8-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 8-K

CURRENT REPORT

Pursuant to Section 13 or 15(d)

of the Securities Exchange Act of 1934

Date of Report

February 11, 2016

Commission File Number	Registrant	State of Incorporation	IRS Employer Identification Number
1-7810	Energen Corporation	Alabama	63-0757759

605 Richard Arrington Jr. Boulevard North Birmingham, Alabama	35203
(Address of principal executive offices)	(Zip Code)

(205) 326-2700

(Registrant’s telephone number including area code)

Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions:

¨ Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)

¨ Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)

¨ Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))

¨ Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c))

ITEM 2.02 Results of Operations and Financial Condition

On February 11, 2016, Energen Corporation issued a press release announcing the fourth quarter and year-to-date financial results. The press release and supplemental financial information are attached hereto as Exhibit 99.1 and 99.2.

The information furnished pursuant to Item 2.02, including Exhibits 99.1 and 99.2, shall not be deemed “filed” for purposes of Section 18 of the Securities Exchange Act of 1934, as amended (the “Exchange Act”) or otherwise subject to the liabilities under that Section and shall not be deemed to be incorporated by reference into any filing of Energen Corporation under the Securities Act of 1933 or the Exchange Act.

ITEM 7.01 Regulation FD Disclosure

Energen Corporation has included reconciliations of certain Non-GAAP financial measures to the related GAAP financial measures. The reconciliations are attached hereto as exhibit 99.3.

The information furnished pursuant to Item 7.01, including Exhibit 99.3, shall not be deemed “filed” for purposes of Section 18 of the Exchange Act or otherwise subject to the liabilities under that Section and shall not be deemed to be incorporated by reference into any filing of Energen Corporation under the Securities Act of 1933 or the Exchange Act.

ITEM 9.01 Financial Statements and Exhibits

(d) Exhibits.

The following exhibits are furnished as part of this Current Report on Form 8-K.

Exhibit Number:
99.1	Press Release dated February 11, 2016
99.2	Supplemental Financial Information
99.3	Non-GAAP Financial Measures Reconciliation

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SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

	ENERGEN CORPORATION
February 12, 2016	By	/s/ Charles W. Porter, Jr.
	Charles W. Porter, Jr.
	Vice President, Chief Financial Officer and Treasurer of Energen Corporation

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EXHIBIT INDEX

EXHIBIT NUMBER		DESCRIPTION
99.1	*	Press Release dated February 11, 2016
99.2	*	Supplemental Financial Information
99.3	*	Non-GAAP Financial Measures Reconciliation

* This exhibit is furnished to, but not filed with, the Commission by inclusion herein.

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EX-99.1

Exhibit 99.1

For Release: 4:30 p.m. ET	Contacts:	Julie S. Ryland
Thursday, February 11, 2016		205.326.8421

ENERGEN’S FIRST JO MILL WELLS TRACKING 1,200 MBOE EUR TYPE CURVE

Company Plans to Exit San Juan Basin and Sell Other Non-Core Assets in Delaware Basin

Focus on Capital Discipline, Expense Reductions in 2016

Highlights

• 340 net engineered Jo Mill and Middle Spraberry locations added to company’s Midland Basin inventory

• Revised unrisked potential drilling inventory supports net potential of more than 2 billion BOE in Permian Basin

• Identified asset sales in San Juan and Delaware basins could bolster 2016 cash flows by estimated $400 million

• Horizontal well production in Midland Basin in 2015 increased 248% year-over-year

• Energen to be pure Permian Basin operator after exiting San Juan Basin

• Adjusting prior year for 1Q15 sale of San Juan Basin assets, YE15 proved reserves increased 16% to 355 MMBOE

• 2016 plans call for 47 net horizontal well completions in Midland Basin; year-over-year production essentially flat

• With modest price recovery later in year, Energen sees running three rigs during 2H16

• Cost-cutting measures estimated to decrease recurring G&A expense in 2016 by 25%

BIRMINGHAM, Alabama – For the 3 months ended December 31, 2015, Energen Corporation (NYSE: EGN) reported a GAAP net loss from all operations of $(590.8) million, or $(7.50) per diluted share. Excluding mark-to-market derivatives losses, commodity price-driven impairments, and pension settlement charges, Energen’s adjusted income in the 4th quarter of 2015 totaled $21.3 million, or $0.27 per diluted share. This compares with adjusted income from continuing operations in the 4th quarter of 2014 of $38.2 million, or $0.52 per diluted share. The variance between the periods largely is attributable to lower realized commodity prices and higher depreciation, depletion, and amortization expense (DD&A) associated with increased drilling activity and the impact of lower year-end commodity prices, partially offset by increased production, lower lease operating, marketing and transportation expenses (LOE), and lower production and ad valorem taxes. [See “Non-GAAP Financial Measures” beginning on pp 13 for more information and reconciliation.]

