OIL AND GAS OPERATIONS (Unaudited)

Capitalized Costs: The following table sets forth capitalized costs:



(in thousands)	December 31, 2011		December 31, 2010
Proved	$	4,927,576	$	3,868,945
Unproved	238,792		211,834
Total capitalized costs	5,166,368		4,080,779
Accumulated depreciation, depletion and amortization	1,382,526		1,161,635
Capitalized costs, net	$	3,783,842	$	2,919,144

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)	2011		2010		2009
Property acquisition:
Proved	$	214,993	$	207,161	$	186,263
Unproved	91,888		201,881		5,100
Exploration	190,854		37,371		16,590
Development	623,775		332,541		226,841
Total costs incurred	$	1,121,510	$	778,954	$	434,794

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)	2011			2010		2009
Gross revenues	$	944,908	*	$	957,371	$	815,465
Production (lifting costs)	257,045			224,901		217,429
Exploration expense	13,110			64,584		10,234
Depreciation, depletion and amortization	240,232			200,179		180,752
Accretion expense	6,837			6,178		4,935
Income tax expense	154,180			166,750		143,691
Results of operations from producing activities	$	273,504		$	294,779	$	258,424

*The year ended December 31, 2011 gross revenues includes a pre-tax non-cash mark-to-market loss on derivatives of $37.6 million.

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, 2011, 2010 and 2009. 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, 2011. 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, 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



Year ended December 31, 2009	Gas MMcf		Oil MBbl		NGL MBbl		Total MMBOE
Proved reserves at beginning of period	1,038,453		62,034		28,953		264.1
Revisions of previous estimates	(122,862	)	1,175		(1,411	)	(20.7	)
Purchases	9,646		12,064		2,537		16.2
Extensions and discoveries	45,791		8,144		1,969		17.7
Production	(72,337	)	(4,690	)	(1,791	)	(18.5	)
Sales	(1,145	)	(764	)	—		(1.0	)
Proved reserves at end of period	897,546		77,963		30,257		257.8
Proved developed reserves at end of period	743,859		66,078		24,985		215.0
Proved undeveloped reserves at end of period	153,687		11,885		5,272		42.8

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, 1sidetrack 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.

2009 Activities: Energen Resources had downward reserve revisions during 2009 which totaled 20.7 MMBOE. The Black Warrior Basin had downward reserve revisions totaling 7.6 MMBOE of which approximately 3.4 MMBOE related to changes in year-end pricing and approximately 2.1 MMBOE was caused by accelerated coal mining plans. In the San Juan Basin, downward reserve revisions of 12.3 MMBOE were largely due to 11.7 MMBOE of estimated price revisions and higher fuel usage. Upward reserve revisions of 1.1 MMBOE in the Permian Basin were due to 4.2 MMBOE of estimated positive price related revisions partially offset by lower than anticipated injection response in certain waterflood units.

Energen Resources purchased 16.2 MMBOE of reserves during 2009 primarily related to the acquisition of oil properties in the Permian Basin.

During 2009, Energen Resources had extensions and discoveries of 17.7 MMBOE of which 81 percent were proved undeveloped reserves and 19 percent were proved developed reserves. Extension drilling resulted in 17.7 MMBOE of discoveries with exploratory drilling providing 0.1 MMBOE of discoveries. The San Juan Basin added 6.4 MMBOE of reserves through the drilling or identification of 46 well locations; additionally, 10 sidetrack wells added 1.1 MMBOE of reserves. The Permian Basin added 9.5 MMBOE of reserves primarily through the drilling or identification of 130 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, 2011, 2010 and 2009, the Company had a deferred hedging gain of $15 million, a deferred hedging loss of $70.4 million and a deferred hedging gain of $79.7 million, respectively, all of which are excluded from the calculation of standardized measure of future net cash flows.



Years ended December 31, (in thousands)	2011		2010		2009
Future gross revenues	$	18,196,229	$	13,210,211	$	8,208,613
Future production costs	5,823,395		4,959,403		3,915,736
Future development costs	1,539,072		1,026,903		533,674
Future income tax expense	3,326,382		2,201,742		944,875
Future net cash flows	7,507,380		5,022,163		2,814,328
Discount at 10% per annum	3,878,217		2,555,027		1,251,138
Standardized measure of discounted future net cash flows relating to proved oil and gas reserves	$	3,629,163	$	2,467,136	$	1,563,190
Discounted future net cash flows before income taxes	$	4,691,086	$	3,155,746	$	1,765,632

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



Years ended December 31, (in thousands)	2011			2010			2009
Balance at beginning of year	$	2,467,136		$	1,563,190		$	1,626,617
Revisions to reserves proved in prior years:
Net changes in prices, production costs and future development costs	707,411			945,179			(248,236		)
Net changes due to revisions in quantity estimates	(80,004		)	36,349			(117,990		)
Development costs incurred, previously estimated	392,720			195,269			140,169
Accretion of discount	246,714			156,319			162,662
Changes in timing and other	(25,937		)	15,815			97,142
Total revisions	1,240,904			1,348,931			33,747
New field discoveries and extensions, net of future production and development costs	755,977			319,223			81,954
Sales of oil and gas produced, net of production costs	(763,171		)	(576,755		)	(389,125		)
Purchases	232,768			278,384			116,435
Sales	—			87			(7,571		)
Net change in income taxes	(304,451		)	(465,924		)	101,133
Net change in standardized measure of discounted future net cash flows	1,162,027			903,946			(63,427		)
Balance at end of year	$	3,629,163		$	2,467,136		$	1,563,190