OIL AND GAS OPERATIONS (Unaudited)

Capitalized Costs: The following table sets forth capitalized costs:



(in thousands)	December 31, 2012		December 31, 2011
Proved	$	6,241,148	$	4,927,576
Unproved	197,979		238,792
Total capitalized costs	6,439,127		5,166,368
Accumulated depreciation, depletion and amortization	1,765,241		1,382,526
Capitalized costs, net	$	4,673,886	$	3,783,842

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)	2012		2011		2010
Property acquisition:
Proved	$	79,862	$	214,993	$	207,161
Unproved	58,634		91,888		201,881
Exploration	419,284		190,854		37,371
Development	749,256		623,775		332,541
Total costs incurred	$	1,307,036	$	1,121,510	$	778,954

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)	2012		2011		2010
Gross revenues*	$	1,167,183	$	944,908	$	957,371
Production (lifting costs)	306,375		257,045		224,901
Exploration expense	19,363		13,110		64,584
Depreciation, depletion and amortization	394,668		240,232		200,179
Accretion expense	7,534		6,837		6,178
Income tax expense	157,670		154,180		166,750
Results of operations from producing activities	$	281,573	$	273,504	$	294,779

*The years ended December 31, 2012, 2011 and 2010 gross revenues includes a pre-tax non cash mark-to-market gain on derivatives of $58.8 million, a pre-tax non-cash mark-to-market loss on derivatives of $37.6 million and a pre-tax non-cash mark-to-market loss on derivatives of $3,000, 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, 2012, 2011 and 2010. 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, 2012. Ryder Scott audited the reserve estimates for coalbed methane in the Black Warrior and 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 99 percent of the Company's ending proved reserves indicating that in their judgment the estimates are reasonable in the aggregate.



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



Year ended December 31, 2010	Gas MMcf		Oil MBbl		NGL MBbl		Total MMBOE
Proved reserves at beginning of period	897,546		77,963		30,257		257.8
Revisions of previous estimates	66,679		(2,243	)	2,434		11.3
Purchases	21,700		16,443		5,730		25.8
Extensions and discoveries	39,570		16,234		4,058		26.8
Production	(70,924	)	(5,131	)	(1,880	)	(18.8	)
Sales	(184	)	(4	)	2		—
Proved reserves at end of period	954,387		103,262		40,601		302.9
Proved developed reserves at end of period	786,292		72,030		28,809		231.9
Proved undeveloped reserves at end of period	168,095		31,232		11,792		71.0

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.

2010 Activities: Energen Resources had upward reserve revisions during 2010 which totaled 11.3 MMBOE. The Black Warrior Basin had upward reserve revisions totaling 0.6 MMBOE of which approximately 1.3 MMBOE related to changes in year-end pricing partially offset by downward reserve revisions of 0.7 MMBOE. The San Juan Basin upward reserve revisions of 11 MMBOE included 7.6 MMBOE related to changes in year-end pricing and 8.2 MMBOE associated with well performance partially offset by 5.3 MMBOE of downward reserve revisions resulting from the SEC’s five-year development rule. Downward reserve revisions of 1.3 MMBOE in the Permian Basin were due to lower than anticipated injection response in certain waterflood units offset by 3.0 MMBOE of estimated positive price related revisions.

Energen Resources purchased 25.8 MMBOE of reserves during 2010 primarily related to the acquisitions of oil properties in the Permian Basin.

During 2010, Energen Resources had extensions and discoveries of 26.8 MMBOE of which 77 percent were proved undeveloped reserves and 23 percent were proved developed reserves. Extension drilling resulted in 26.6 MMBOE of discoveries with exploratory drilling providing 0.3 MMBOE of discoveries. The San Juan Basin added 6.4 MMBOE of reserves through the drilling or identification of 36 well locations; additionally, 1 sidetrack well added 1.1 MMBOE of reserves. The Permian Basin added 22.1 MMBOE of reserves primarily through the drilling or identification of 271 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, 2012, 2011 and 2010, the Company had a deferred hedging gain of $74.8 million, a deferred hedging gain of $15 million and a deferred hedging loss of $70.4 million, respectively, all of which are excluded from the calculation of standardized measure of future net cash flows.



Years ended December 31, (in thousands)	2012		2011		2010
Future gross revenues	$	17,735,363	$	18,196,229	$	13,210,211
Future production costs	5,715,248		5,823,395		4,959,403
Future development costs	1,892,600		1,539,072		1,026,903
Future income tax expense	2,809,411		3,326,382		2,201,742
Future net cash flows	7,318,104		7,507,380		5,022,163
Discount at 10% per annum	3,618,785		3,878,217		2,555,027
Standardized measure of discounted future net cash flows relating to proved oil and gas reserves	$	3,699,319	$	3,629,163	$	2,467,136
Discounted future net cash flows before income taxes	$	4,411,399	$	4,691,086	$	3,155,746

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



Years ended December 31, (in thousands)	2012			2011			2010
Balance at beginning of year	$	3,629,163		$	2,467,136		$	1,563,190
Revisions to reserves proved in prior years:
Net changes in prices, production costs and future development costs	(922,792		)	707,411			945,179
Net changes due to revisions in quantity estimates	(383,755		)	(80,004		)	36,349
Development costs incurred, previously estimated	472,603			392,720			195,269
Accretion of discount	362,916			246,714			156,319
Changes in timing and other	(317,244		)	(25,937		)	15,815
Total revisions	(788,272		)	1,240,904			1,348,931
New field discoveries and extensions, net of future production and development costs	1,025,419			755,977			319,223
Sales of oil and gas produced, net of production costs	(812,781		)	(763,171		)	(576,755		)
Purchases	189,755			232,768			278,384
Sales	—			—			87
Net change in income taxes	456,035			(304,451		)	(465,924		)
Net change in standardized measure of discounted future net cash flows	70,156			1,162,027			903,946
Balance at end of year	$	3,699,319		$	3,629,163		$	2,467,136