Energen’s adjusted EBITDAX totaled $205.0 million in the 4th quarter of 2015 and compared with adjusted EBITDAX from continuing operations in the same period last year of $208.6 million. [See “Non-GAAP Financial Measures” beginning on pp 13 for more information and reconciliation.]

Relative to internal expectations, Energen’s adjusted 4Q15 earnings were negatively affected by a 4^th quarter DD&A adjustment that totaled $0.17 per share and was driven by the impact on reserves of low commodity prices at year end. Otherwise, Energen’s adjusted 4Q15 earnings would have been $0.44 per diluted share. In addition, the impact of slightly below-budget production was more than offset by decreased LOE and ad valorem, production and other taxes, greater-than-expected realized oil prices, lower exploration expense, and less net salaries and general and administrative expense (G&A).

Production in 4Q15 fell just short of the company’s guidance midpoint for a number of reasons, including the underperformance of primarily Wolfcamp B wells in a select area near the Glasscock/Reagan county line where higher gas rates and lower oil rates were encountered, weather-related impacts, and the timing of flow back of 4^th quarter development wells; these factors were partially offset by continued strong production from 3rd Bone Spring and Wolfcamp wells in the Delaware Basin.

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2016 Capital and Production Summary

Energen plans to invest approximately $250-$350 million of drilling and development capital in 2016. At recent strip oil prices for the year approximating $36 per barrel, the low end of the range reflects capital investment to hold the company’s acreage in the Delaware and Midland basins and to complete 47 gross (47 net) horizontal wells in the Midland Basin, including 46 gross (46 net) wells that were drilled but uncompleted (DUC) at YE15.

If oil prices increase later in the year, Energen likely would invest capital at the higher end of the range in order to resume drilling in the Midland Basin.

The company anticipates funding the estimated gap between capital investment and after-tax cash flows of approximately $225-$325 million with proceeds from the sale of non-core assets in the San Juan and Delaware basins in 2016. After-tax cash flows will include a working capital adjustment of $(79.0) million related to accrued capital at YE15.

Being largely unhedged, the company’s debt-to-EBITDAX ratio is highly sensitive to changes in oil prices. At average 2016 oil prices of $40 per barrel, and assuming the sale of non-core assets for cash proceeds of approximately $400 million, Energen’s capital investment of $250 million would result in an estimated total debt-to-EBITDAX multiple at YE16 of approximately 2.5.

2016 Capital Summary

	2016e Capital		Wells to be Drilled		Wells to be Completed
	($MM)		Operated Gross (Net)		Operated Gross (Net)
Midland Basin	$	197		7 (7)		52 (52)
Delaware Basin	$	41		4 (4)		4 (4)
Other	$	3
Net Carry/ARO/ Other	$	5
Drilling & Development Capital	$	246

Energen’s capital plan includes approximately $168 million for completion of 46 gross (46 net) DUCs in the Midland Basin and another $6.6 million to drill and complete a Lower Spraberry well needed to finish a pad. Approximately $48 million will be invested to drill 6 gross (6 net) vertical Wolfberry wells in the Midland Basin and 4 gross (4 net) Wolfcamp shale wells in the Delaware Basin to hold leases. Another $17 million will be invested in other drilling- and development-related activities such as facilities and non-operated drilling, including $10 million in the Midland Basin and $5 million in the Delaware Basin.

2016 Production Guidance

Production in 2016 is estimated to be essentially flat relative to 2015, as 25 percent production growth from horizontal drilling and development activities in the Midland Basin is offset by natural declines in the vertical Wolfberry, the 3^rd Bone Spring sands in the Delaware Basin, and the Central Basin Platform.

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Excluding production from the planned sales of non-core assets in the San Juan and Delaware basins, the company estimates that production in 2016 will range from 19.5-20.3 MMBOE, or 53,280-55,465 boepd. The guidance midpoint is 19.9 MMBOE, or 54,437 boepd. With DUC completions scheduled to occur in the first half of the year, 2016 production is expected to peak in 3Q16. Energen’s 4Q16 exit rate is estimated to be 51,370 boepd, or 12 percent less than the comparable 4Q15 exit rate of 58,457 boepd.

