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

12 Months Ended

Dec. 31, 2014

Oil and Gas Exploration and Production Industries Disclosures [Abstract]

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

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

	Successor				Predecessor
	Year Ended December 31, 2014		December 17, 2013 through December 31, 2013		January 1, 2013 through December 16, 2013		Year Ended December 31, 2012
(in thousands)
Property acquisition costs:
Proved	$	478,311	$	—	$	3,457	$	70,700
Unproved	—		—		463		10,686
Exploration costs	148		—		868		16,405
Development costs	555,629		22,266		577,568		696,095
Asset retirement costs	6,064		—		15,998		18,248
Total costs incurred (1)	$	1,040,152	$	22,266	$	598,354	$	812,134

⁽¹⁾  The total above does not reflect approximately $6 million, $41,000, $6 million and $18 million of capitalized interest incurred for the year ended December 31, 2014, for the periods from December 17, 2013 through December 31, 2013, and January 1, 2013 through December 16, 2013, and for the year ended December 31, 2012, respectively.

Capitalized Costs Relating to Oil and Gas Producing Activities Disclosure

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

	December 31,
	2014			2013
	(in thousands)
Oil and natural gas:
Proved properties	$	4,025,595		$	3,397,785
Unproved properties	846,464			1,415,874
	4,872,059			4,813,659
Less accumulated depletion and amortization	(525,007		)	(10,394		)
	$	4,347,052		$	4,803,265

Results of Operations for Oil and Gas Producing Activities Disclosure

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

	Successor					Predecessor
	Year Ended December 31, 2014		December 17, 2013 through December 31, 2013			January 1, 2013 through December 16, 2013			Year Ended December 31, 2012
(in thousands)
Revenues and other:
Oil, natural gas and natural gas liquid sales	$	1,298,402	$	50,324		$	1,103,245		$	937,261
Gains (losses) on oil and natural gas derivatives	78,784		(5,049		)	(34,711		)	64,620
	1,377,186		45,275			1,068,534			1,001,881
Production costs:
Lease operating expenses	364,540		15,410			295,811			232,266
Transportation expenses	41,842		2,576			46,774			39,531
Severance taxes, ad valorem taxes and California carbon allowances	97,683		2,130			57,063			39,374
	504,065		20,116			399,648			311,171
Other costs:
Exploration costs	—		—			24,048			21,010
Depletion and amortization	294,107		10,612			275,927			224,836
Impairment of long-lived assets	253,362		—			—			—
(Gains) losses on sale of assets and other, net	112,303		10,208			(23		)	(1,782		)
	659,772		20,820			299,952			244,064
Income tax expense	69		—			65,280			88,121
Results of operations	$	213,280	$	4,339		$	303,654		$	358,525

Schedule of Proved Developed and Undeveloped Oil and Gas Reserve Quantities

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

	Successor
	Year Ended December 31, 2014
	Oil MBbls		Natural Gas MMcf		Total MBOE
Total proved reserves:
Beginning of year	187,362		280,117		234,048
Revisions of previous estimates	(10,647	)	42,514		(3,561	)
Extensions, discoveries and other additions	20,435		35,552		26,360
Purchases of minerals in place	22,533		408,857		90,676
Sales of minerals in place	(41,216	)	(51,065	)	(49,727	)
Production	(14,065	)	(28,938	)	(18,888	)
End of year	164,402		687,037		278,908
Proved developed reserves	119,039		552,184		211,069
Proved undeveloped reserves	45,363		134,853		67,839
Total proved reserves	164,402		687,037		278,908

	Successor						Predecessor
	December 17, 2013 through December 31, 2013						January 1, 2013 through December 16, 2013
	Oil MBbls		Natural Gas MMcf		Total MBOE		Oil MBbls		Natural Gas MMcf		Total MBOE
Total proved reserves:
Beginning of period	187,892		280,943		234,715		204,208		425,519		275,129
Revisions of previous estimates	—		—		—		(13,536	)	(153,330	)	(39,092	)
Extensions, discoveries and other additions	—		—		—		10,955		29,756		15,913
Sales of minerals in place	—		—		—		(2,263	)	(3,071	)	(2,775	)
Production	(530	)	(826	)	(667	)	(11,472	)	(17,931	)	(14,460	)
End of period	187,362		280,117		234,048		187,892		280,943		234,715
Proved developed reserves	121,694		202,798		155,494		122,224		203,624		156,161
Proved undeveloped reserves	65,668		77,319		78,554		65,668		77,319		78,554
Total proved reserves	187,362		280,117		234,048		187,892		280,943		234,715

