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

Costs incurred in oil and natural gas property acquisition, exploration and development, whether capitalized or expensed, are presented below:

	Year Ended December 31,
	2015		2014		2013
	(in thousands)
Property acquisition costs: (1)
Proved	$	—	$	2,784,852	$	3,740,379
Unproved	—		788,682		1,638,302
Exploration costs	19,929		792		13,096
Development costs	430,357		1,487,204		1,153,770
Asset retirement costs	6,303		20,919		7,351
Total costs incurred	$	456,589	$	5,082,449	$	6,552,898

⁽¹⁾  See Note 2 for details about the Company’s acquisitions.

Capitalized Costs Relating to Oil, Natural Gas and NGL Producing Activities

Aggregate capitalized costs related to oil, natural gas and NGL production activities with applicable accumulated depletion and amortization are presented below:

	December 31,
	2015			2014
	(in thousands)
Proved properties:
Leasehold acquisition	$	13,361,171		$	13,362,642
Development	2,976,643			2,830,841
Unproved properties	1,783,341			1,875,417
	18,121,155			18,068,900
Less accumulated depletion and amortization	(11,097,492		)	(4,867,682		)
	$	7,023,663		$	13,201,218

Results of Operations for Oil and Gas Producing Activities

The results of operations for oil, natural gas and NGL producing activities (excluding corporate overhead and interest costs) are presented below:

	Year Ended December 31,
	2015			2014			2013
	(in thousands)
Revenues and other:
Oil, natural gas and natural gas liquids sales	$	1,726,271		$	3,610,539		$	2,073,240
Gains on oil and natural gas derivatives	1,056,189			1,206,179			177,857
	2,782,460			4,816,718			2,251,097
Production costs:
Lease operating expenses	617,764			805,164			372,523
Transportation expenses	219,721			207,331			128,440
Severance taxes, ad valorem taxes and California carbon allowances	181,941			267,100			139,202
	1,019,426			1,279,595			640,165
Other costs:
Exploration costs	9,473			125,037			5,251
Depletion and amortization	745,512			1,020,674			790,320
Impairment of long-lived assets	5,813,954			2,303,749			828,317
Gains on sale of assets and other, net	(198,924		)	(388,733		)	(138		)
Texas margin tax expense (benefit)	(2,789		)	4,053			458
	6,367,226			3,064,780			1,624,208
Results of operations	$	(4,604,192	)	$	472,343		$	(13,276	)

There is no federal tax provision included in the results above because the Company’s subsidiaries subject to federal tax do not own any of the Company’s oil and natural gas interests. Limited liability companies are subject to Texas margin tax. See Note 14 for additional information about income taxes.

Estimated Quantities of Oil, Natural Gas and NGL Reserves

An analysis of the change in estimated quantities of oil, natural gas and NGL reserves, all of which are located within the U.S., is shown below:

	Year Ended December 31, 2015
	Natural Gas (Bcf)		Oil (MMBbls)		NGL (MMBbls)		Total (Bcfe)
Proved developed and undeveloped reserves:
Beginning of year	4,255		341.8		166.3		7,304
Revisions of previous estimates	(1,404	)	(122.2	)	(40.4	)	(2,379	)
Sales of minerals in place	(13	)	(4.1	)	(2.0	)	(50	)
Extensions, discoveries and other additions	15		4.6		0.8		47
Production	(234	)	(22.8	)	(10.4	)	(434	)
End of year	2,619		197.3		114.3		4,488
Proved developed reserves:
Beginning of year	3,549		246.0		132.2		5,818
End of year	2,619		197.3		114.3		4,488
Proved undeveloped reserves:
Beginning of year	706		95.8		34.1		1,486
End of year	—		—		—		—

	Year Ended December 31, 2014
	Natural Gas (Bcf)		Oil (MMBbls)		NGL (MMBbls)		Total (Bcfe)
Proved developed and undeveloped reserves:
Beginning of year	3,010		365.6		200.0		6,403
Revisions of previous estimates	96		(22.3	)	(46.8	)	(318	)
Purchases of minerals in place	1,763		50.0		71.9		2,495
Sales of minerals in place	(477	)	(51.7	)	(49.5	)	(1,084	)
Extensions, discoveries and other additions	72		26.8		2.9		250
Production	(209	)	(26.6	)	(12.2	)	(442	)
End of year	4,255		341.8		166.3		7,304
Proved developed reserves:
Beginning of year	2,027		252.4		133.2		4,340
End of year	3,549		246.0		132.2		5,818
Proved undeveloped reserves:
Beginning of year	983		113.2		66.8		2,063
End of year	706		95.8		34.1		1,486

