OIL AND NATURAL GAS OPERATIONS (Unaudited)

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

Costs Incurred: 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

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.

Oil and Natural Gas Operations: The calculation of proved reserves is made pursuant to rules prescribed by the SEC. Such rules, in part, require that proved categories of reserves be disclosed. Proved reserves and associated values were calculated using twelve-month average prices and current costs for the years ended December 31, 2015, 2014 and 2013. Changes to prices and costs could have a significant effect on the disclosed amount of proved reserves and their associated values. In addition, the estimation of proved reserves inherently requires the use of geologic and engineering estimates which are subject to revision as reservoirs are produced and developed and as additional information is available. Accordingly, the amount of actual future production may vary significantly from the amount of proved reserves disclosed. The proved reserves are located onshore in the United States of America.

Estimates of physical quantities of oil and natural gas proved reserves were determined by Company engineers. Ryder Scott Company, L.P. (Ryder Scott) and Hickman McClaine and Associates, Inc. (Hickman McClaine), independent oil and natural gas reservoir engineers, have audited the estimates of proved reserves of oil, natural gas liquids and natural gas that Energen has attributed to its net interests in oil and natural gas properties as of December 31, 2015. Ryder Scott audited the proved reserve estimates for coalbed methane in the San Juan Basin and substantially all of the Permian Basin proved reserves. Hickman McClaine audited the conventional proved reserves in the San Juan Basin. 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

2015 Activities: Energen had net downward reserve revisions during 2015 which totaled 58.9 MMBOE including negative revisions of approximately 38.0 MMBOE related to changes in year-end pricing and negative revisions of approximately 8.2 MMBOE of proved undeveloped reserves that are now expected to be drilled after the original five year period. Other negative revisions were 5.5 MMBOE due to increased declines in certain Wolfberry wells and 5.0 MMBOE of Wolfcamp reserves due to interference caused by our wellbore placement geometry.

During 2015, Energen had extensions and discoveries of 132.6 MMBOE, primarily in the Permian Basin, of which 78 percent were proved undeveloped reserves and 22 percent were proved developed reserves. Extension drilling resulted in 3.1 MMBOE of discoveries with exploratory drilling providing 129.5 MMBOE of discoveries.

During 2015, Energen had sales of 67.7 MMBOE primarily due to the sale of certain natural gas assets in the San Juan Basin.

2014 Activities: Energen had net downward reserve revisions during 2014 which totaled 75.7 MMBOE including downward revisions of approximately 53.4 MMBOE of proved undeveloped reserves that are now expected to be drilled after the original five year period and upward revisions of approximately 3.9 MMBOE related to changes in year-end pricing. The San Juan Basin had upward reserve revisions of 1.6 MMBOE including 4.4 MMBOE related to changes in year-end pricing and downward revisions of approximately 1.5 MMBOE due to higher operating costs. Net downward reserve revisions of 77.3 MMBOE in the Permian Basin were due to reclassifying 53.4 MMBOE as unproved because of changes in our development plans, downward revisions of approximately 13.3 MMBOE due to decreased well performance in certain Wolfberry wells, downward revisions of approximately 5.4 due to higher operating costs and approximately 0.5 MMBOE related to changes in the year-end pricing.

Energen purchased 0.1 MMBOE of reserves during 2014 primarily related to the acquisitions of oil properties in the Permian Basin.

During 2014, Energen had extensions and discoveries of 130.0 MMBOE of which 70 percent were proved undeveloped reserves and 30 percent were proved developed reserves. Extension drilling resulted in 89.6 MMBOE of discoveries with exploratory drilling providing 40.4 MMBOE of discoveries. The San Juan Basin added 1.1 MMBOE of reserves through the drilling or identification of 16 well locations and 10 pay adds. The Permian Basin added 128.6 MMBOE of reserves primarily through the drilling or identification of 361 well locations.

During 2014, Energen had sales of 3.7 MMBOE primarily due to the sale of the North Louisiana/East Texas primarily natural gas properties.

2013 Activities: Energen had upward reserve revisions during 2013 which totaled 4.6 MMBOE including approximately 7 MMBOE related to changes in year-end pricing and downward revisions of approximately 5.3 MMBOE of proved undeveloped reserves of which 4.6 MMBOE are expected to be drilled beyond five years with the remainder no longer expected to be drilled. The San Juan Basin upward reserve revisions of 2.2 MMBOE including 5.9 MMBOE related to changes in year-end pricing and downward revisions of approximately 4.6 MMBOE of proved undeveloped reserves that are expected to be drilled beyond five years. Net upward reserve revisions of 1.2 MMBOE in the Permian Basin were due to improved well performance in certain Wolfberry wells and approximately 0.4 MMBOE related to changes in the year-end pricing and downward revisions of approximately 0.7 MMBOE of proved undeveloped reserves that are no longer expected to be drilled.

Energen purchased 0.2 MMBOE of reserves during 2013 primarily related to the acquisitions of oil properties in the Permian Basin.

During 2013, Energen had extensions and discoveries of 36.8 MMBOE of which 45 percent were proved undeveloped reserves and 55 percent were proved developed reserves. Extension drilling resulted in 21.6 MMBOE of discoveries with exploratory drilling providing 15.2 MMBOE of discoveries. The San Juan Basin added 2.3 MMBOE of reserves through 30 pay adds. The Permian Basin added 34.4 MMBOE of reserves primarily through the drilling or identification of 262 well locations.

During 2013, Energen had sales of 14.8 MMBOE primarily due to the sale of the Black Warrior Basin coalbed methane properties.

Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Natural Gas Reserves: The standardized measure of discounted future net cash flows is not intended, nor should it be interpreted, to present the fair market value of Energen’s crude oil and natural gas reserves. An estimate of fair market value would take into consideration factors such as, but not limited to, the recovery of reserves not presently classified as proved reserves, anticipated future changes in prices and costs, and a discount factor more representative of the time value of money and the risks inherent in reserve estimates. Open mark-to-market derivatives applicable to future periods are excluded from the calculation of standardized measure of future net cash flows.



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

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.