OIL AND NATURAL GAS OPERATIONS (Unaudited)

Capitalized Costs: The following table sets forth capitalized costs:



(in thousands)	December 31, 2017		December 31, 2016
Proved	$	8,466,708	$	7,543,464
Unproved	453,028		196,888
Total capitalized costs	8,919,736		7,740,352
Accumulated depreciation, depletion and amortization	4,200,797		3,723,669
Capitalized costs, net	$	4,718,939	$	4,016,683

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)	2017		2016		2015
Property acquisition:
Proved*	$	9,889	$	4,066	$	1,866
Unproved	273,326		143,667		85,690
Exploration	676,357		349,463		649,764
Development	235,279		89,624		372,177
Total costs incurred	$	1,194,851	$	586,820	$	1,109,497

*Includes a $6.4 million noncash lawsuit settlement over certain leasehold interests.

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)	2017		2016			2015
Gross revenues*	$	961,045	$	532,889		$	878,554
Production (lifting costs)	243,144		214,652			285,760
Exploration expense	10,075		5,415			14,877
Depreciation, depletion and amortization including asset impairments	480,491		663,659			1,880,190
Accretion expense	5,831		6,672			7,108
Income tax expense (benefit)**	79,815		(123,153		)	(469,362		)
Results of operations from producing activities	$	141,689	$	(234,356	)	$	(840,019	)

* The years ended December 31, 2017, 2016 and 2015 gross revenues include pre-tax non-cash mark-to-market losses on derivatives of $10.8 million, $71.2 million and $281.8 million, respectively.

**Income tax benefit does not reflect any impact due to the enactment of the Tax Cuts and Jobs Act in 2017.

Oil and Natural Gas Reserves: 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, 2017, 2016 and 2015. 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 Company’s 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), 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, 2017. Ryder Scott audited the proved reserve estimates for substantially all of the Permian Basin proved 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, 2017	Oil MBbl		NGL MBbl		Natural Gas MMcf		Total MMBOE
Proved reserves at beginning of period	199,575		58,046		352,248		316.3
Revisions of previous estimates	7,903		14,853		102,107		39.8
Purchases	179		37		201		0.2
Extensions and discoveries	66,304		23,098		156,461		115.5
Production	(16,951	)	(5,255	)	(33,528	)	(27.8	)
Proved reserves at end of period	257,010		90,779		577,489		444.0
Proved developed reserves at end of period	143,907		52,882		342,616		253.9
Proved undeveloped reserves at end of period	113,103		37,897		234,873		190.1



Year ended December 31, 2016	Oil MBbl		NGL MBbl		Natural Gas MMcf		Total MMBOE
Proved reserves at beginning of period	210,691		71,713		433,904		354.7
Revisions of previous estimates	(17,840	)	(6,800	)	(7,779	)	(26.0	)
Purchases	103		21		89		0.1
Extensions and discoveries	45,129		10,480		50,780		64.1
Production	(13,213	)	(3,892	)	(27,204	)	(21.6	)
Sales	(25,295	)	(13,476	)	(97,542	)	(55.0	)
Proved reserves at end of period	199,575		58,046		352,248		316.3
Proved developed reserves at end of period	101,202		29,767		187,117		162.1
Proved undeveloped reserves at end of period	98,373		28,279		165,131		154.2



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		0.0
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

2017 Activities: Energen had net upward reserve revisions during 2017 which totaled 39.8 MMBOE and include upward revisions of approximately 11.6 MMBOE related to changes in year-end pricing, 17.6 MMBOE related to extending lateral length of certain locations, 12.0 MMBOE due to improved well performance and 3.0 MMBOE due to changes in plant yield. These were partially offset by net downward reserve revisions of 4.6 MMBOE of proved undeveloped reserves that will no longer be developed in the five-year time horizon.

Energen purchased 0.2 MMBOE of reserves during 2017 primarily related to the acquisition of oil properties in the Permian Basin.

During 2017, Energen had extensions and discoveries of 115.5 MMBOE of which 27 percent were proved undeveloped reserves and 73 percent were proved developed reserves. Extension drilling resulted in 0.6 MMBOE of discoveries with exploratory drilling providing 114.9 MMBOE of discoveries.

2016 Activities: Energen had net downward reserve revisions during 2016 which totaled 26.0 MMBOE including approximately 10.6 MMBOE related to changes in year-end pricing and downward revisions of approximately 22.9 MMBOE of proved undeveloped reserves that will no longer be developed in the five-year time horizon due to development being delayed to focus on other assets with higher returns. Net upward reserve revisions of 7.5 MMBOE due to factors other than price included increased lateral length, lower lease operating expense and improved well performance partially offset by changes in plant yields.

Energen purchased 0.1 MMBOE of reserves during 2016 primarily related to the acquisition of oil properties in the Permian Basin.

During 2016, Energen had extensions and discoveries of 64.1 MMBOE of which 65 percent were proved undeveloped reserves and 35 percent were proved developed reserves. Extension drilling resulted in no discoveries with exploratory drilling providing 64.1 MMBOE of discoveries.

During 2016, Energen had sales of 55.0 MMBOE primarily due to the sale of certain non-core Permian Basin assets in the Delaware Basin in Texas and in the San Juan Basin in New Mexico.

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.

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)	2017		2016		2015
Future gross revenues	$	15,531,237	$	9,191,808	$	11,714,729
Future production costs	4,467,989		3,126,153		4,353,974
Future development costs	2,077,918		1,632,577		1,961,661
Future income tax expense	1,381,999		762,921		1,065,887
Future net cash flows	7,603,331		3,670,157		4,333,207
Discount at 10% per annum	4,283,536		2,320,350		2,299,859
Standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves	$	3,319,795	$	1,349,807	$	2,033,348

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



Years ended December 31, (in thousands)	2017			2016			2015
Balance at beginning of year	$	1,349,807		$	2,033,348		$	4,219,656
Revisions to reserves proved in prior years:
Net changes in prices and production costs	659,802			(343,839		)	(3,101,283		)
Net changes in future development costs	(86,642		)	122,200			239,692
Net changes due to revisions in quantity estimates	389,684			(167,188		)	(404,708		)
Development costs incurred, previously estimated	148,534			71,099			350,560
Accretion of discount	149,664			203,335			542,105
Changes in timing and other*	257,523			(100,742		)	(1,024,114		)
Total revisions	1,518,565			(215,135		)	(3,397,748		)
New field discoveries and extensions, net of future production and development costs	1,492,562			352,358			776,315
Sales of oil and gas produced, net of production costs	(788,130		)	(440,446		)	(514,380		)
Purchases	3,769			1,733			8
Sales	—			(235,222		)	(372,039		)
Net change in income taxes	(256,778		)	(146,829		)	1,321,536
Net change in standardized measure of discounted future net cash flows	1,969,988			(683,541		)	(2,186,308		)
Balance at end of year	$	3,319,795		$	1,349,807		$	2,033,348

*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.