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Production by Product, Pro Forma to Exclude Planned Sales of Non-Core Assets

	2016e Guidance Midpoint				2015				Change from Midpoint
	(mmboe)		(boepd)		(mmboe)		(boepd)
Oil		12.6		34,508		13.4		36,616		(6	)%
Natural Gas Liquids		3.5		9,612		3.3		8,981		7	%
Natural Gas		3.8		10,317		3.6		9,797		5	%
Total		19.9		54,437		20.2		55,397		(2	)%

NOTE: Totals may not sum due to rounding

Production by Play, Pro Forma to Exclude Planned Sales of Non-Core Assets

	2016e Guidance Midpoint				2015				Change % From Midpoint
	(mmboe)		(boepd)		(mmboe)		(boepd)
Midland Basin		12.5		34,068		11.6		31,644		8	%
Horizontal		9.3		25,333		7.4		20,260		25	%
Vertical		3.2		8,735		4.2		11,384		(23	)%
Delaware Basin		4.0		11,019		5.1		13,935		(21	)%
Other		3.4		9,350		3.5		9,819		(5	)%
Total		19.9		54,437		20.2		55,397		(2	)%

NOTE: Totals may not sum due to rounding

Plans to Monetize Non-Core Assets Announced

Energen plans to sell the remainder of its San Juan Basin assets in 2016 along with other non-core assets in the Delaware Basin. The company estimates that proceeds from these asset sales could total $400 million.

Approximately 70 percent of the company’s assets in the San Juan Basin were sold in March 2015. The remaining assets are primarily natural gas production with upside potential in the Mancos oil play. Energen decided to exit the San Juan Basin after assessing the early performance of exploratory wells it drilled in 2015 to test the oil play’s potential on portions of its acreage. The company concluded that these assets do not compete with its high-quality assets in the Midland and Delaware basins.

In addition to exiting the San Juan Basin, Energen is marketing select, non-core assets in the eastern Delaware Basin in Texas. Sales processes are under way.

As a pure Permian Basin operator, Energen will focus on its high-quality assets in the Midland and Delaware basins.

Cost-cutting Measures Implemented as Oil Prices Drop

Energen has implemented a variety of cost-cutting measures, including a workforce reduction, in response to the dramatic drop in oil prices. Additional savings will occur with the disposition of the company’s remaining San Juan Basin assets.

G&A expenses (excluding pension settlement charges and severance payments) are estimated to decrease 25 percent year-over-year in 2016 to approximately $89 million.

Other measures taken to enhance capital discipline include the recent decision to discontinue paying the company’s cash dividend.

5

Updated Permian Basin Inventory Identifies Net Potential of >2 Billion BOE

Energen’s updated, unrisked potential drilling inventory of horizontal locations in the Permian Basin at year-end 2015 totals 4,440. Of that amount, 2,504 net locations are in the Midland Basin, and 1,936 net locations are in the Delaware Basin. The company estimates that the associated net undeveloped resource potential is more than 1 billion BOE in each basin. [See inventory and spacing slides at www.energen.com]

Adjustments to Energen’s inventory included the addition of 340 net Jo Mill and Middle Spraberry locations in the Midland Basin along with the identification of 477 net locations with 10,000’ lateral lengths in the Midland Basin and 143 net locations in the Delaware Basin with an average lateral length of 9,700’. The inventory also was adjusted for locations drilled in 2015.

Potential drilling locations are engineered based on the company’s existing acreage and spacing plans and may change over time as the company and offset operators drill wells in each target zone. The updated potential inventory excludes eastern Delaware Basin assets that are targeted for sale in 2016.

Wolfcamp, Spraberry Drilling Drives Total Proved Reserve Additions of  ≈132 MMBOE

Energen’s proved reserves at year-end 2015 totaled 355 MMBOE. This reflected only a 5 percent decrease from 2014 even though the company lost 58 MMBOE primarily due to substantially lower commodity prices and another 68 MMBOE due to the sale of proved reserves in the San Juan Basin in March 2015. Adjusting 2014 year-end proved reserves just for the 1Q15 San Juan Basin divestiture, proved reserves at year-end 2015 would have increased 16 percent.

Wolfcamp and Spraberry drilling in the Midland and Delaware basins was the dominant driver of total proved reserve additions of approximately 132 MMBOE, which replaced 2015 production by 550 percent. Proved oil reserves increased 17 percent in 2015 and represent 59 percent of total proved reserves. Approximately 52 percent of Energen’s total proved reserves are proved developed.

Commodity prices used for calculating reserves at year-end 2015 were substantially lower than those at year-end 2014. WTI oil prices declined 47 percent to $50.28 per barrel, while NGL prices (before transportation and fractionation) declined 45 percent to 41 cents per gallon and Henry Hub natural gas prices dropped 40 percent to $2.59 per thousand cubic feet (Mcf).

