OIL AND GAS OPERATIONS (Unaudited)

Capitalized Costs: The following table sets forth capitalized costs:



(in thousands)	December 31, 2013		December 31, 2012
Proved	$	7,043,779	$	6,241,148
Unproved	168,975		197,979
Total capitalized costs	7,212,754		6,439,127
Accumulated depreciation, depletion and amortization	2,078,411		1,765,241
Capitalized costs, net	$	5,134,343	$	4,673,886

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)	2013		2012		2011
Property acquisition:
Proved	$	4,661	$	79,862	$	214,993
Unproved	26,820		58,634		91,888
Exploration	435,636		419,284		190,854
Development	655,353		749,256		623,775
Total costs incurred	$	1,122,470	$	1,307,036	$	1,121,510

Results of Operations From Producing Activities: The following table sets forth results of the Company’s oil and gas operations from producing activities:



Years ended December 31, (in thousands)	2013		2012		2011
Gross revenues*	$	1,206,293	$	1,090,948	$	834,700
Production (lifting costs)	351,541		278,193		226,361
Exploration expense	27,942		19,356		12,967
Depreciation, depletion and amortization	449,700		339,569		210,532
Accretion expense	6,995		6,339		5,699
Income tax expense	128,773		160,551		134,564
Results of operations from producing activities	$	241,342	$	286,940	$	244,577

* The years ended December 31, 2013, 2012 and 2011 gross revenues include a pre-tax non-cash mark-to-market loss on derivatives of $47.8 million, a pre-tax non-cash mark-to-market gain on derivatives of $58.8 million and a pre-tax non-cash mark-to-market loss on derivatives of $37.6 million, respectively.

Oil and 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. Reserves and associated values were calculated using twelve-month average prices and current costs for the years ended December 31, 2013, 2012 and 2011. Changes to prices and costs could have a significant effect on the disclosed amount of reserves and their associated values. In addition, the estimation of 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 reserves disclosed. The proved reserves are located onshore in the United States of America.

Estimates of physical quantities of oil and gas proved reserves were determined by Company engineers. Ryder Scott Company, L.P. (Ryder Scott) and T. Scott Hickman and Associates, Inc. (T. Scott Hickman), independent oil and gas reservoir engineers, have audited the estimates of proved reserves of natural gas, oil and natural gas liquids that the Company has attributed to its net interests in oil and gas properties as of December 31, 2013. Ryder Scott audited the reserve estimates for coalbed methane in the San Juan basins and substantially all of the Permian Basin reserves. T. Scott Hickman audited the reserves for the North Louisiana and East Texas regions and the conventional reserves in the San Juan Basin. The independent reservoir engineers have issued reports covering approximately 98 percent of the Company’s ending proved reserves indicating that in their judgment the estimates are reasonable in the aggregate.



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



Year ended December 31, 2012	Gas MMcf		Oil MBbl		NGL MBbl		Total MMBOE
Proved reserves at beginning of period	957,368		129,578		53,957		343.1
Revisions of previous estimates	(143,704	)	(8,546	)	(9,557	)	(42.1	)
Purchases	10,656		7,950		2,569		12.4
Extensions and discoveries	61,170		35,132		11,759		57.1
Production	(76,362	)	(8,766	)	(2,573	)	(24.1	)
Proved reserves at end of period	809,128		155,348		56,155		346.4
Proved developed reserves at end of period	708,657		105,976		36,440		260.5
Proved undeveloped reserves at end of period	100,471		49,372		19,715		85.9



Year ended December 31, 2011	Gas MMcf		Oil MBbl		NGL MBbl		Total MMBOE
Proved reserves at beginning of period	954,387		103,262		40,601		302.9
Revisions of previous estimates	(12,823	)	(4,513	)	841		(5.8	)
Purchases	19,362		12,583		5,055		20.8
Extensions and discoveries	68,160		24,564		9,637		45.6
Production	(71,718	)	(6,318	)	(2,177	)	(20.4	)
Proved reserves at end of period	957,368		129,578		53,957		343.1
Proved developed reserves at end of period	788,812		83,899		33,154		248.5
Proved undeveloped reserves at end of period	168,556		45,679		20,803		94.6

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

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

2012 Activities: Energen Resources had downward reserve revisions during 2012 which totaled 42.1 MMBOE. The Black Warrior Basin had downward reserve revisions totaling 5.1 MMBOE of which approximately 5.9 MMBOE related to estimated negative price related revisions partially offset by better well performance. The San Juan Basin downward reserve revisions of 19.7 MMBOE included 22.5 MMBOE in negative price related revisions partially offset by better well performance, lower operating costs and lower fuel usage. Downward reserve revisions of 15.8 MMBOE in the Permian Basin were primarily due to lower than anticipated performance in certain development wells along with 1.0 MMBOE of estimated negative price related revisions.