	Predecessor
	Year Ended December 31, 2012
	Oil MBbls		Natural Gas MMcf		Total MBOE
Total proved reserves:
Beginning of year	185,880		534,279		274,926
Revisions of previous estimates	12,145		(205,845	)	(22,162	)
Extensions, discoveries and other additions	8,459		100,129		25,148
Purchases of minerals in place	8,304		16,740		11,094
Sales of minerals in place	(556	)	—		(556	)
Production	(10,024	)	(19,784	)	(13,321	)
End of year	204,208		425,519		275,129
Proved developed reserves	118,937		187,668		150,216
Proved undeveloped reserves	85,271		237,851		124,913
Total proved reserves	204,208		425,519		275,129

The tables above include changes in estimated quantities of natural gas reserves shown in BOE equivalents at a rate of six Mcf per one barrel.

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

The future income tax expenses gave effect to income tax deductions, credits and allowances relating to the proved oil and natural gas reserves.

	Successor						Predecessor
	December 31, 2014			December 31, 2013			December 31, 2012
(in thousands)
Future estimated revenues	$	16,844,678		$	17,863,984		$	19,738,729
Future estimated production costs	(7,742,035		)	(6,654,536		)	(5,884,891		)
Future estimated development costs	(1,132,807		)	(1,854,849		)	(2,164,780		)
Future estimated income tax expense	—			—			(3,344,024		)
Future net cash flows	7,969,836			9,354,599			8,345,034
10% annual discount for estimated timing of cash flows	(3,639,459		)	(4,719,267		)	(4,511,619		)
Standardized measure of discounted future net cash flows	$	4,330,377		$	4,635,332		$	3,833,415
Representative NYMEX prices: (1)
Oil (Bbl)	$	95.27		$	96.89		$	90.66
Natural gas (MMBtu)	4.35			3.67			2.88

⁽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.

Schedule of Changes in Standardized Measure of Discounted Future Net Cash Flows

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

	Successor
	December 31, 2014
(in thousands)
Standardized measure—beginning of year	$	4,635,332
Sales and transfers of oil, natural gas and NGL produced during the period	(794,337		)
Changes in estimated future development costs	68,290
Net change in sales and transfer prices and production costs related to future production	(1,020,605		)
Extensions, discoveries and improved recovery	674,392
Purchases of minerals in place	548,256
Sales of minerals in place	(486,903		)
Previously estimated development costs incurred during the period	269,473
Net change due to revisions in quantity estimates	(66,696		)
Accretion of discount	463,533
Changes in production rates and other	39,642
Net decrease	(304,955		)
Standardized measure—end of year	$	4,330,377

	Successor			Predecessor
	December 17, 2013 through December 31, 2013			January 1, 2013 through December 16, 2013
(in thousands)
Standardized measure—beginning of period	$	3,558,595		$	3,833,415
Sales and transfers of oil, natural gas and NGL produced during the period	(30,208		)	(703,597		)
Changes in estimated future development costs	—			20,932
Net change in sales and transfer prices and production costs related to future production	(1,272		)	(214,489		)
Extensions, discoveries and improved recovery	—			189,625
Sales of minerals in place	—			(13,279		)
Previously estimated development costs incurred during the period	—			401,791
Net change due to revisions in quantity estimates	—			(856,118		)
Accretion of discount	19,184			496,718
Income taxes	1,109,522			237,117
Changes in production rates and other	(20,489		)	166,480
Net increase (decrease)	1,076,737			(274,820		)
Standardized measure—end of period	$	4,635,332		$	3,558,595

	Predecessor
	December 31, 2012
(in thousands)
Standardized measure—beginning of year	$	4,035,279
Sales and transfers of oil, natural gas and NGL produced during the period	(625,707		)
Changes in estimated future development costs	(331,498		)
Net change in sales and transfer prices and production costs related to future production	(786,022		)
Extensions, discoveries and improved recovery	124,466
Purchases of minerals in place	114,094
Sales of minerals in place	(15,283		)
Previously estimated development costs incurred during the period	497,036
Net change due to revisions in quantity estimates	743
Accretion of discount	570,505
Income taxes	323,128
Changes in production rates and other	(73,326		)
Net decrease	(201,864		)
Standardized measure—end of year	$	3,833,415