Proved Reserves by Basin (MMBOE)

Basin	YE14		2015 Production			2015 Acquisitions/ (Divestitures)			2015 Additions		2015 Price/Other Revisions			YE15
Permian		280.8		(20.7	)		(0.1	)		128.6		(51.7	)		337.0
San Juan Basin		90.9		(3.3	)		(67.6	)		3.5		(6.6	)		16.9
Other		1.0		(0.0	)		(0.1	)		0.1		(0.2	)		0.8
TOTAL		372.7		(24.0	)		(67.7	)		132.2		(58.4	)		354.7

NOTE: Totals may not sum due to rounding

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Proved Reserves by Commodity (MMBOE)

Commodity	2015		2014		% Change
Oil		211		181		17
Natural gas liquids		72		73		(1	)
Natural gas		72		119		(39	)
TOTAL		355		373		(5	)

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YE2015 3P Reserves & Contingent Resources (MMBOE)

Basin	Proved		Probable		Possible		Contingent Resources		Total
Midland Basin		225		87		194		846		1,352
Delaware Basin		70		6		18		1,359		1,452
Central Basin Platform		42		2		1		1		45
San Juan Basin/Other		18		1		12		278		309
TOTAL		355		95		226		2,483		3,159
Non-core assets for sale (included above)
Delaware Basin		25		0		0		375		400
San Juan Basin		17		1		12		278		308

NOTE: Totals may not sum due to rounding

The definitions of probable and possible reserves imply different probabilities of potential recovery in each classification; the quantities reported here are unrisked and based on the Company’s estimate of current costs to drill wells in each basin/area and bring associated production to market. [See Cautionary Statements on page 12].

Energen’s First Jo Mill Wells Highlight 4Q15 Appraisal Program Results

Energen’s latest appraisal wells in the Midland Basin were highlighted by the company’s first two Jo Mill tests –impressive wells that are tracking at or above a 1.2 million BOE type curve. Drilled in Martin County, these wells had an average peak 24-hour IP of 1,062 boepd and an average peak 30-day average rate of 943 boepd, and were approximately 75 percent oil.

Another highlight was the company’s test of the Lower Spraberry in Glasscock County north of its first Lower Spraberry well. With a 10,000’ lateral length, the Daniel SN 7-6 04 #504H generated a 24-hour IP of 1,460 boepd (74% oil) and a peak, 30-day average rate of 1,213 boepd (70% oil). The company also drilled wells east and west of its first Lower Spraberry well; while results were not as strong as the Daniel well, these are solid wells that will be good additions to the Glasscock County development program in a higher commodity price environment.

In northern Midland County, the company drilled a Wolfcamp A test well that confirmed the positive results of the B-bench well drilled at that location earlier in 2015. [See locator maps and graphs of the cumulative oil production of Jo Mill, Middle Spraberry, and Lower Spraberry wells over time at www.energen.com].

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Midland Basin (3-Stream Results)

Well Name	Zone/ County	Lateral length (ft)				Frac Stages		Peak 24-Hour IP								Peak 30-day Avg.
		Drilled*		Completed				Boepd		%Oil		%NGL		%Gas		Boepd		%Oil		%NGL		%Gas
JO MILL
Jones Holton #807H	Martin		7,501		7,137		34		1,137		76		15		9		1,032		75		15		10
Jones Holton #811H	Martin		7,476		7,048		33		987		74		16		10		853		72		18		10
LOWER SPRABERRY SHALE
Daniel SN 7-6 04 #504H	Glasscock		10,309		9,896		46		1,460		74		16		10		1,213		70		19		11
WOLFCAMP A
L.B. Epley NS 39-36 06 #106H	Midland		6,476		6,469		31		948		69		18		13		712		72		16		12

* Represents distance from vertical departure to toe

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Midland Basin Development Program Results

Development program wells drilled in 4Q15 (gross/net)	19/19
Development program wells completed in 4Q15 (gross/net)	2/2
Development program wells awaiting completion at end of 4Q15 (gross/net)	48/48

In its 2-well, pad-drilling development program in Glasscock County, Energen tested 15 Wolfcamp A and B wells with lateral lengths of 7,500 feet during 4Q15. These wells generated average peak 24-hour IP rates (3-stream) of 1,242 boepd (83% oil) and peak 30-day average rates (3-stream) of 875 boepd (71% oil).

Since the development program’s inception in 2014, Energen has tested 90 gross (87 net) wells that generated average peak 24-hour IPs (3-stream) of 1,002 boepd (80% oil) and peak 30-day average rates (3-stream) of 754 boepd (71% oil).