	Year Ended December 31, 2013
	Natural Gas (Bcf)		Oil (MMBbls)		NGL (MMBbls)		Total (Bcfe)
Proved developed and undeveloped reserves:
Beginning of year	2,571		191.5		179.4		4,796
Revisions of previous estimates	(17	)	(21.3	)	(2.0	)	(157	)
Purchases of minerals in place	356		191.1		17.8		1,610
Sales of minerals in place	(24	)	(5.2	)	(2.9	)	(73	)
Extensions, discoveries and other additions	286		21.7		18.5		527
Production	(162	)	(12.2	)	(10.8	)	(300	)
End of year	3,010		365.6		200.0		6,403
Proved developed reserves:
Beginning of year	1,661		131.4		113.0		3,127
End of year	2,027		252.4		133.2		4,340
Proved undeveloped reserves:
Beginning of year	910		60.1		66.4		1,669
End of year	983		113.2		66.8		2,063

The tables above include changes in estimated quantities of oil and NGL reserves shown in Mcf equivalents using the ratio of one barrel to six Mcf.

Standardized Measure of Discounted Future Net Cash Flows and Changes Therein Relating to Proved Reserves

Information with respect to the standardized measure of discounted future net cash flows relating to proved reserves is summarized below. Future cash inflows are computed by applying applicable prices relating to the Company’s proved reserves to the year-end quantities of those reserves. Future production, development, site restoration and abandonment costs are derived based on current costs assuming continuation of existing economic conditions. There are no future income tax expenses because the Company is not subject to federal income taxes. Limitedliability companies are subject to Texas margin tax; however, these amounts are not material. See Note 14 for additional information about income taxes.

	December 31,
	2015			2014			2013
	(in thousands)
Future estimated revenues	$	17,293,943		$	55,195,268		$	51,112,346
Future estimated production costs	(10,734,979		)	(24,100,468		)	(19,306,728		)
Future estimated development costs	(1,107,639		)	(4,032,588		)	(5,110,896		)
Future net cash flows	5,451,325			27,062,212			26,694,722
10% annual discount for estimated timing of cash flows	(2,417,780		)	(14,549,921		)	(14,795,393		)
Standardized measure of discounted future net cash flows	$	3,033,545		$	12,512,291		$	11,899,329
Representative NYMEX prices: (1)
Natural gas (MMBtu)	$	2.59		$	4.35		$	3.67
Oil (Bbl)	$	50.16		$	95.27		$	96.89

⁽¹⁾  In accordance with SEC regulations, reserves were estimated using the average price during the 12-month period, determined as an unweighted average of the first-day-of-the-month price for each month, excluding escalations based upon future conditions. The average price used to estimate reserves is held constant over the life of the reserves.

Principal Sources of Change in Standardized Measure of Discounted Future Net Cash Flow

The following table summarizes the principal sources of change in the standardized measure of discounted future net cash flows:

	Year Ended December 31,
	2015			2014			2013
	(in thousands)
Sales and transfers of oil, natural gas and NGL produced during the period	$	(706,845	)	$	(2,330,944	)	$	(1,433,075	)
Changes in estimated future development costs	1,501,593			156,614			317,064
Net change in sales and transfer prices and production costs related to future production	(9,309,151		)	(599,121		)	203,370
Purchases of minerals in place	—			3,021,768			5,113,335
Sales of minerals in place	(97,785		)	(1,681,504		)	(139,384		)
Extensions, discoveries and improved recovery	90,090			910,787			801,254
Previously estimated development costs incurred during the period	159,248			819,987			444,861
Net change due to revisions in quantity estimates	(1,633,958		)	(672,800		)	(220,224		)
Accretion of discount	1,251,229			1,189,933			607,298
Changes in production rates and other	(733,167		)	(201,758		)	131,849
	$	(9,478,746	)	$	612,962		$	5,826,348