Energen Resources purchased 12.4 MMBOE of reserves during 2012 primarily related to the acquisitions of oil properties in the Permian Basin.

During 2012, Energen Resources had extensions and discoveries of 57.1 MMBOE of which 59 percent were proved undeveloped reserves and 41 percent were proved developed reserves. Extension drilling resulted in 45.6 MMBOE of discoveries with exploratory drilling providing 11.5 MMBOE of discoveries. The San Juan Basin added 0.9 MMBOE of reserves through the drilling or identification of 6 well locations. The Permian Basin added 56.1 MMBOE of reserves primarily through the drilling or identification of 422 well locations.

2011 Activities: Energen Resources had downward reserve revisions during 2011 which totaled 5.8 MMBOE. The Black Warrior Basin had downward reserve revisions totaling 0.3 MMBOE of which approximately 0.7 MMBOE related to estimated negative price related revisions partially offset by other positive revisions of 0.4 MMBOE. The San Juan Basin downward reserve revisions of 2.6 MMBOE included 3.9 MMBOE in negative performance related revisions partially offset by 1.3 MMBOE related to estimated positive price related revisions. Downward reserve revisions of 3.1 MMBOE in the Permian Basin were primarily due to lower than anticipated injection response in certain waterflood units and other performance related adjustments. These downward revisions were partially offset by 1.4 MMBOE of estimated positive price related revisions.

Energen Resources purchased 20.8 MMBOE of reserves during 2011 primarily related to the acquisitions of oil properties in the Permian Basin.

During 2011, Energen Resources had extensions and discoveries of 45.6 MMBOE of which 69 percent were proved undeveloped reserves and 31 percent were proved developed reserves. Extension drilling resulted in 41.1 MMBOE of discoveries with exploratory drilling providing 4.5 MMBOE of discoveries. The San Juan Basin added 5.9 MMBOE of reserves through the drilling or identification of 53 well locations. The Permian Basin added 39.6 MMBOE of reserves primarily through the drilling or identification of 395 well locations.

Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and 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 the Company’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. At December 31, 2013, 2012 and 2011, the Company had a deferred hedging gain of $21.6 million, a deferred hedging gain of $74.8 million and a deferred hedging gain of $15 million, respectively, all of which are excluded from the calculation of standardized measure of future net cash flows.



Years ended December 31, (in thousands)	2013		2012		2011
Future gross revenues	$	19,509,305	$	17,735,363	$	18,196,229
Future production costs	6,136,709		5,715,248		5,823,395
Future development costs	1,896,602		1,892,600		1,539,072
Future income tax expense	3,209,697		2,809,411		3,326,382
Future net cash flows	8,266,297		7,318,104		7,507,380
Discount at 10% per annum	4,248,456		3,618,785		3,878,217
Standardized measure of discounted future net cash flows relating to proved oil and gas reserves	$	4,017,841	$	3,699,319	$	3,629,163

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



Years ended December 31, (in thousands)	2013			2012			2011
Balance at beginning of year	$	3,699,319		$	3,629,163		$	2,467,136
Revisions to reserves proved in prior years:
Net changes in prices, production costs and future development costs	566,838			(922,792		)	707,411
Net changes due to revisions in quantity estimates	(81,762		)	(383,755		)	(80,004		)
Development costs incurred, previously estimated	299,432			472,603			392,720
Accretion of discount	369,932			362,916			246,714
Changes in timing and other	(179,502		)	(317,244		)	(25,937		)
Total revisions	974,938			(788,272		)	1,240,904
New field discoveries and extensions, net of future production and development costs	376,326			1,025,419			755,977
Sales of oil and gas produced, net of production costs	(1,014,593		)	(812,781		)	(763,171		)
Purchases	4,690			189,755			232,768
Sales	(24,876		)	—			—
Net change in income taxes	2,037			456,035			(304,451		)
Net change in standardized measure of discounted future net cash flows	318,522			70,156			1,162,027
Balance at end of year	$	4,017,841		$	3,699,319		$	3,629,163