[See updated Glasscock County Wolfcamp A/B type curve, normalized to 7,500’, at www.energen.com].

4th Quarter Financial Review

Reconciliation of Consolidated GAAP Net Income to Adjusted Income from Continuing Operations

[See “Non-GAAP Financial Measures” beginning on pp 13 for more information]

	4Q15						4Q14
	$M			$/dil. sh.			$M			$/dil. sh.
Net Income/(Loss) All Operations (GAAP)	$	(590,806	)	$	(7.50	)	$	65,418		$	0.89
Less: Non-cash mark-to-market gains/(losses)		(66,984	)		(0.85	)		167,315			2.28
Less: Asset impairments, dry hole expenses		(528,145	)		(6.70	)		(141,945	)		(1.94	)
Less: Pension and pension settlement expenses		(16,884	)		(0.21	)		(3,558	)		(0.05	)
Less: Income/(loss) associated w/ San Juan Basin divestment		(65	)		0.00			6,522			0.09
Less: Gain/(loss) discontinued operations		—			—			(1,101	)		(0.02	)
Adj. Income Continuing Operations (Non-GAAP)	$	21,272		$	0.27		$	38,185		$	0.52

Note: Per share amounts may not sum due to rounding

Asset impairments in 4Q15 reflect price-driven write downs of proved properties, primarily in the San Juan and Delaware basins, and a write down to fair value of unproved leasehold in the San Juan Basin (which has been designated as “held for sale” at year-end 2015). Pension and pension settlement expenses relate to the termination and subsequent distribution of benefits of Energen’s qualified defined pension plan and non-qualified supplemental retirement plans. The bulk of these expenses occurred in 4Q15.

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Production from Continuing Operations

(excludes production associated with 1Q15 San Juan divestiture)

Commodity	4Q15				4Q14				Change
	(mboe)		(boepd)		(mboe)		(boepd)
Oil		3,584		38,957		3,209		34,880		12	%
NGL		1,078		11,717		879		9,554		23	%
Natural Gas		1,305		14,185		1,033		11,228		26	%
Total		5,967		64,859		5,121		55,663		17	%

Note: Totals may not sum due to rounding

11

Production from Continuing Operations

(excludes production associated with 1Q15 San Juan divestiture)

Area	4Q15				4Q14				Change
	(mboe)		(boepd)		(mboe)		(boepd)
Midland Basin		3,305		35,924		2,237		24,315		48	%
Wolfcamp/Spraberry		2,347		25,511		1,095		11,902		114	%
Wolfberry		958		10,413		1,142		12,413		(16	)%
Delaware Basin		1,346		14,630		1,435		15,598		(6	)%
3rd Bone Spring/Other		921		10,010		1,135		12,337		(19	)%
Wolfcamp		425		4,620		300		3,261		42	%
Central Basin Platform		845		9,185		966		10,500		(13	)%
Total Permian Basin		5,496		59,739		4,638		50,413		18	%
San Juan Basin/Other		471		5,120		483		5,250		(2	)%
Total		5,967		64,859		5,121		55,663		17	%

Note: Totals may not sum due to rounding

Average Realized Sales Prices from Continuing Operations

(excludes production associated with 1Q15 San Juan divestiture)

Commodity	4Q15		4Q14		Change
Oil (per barrel)	$	71.43	$	81.86		(13	)%
NGL (per gallon)	$	0.27	$	0.62		(56	)%
Natural Gas (per Mcf)	$	3.65	$	4.10		(11	)%

Average Prices from Continuing Operations Before Effects of Hedges

(excludes production associated with 1Q15 San Juan divestiture)

Commodity	4Q15		4Q14		Change
Oil (per barrel)	$	39.20	$	65.98		(41	)%
NGL (per gallon)	$	0.27	$	0.48		(44	)%
Natural Gas (per Mcf)	$	1.92	$	3.54		(46	)%

Expenses from Continuing Operations and Excluding San Juan Basin Assets sold 1Q15

(per BOE, except interest expense)

Expenses	4Q15		4Q14		Change
LOE*	$	8.79	$	11.74		(25	)%
Production & ad valorem taxes	$	1.94	$	3.48		(44	)%
DD&A	$	26.54	$	26.47		0	%
Net G&A†	$	4.78	$	4.61		4	%
Interest ($MM)	$	10.0	$	10.4		(4	)%

* Production costs + workovers and repairs + marketing and transportation

† Excludes $4.40 per BOE in 4Q15 and $1.08 per BOE in 4Q14 for pension and pension settlement expenses

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4th Quarter Comparisons, 2015 vs 2014 (excluding San Juan Basin assets sold March 31, 2015)

• The success of Energen’s Wolfcamp development program drove a 114 percent increase in production from horizontal plays in the Midland Basin and more than offset natural declines in the vertical Wolfberry.

