Oil and Natural Gas Operations (Unaudited) (Tables)

12 Months Ended

Dec. 31, 2015

Extractive Industries [Abstract]

Schedule of Capitalized Costs

The following table sets forth capitalized costs:

(in thousands)	December 31, 2015		December 31, 2014
Proved	$	7,911,554	$	8,069,638
Unproved	150,674		142,340
Total capitalized costs	8,062,228		8,211,978
Accumulated depreciation, depletion and amortization	3,673,569		2,663,434
Capitalized costs, net	$	4,388,659	$	5,548,544

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

The following table sets forth costs incurred in property acquisition, exploration and development activities and includes both capitalized costs and costs charged to expense during the year:

Years ended December 31, (in thousands)	2015		2014		2013
Property acquisition:
Proved	$	1,866	$	2,582	$	4,661
Unproved	85,690		68,514		26,820
Exploration	649,764		972,164		435,636
Development	372,177		408,949		655,353
Total costs incurred	$	1,109,497	$	1,452,209	$	1,122,470

Schedule of Results of Operations from Producing Activities

The following table sets forth results of Energen’s oil, natural gas liquids and natural gas operations from producing activities:

Years ended December 31, (in thousands)	2015			2014		2013
Gross revenues*	$	878,554		$	1,679,213	$	1,206,293
Production (lifting costs)	285,760			376,495		351,541
Exploration expense	14,877			28,090		14,036
Depreciation, depletion and amortization including asset impairments	1,880,190			960,539		463,606
Accretion expense	7,108			7,608		6,995
Income tax expense (benefit)	(469,362		)	99,469		128,773
Results of operations from producing activities	$	(840,019	)	$	207,012	$	241,342

* The years ended December 31, 2015, 2014 and 2013 gross revenues include a pre-tax non-cash mark-to-market loss on derivatives of $281.8 million, a pre-tax non-cash mark-to-market gain on derivatives of $315.4 million and a pre-tax non-cash mark-to-market loss on derivatives of $47.8 million, respectively.

Schedule of Proved Developed and Undeveloped Oil and Gas Reserves

The independent reservoir engineers have issued reports covering approximately 99 percent of Energen’s ending proved reserves indicating that in their judgment the estimates are reasonable in the aggregate.

Year ended December 31, 2015	Oil MBbl		NGL MBbl		Natural Gas MMcf		Total MMBOE
Proved reserves at beginning of period	181,227		73,463		707,926		372.7
Revisions of previous estimates	(39,537	)	(11,979	)	(44,176	)	(58.9	)
Purchases	2		1		2		—
Extensions and discoveries	83,319		25,530		143,022		132.6
Production	(14,023	)	(4,065	)	(35,604	)	(24.0	)
Sales	(297	)	(11,237	)	(337,266	)	(67.7	)
Proved reserves at end of period	210,691		71,713		433,904		354.7
Proved developed reserves at end of period	108,319		36,374		236,112		184.0
Proved undeveloped reserves at end of period	102,372		35,339		197,792		170.7

Year ended December 31, 2014	Oil MBbl		NGL MBbl		Natural Gas MMcf		Total MMBOE
Proved reserves at beginning of period	164,870		63,011		719,725		347.8
Revisions of previous estimates	(48,548	)	(15,165	)	(71,806	)	(75.7	)
Purchases	88		26		116		0.1
Extensions and discoveries	76,722		29,695		141,209		130
Production	(11,818	)	(4,104	)	(59,562	)	(25.8	)
Sales	(87	)	—		(21,756	)	(3.7	)
Proved reserves at end of period	181,227		73,463		707,926		372.7
Proved developed reserves at end of period	118,697		47,621		589,074		264.5
Proved undeveloped reserves at end of period	62,530		25,842		118,852		108.2

Year ended December 31, 2013	Oil MBbl		NGL MBbl		Natural Gas MMcf		Total MMBOE
Proved reserves at beginning of period	155,348		56,155		809,128		346.4
Revisions of previous estimates	(680	)	2,211		18,465		4.6
Purchases	142		56		282		0.2
Extensions and discoveries	20,517		7,823		50,568		36.8
Production	(10,378	)	(3,233	)	(70,506	)	(25.4	)
Sales	(79	)	(1	)	(88,212	)	(14.8	)
Proved reserves at end of period	164,870		63,011		719,725		347.8
Proved developed reserves at end of period	113,795		42,087		623,305		259.8
Proved undeveloped reserves at end of period	51,075		20,924		96,420		88.0

Schedule of Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves

Years ended December 31, (in thousands)	2015		2014		2013
Future gross revenues	$	11,714,729	$	20,971,672	$	19,509,305
Future production costs	4,353,974		7,532,273		6,136,709
Future development costs	1,961,661		1,784,738		1,896,602
Future income tax expense	1,065,887		3,440,582		3,209,697
Future net cash flows	4,333,207		8,214,079		8,266,297
Discount at 10% per annum	2,299,859		3,994,423		4,248,456
Standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves	$	2,033,348	$	4,219,656	$	4,017,841

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

The following are the principal sources of changes in the standardized measure of discounted future net cash flows:

Years ended December 31, (in thousands)	2015			2014			2013
Balance at beginning of year	$	4,219,656		$	4,017,841		$	3,699,319
Revisions to reserves proved in prior years:
Net changes in prices, production costs and future development costs	(2,861,591		)	(1,147,028		)	566,838
Net changes due to revisions in quantity estimates	(404,708		)	(1,285,394		)	(81,762		)
Development costs incurred, previously estimated	350,560			337,198			299,432
Accretion of discount	421,966			401,784			369,932
Changes in timing and other*	(903,975		)	987,652			(179,502		)
Total revisions	(3,397,748		)	(705,788		)	974,938
New field discoveries and extensions, net of future production and development costs	776,315			2,321,028			376,326
Sales of oil and gas produced, net of production costs	(514,380		)	(1,054,553		)	(1,014,593		)
Purchases	8			4,241			4,690
Sales	(372,039		)	(21,092		)	(24,876		)
Net change in income taxes	1,321,536			(342,021		)	2,037
Net change in standardized measure of discounted future net cash flows	(2,186,308		)	201,815			318,522
Balance at end of year	$	2,033,348		$	4,219,656		$	4,017,841

*Amount represents changes in production timing and other. In 2015, the production timing is significantly affected by changes related to the delay of the drilling program. For 2014, the production timing is significantly affected by changes related to the acceleration of the horizontal drilling program and the delay of the vertical drilling program.