• The company’s average realized oil price fell 13 percent to $71.43 per barrel, while the realized price of NGL dropped 56 percent. Excluding the impact of commodity and differential hedges, average realized prices declined more than 40 percent for oil, NGL, and natural gas.

• LOE per unit declined 25 percent to $8.79 per barrel largely due to lower workover and repair expense, and lower water disposal and gathering system costs.

• Per-unit net G&A expense of $4.78 per BOE (excluding pension and pension settlement expenses) increased 4 percent from the same period a year ago primarily due to increased performance-based compensation.

2015 Financial Review

For the 12 months ended December 31, 2015, Energen reported a GAAP net loss from all operations of $(945.7) million, or $(12.43) per diluted share. Excluding mark-to-market derivatives losses, commodity price-related impairments, and pension settlement charges, Energen’s adjusted income in 2015 totaled $64.5 million, or $0.85 per diluted share. This compares with adjusted income from continuing operations in 2014 of $135.8 million, or $1.85 per diluted share.

The variance between the periods largely is attributable to lower realized commodity prices and higher DD&A associated with increased drilling activity and the impact of lower prices at year-end, partially offset by increased production, lower LOE, lower production and ad valorem taxes, and decreased exploration expense. [See “Non-GAAP Financial Measures” beginning on pp 13 for more information and reconciliation.]

Energen’s adjusted 2015 EBITDAX totaled $739.8 million as compared with adjusted EBITDAX from continuing operations in 2014 of $762.9 million. [See “Non-GAAP Financial Measures” beginning on pp 13 for more information and reconciliation.]

Reconciliation of Consolidated GAAP Net Income to Adjusted Income from Continuing Operations

[See “Non-GAAP Financial Measures” beginning on pp 13 for more information]

	2015						2014
	$M			$/dil. sh.			$M			$/dil. sh.
Net Income/(Loss) All Operations (GAAP)	$	(945,731	)	$	(12.43	)	$	568,032		$	7.75
Less: Non-cash mark-to-market gains/(losses)		(181,251	)		(2.38	)		201,790			2.75
Less: Asset impairments, dry hole expenses		(830,957	)		(10.92	)		(263,189	)		(3.59	)
Less: Pension and pension settlement expenses		(20,148	)		(0.26	)		(12,179	)		(0.17	)
Less: Income/(loss) associated w/ San Juan Basin divestment		22,076			0.29			37,378			0.51
Less: Gain/(loss) discontinued operations		—			—			468,389			6.39
Adj. Income Continuing Operations (Non-GAAP)	$	64,549		$	0.85		$	135,843		$	1.85

Note: Per share amounts may not sum due to rounding

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Production from Continuing Operations

(excludes production associated with 1Q15 San Juan divestiture)

Commodity	2015				2014				Change
	(mboe)		(boepd)		(mboe)		(boepd)
Oil		14,022		38,416		11,798		32,323		19	%
NGL		3,926		10,756		3,408		9,337		15	%
Natural Gas		4,587		12,567		3,891		10,660		18	%
Total		22,535		61,740		19,097		52,321		18	%

Note: Totals may not sum due to rounding

Production from Continuing Operations

(excludes production associated with 1Q15 San Juan divestiture)

Area	2015				2014				Change
	(mboe)		(boepd)		(mboe)		(boepd)
Midland Basin		11,550		31,644		7,405		20,288		56	%
Wolfcamp/Spraberry		7,395		20,260		2,127		5,827		248	%
Wolfberry		4,155		11,384		5,278		14,460		(21	)%
Delaware Basin		5,566		15,249		5,907		16,184		(6	)%
3rd Bone Spring/Other		3,765		10,315		4,694		12,860		(20	)%
Wolfcamp		1,801		4,934		1,213		3,323		48	%
Central Basin Platform		3,548		9,721		3,986		10,921		(11	)%
Total Permian Basin		20,664		56,614		17,298		47,392		19	%
San Juan Basin/Other		1,871		5,126		1,799		4,929		4	%
Total		22,535		61,740		19,097		52,321		18	%

Note: Totals may not sum due to rounding

Average Realized Sales Prices from Continuing Operations

(excludes production associated with 1Q15 San Juan divestiture)

Commodity	2015		2014			Change
Oil (per barrel)	$	69.75	$	84.09			(17	)%
NGL (per gallon)	$	0.29	$	0.70			(59	)%
Natural Gas (per Mcf)	$	3.73	$	3.39	*		10	%

* Prior period hedges were left unallocated for current-year San Juan Basin divestiture; as reported last year, the average realized sales price of natural gas in 2014 was $4.32 per Mcf.

14

Average Prices from Continuing Operations Before Effects of Hedges

(excludes production associated with 1Q15 San Juan divestiture)

Commodity	2015		2014		Change
Oil (per barrel)	$	45.05	$	83.72		(46	)%
NGL (per gallon)	$	0.29	$	0.66		(56	)%
Natural Gas (per Mcf)	$	2.19	$	3.96		(45	)%

15

Expenses from Continuing Operations and Excluding San Juan Basin Assets sold 1Q15

(per BOE, except interest expense)

Expenses	2015		2014		Change
LOE*	$	9.49	$	11.24		(16	)%
Production & ad valorem taxes	$	2.46	$	4.55		(46	)%
DD&A	$	25.73	$	25.55		1	%
Net G&A†	$	5.25	$	5.52		(5	)%
Interest ($MM)	$	43.1	$	37.8		14	%

* Production costs + workovers and repairs + marketing and transportation

† Excludes $1.39 per BOE in CY15 and $0.99 per BOE in CY14 for pension and pension settlement expenses

Liquidity Update

As of December 31, 2015, Energen had borrowings (net of cash) of $221.2 million on its line of credit, for total liquidity available on its $1.4 billion borrowing base of $1.18 billion. Long-term debt at the end of December totaled $553.6 million. Total debt-to-2015 adjusted EBITDAX was approximately 1.0 at YE15. [See “Non-GAAP Financial Measures” beginning on pp 13 for more information and reconciliation.]

Capital

Drilling and development capital in 2015 totaled $1.0 billion, with total capital investment of $1.1 billion, including approximately $0.1 billion for the acquisition of proved and unproved leasehold, primarily in the Permian Basin.

1Q16 and CY16 Financial Guidance

Energen’s estimated expenses, pro forma for planned sales of non-core assets:

Per BOE, except where noted	1Q16	CY16
LOE (production costs, marketing & transportation)	$10.00-$10.40	$9.50 - $9.90*
Production & ad valorem taxes (% of revenues, excluding hedges)	10.3%	8.9%
DD&A expense	$22.60-$23.10	$23.25-$23.85
General & administrative expense, net†	$5.00-$5.60	$4.10-$4.80
Exploration expense (seismic, delay rentals, etc.)	$0.30-$0.35	$0.30-$0.35
Interest expense ($MM)	$10.0-$11.0	$38.7-$39.7
FF&E depreciation ($MM)	$1.1-$1.6	$5.0-$5.5
Accretion of discount on ARO ($MM)	$1.2-$1.8	$6.0-$6.5
Effective tax rate (%)	35%-37%	34%-36%

* LOE in the Midland Basin is estimated to range from $6.10-$6.60 in CY16

† Excludes $1.36 per BOE in 1Q16 and $0.39 per BOE in CY16 for pension and pension settlement and severance expenses.

16

Production by Commodity/Quarter, Pro Forma to Exclude Planned Sales of Non-Core Assets

Commodity	1Q16 Guidance Midpoint				2016e Guidance Midpoint
	(mmboe)		(boepd)		(mmboe)		(boepd)
Oil		3.0		32,945		12.6		34,508
NGL		0.9		9,637		3.5		9,612
Gas		1.0		10,462		3.8		10,317
Total Production		4.9		53,044		19.9		54,437

NOTE: Totals may not sum due to rounding

1Q16 Hedge Position

Commodity	Hedge Volumes	Production @ Midpoint	Hedge %	NYMEXe Price
Oil	0.3 mmbo	3.0 mmbo	9	$	63.80 barrel
Natural Gas	1.2 bcf	5.7 bcf	21	$	2.49 per mcf

CY16 Hedge Position

Commodity	Hedge Volumes	Production @ Midpoint	Hedge %	NYMEXe Price
Oil	1.1 mmbo	12.6 mmbo	9	$	63.80 barrel
Natural Gas	6.6 bcf	22.7 bcf	29	$	2.47 per mcf

In the tables above, basin-specific contract prices for natural gas have been converted for comparability purposes to a NYMEX-equivalent price by adding to them Energen’s assumed basis differentials.

Average realized oil and gas prices for Energen’s production associated with NYMEX contracts as well as for unhedged production will reflect the impact of basis differentials; average realized oil prices also will reflect estimated 1Q16 and CY16 oil transportation charges of $2.60 per barrel and $2.55 per barrel, respectively; and average realized NGL prices will be net of transportation and fractionation fees that are estimated to average $0.12 per gallon in 1Q16 and CY16.

The company also has hedges in place to limit its exposure to the Midland to Cushing differential. For 1Q16 and CY16, Energen has hedged the WTS Midland to WTI Cushing (sour oil) differential for 0.5 million barrels and 2.1 million barrels of oil production, respectively, at an average price of $(1.63) per barrel; WTI Midland to WTI Cushing (sweet oil) differential hedges in 1Q16 and CY16 are for 1.9 million barrels and 7.5 million barrels, respectively, at an average price of $(1.92) per barrel.

17

Approximately 75 percent and 77 percent of Energen’s estimated oil production in 1Q16 and CY16, respectively, will be sweet oil. Gas basis assumptions for all open contracts (February-December) are $(0.17) per Mcf.

Estimated Price Realizations (pre-hedge):

	1Q16			CY16
Crude oil (% of NYMEX/WTI)		87	%		90	%
Natural gas (% of NYMEX/Henry Hub)		79	%		81	%
NGL (after T&F) (% of NYMEX/WTI)		30	%		28	%

Energen’s assumed commodity prices for unhedged production in 2016 are $36.33 per barrel of oil (February-December), $0.38 per gallon of NGL (February-December), and $2.39 per Mcf of gas (March-December). Assumed prices for unhedged Midland to Cushing basis differentials for sweet and sour oil (March-December) are $(0.30) and $(0.41), respectively.

Given Energen’s modest hedge position in 2016, its cash flows and earnings are highly sensitive to changes in commodity prices. Relative to the company’s price assumptions: every $1.00 per barrel change in the price of oil is estimated to impact the company’s cash flows by approximately $11.3 million; every $0.01 per gallon change in the average price of NGL is estimated to have an impact of approximately $1.2 million; and every $0.10 per Mcf change in the price of natural gas is estimated to have an impact of approximately $950,000.

18

Conference Call

Energen will hold its quarterly conference call Friday, February 12, at 11:00 a.m. EDT. Members of the investment community may participate by calling 1-877-407-8289 (reference Energen earnings call). A live audio Webcast of the program as well as a replay may be accessed through Web site, www.energen.com.

Energen Corporation is an oil and gas exploration and production company with headquarters in Birmingham, Alabama. At year-end 2015, the company had 355 million barrels of oil-equivalent proved reserves and another 2.8 billion barrels of oil-equivalent probable and possible reserves and contingent resources. These all-domestic reserves and resources are located primarily in the Permian Basin in west Texas. For more information, go to http://www.energen.com.

FORWARD LOOKING STATEMENTS: All statements, other than statements of historical fact, appearing in this release constitute forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995. These forward-looking statements include, among other things, statements about our expectations, beliefs, intentions or business strategies for the future, statements concerning our outlook with regard to the timing and amount of future production of oil, natural gas liquids and natural gas, price realizations, the nature and timing of capital expenditures for exploration and development, plans for funding operations and drilling program capital expenditures, the timing and success of specific projects, operating costs and other expenses, proved oil and natural gas reserves, liquidity and capital resources, outcomes and effects of litigation, claims and disputes and derivative activities. Among other forward-looking statements in this release are statements regarding our intention to engage in certain assets sales and the estimated proceeds thereof. These sales processes are at preliminary stages, and we do not have binding agreements for any transactions; as a result, the estimate of proceeds from these transactions is preliminary and may not be realized. Our ability to consummate any transactions and their timing are subject to market conditions and other factors, and we may not be able to consummate these transactions at all or for the net proceeds we are estimating.

Forward-looking statements may include words such as “anticipate”, “believe”, “could”, “estimate”, “expect”, “forecast”, “foresee”, “intend”, “may”, “plan”, “potential”, “predict”, “project”, “seek”, “will” or other words or expressions concerning matters that are not historical facts. These statements involve certain risks and uncertainties that may cause actual results to differ materially from expectations as of the date of this news release. Except as otherwise disclosed, the forward-looking statements do not reflect the impact of possible or pending acquisitions, investments, divestitures or restructurings. The absence of errors in input data, calculations and formulas used in estimates, assumptions and forecasts cannot be guaranteed. We base our forward-looking statements on information currently available to us, and we undertake no obligation to correct or update these statements whether as a result of new information, future events or otherwise. Additional information regarding our forward-looking statements and related risks and uncertainties that could affect future results of Energen, can be found in the Company’s periodic reports filed with the Securities and Exchange Commission and available on the Company’s website - www.energen.com.

CAUTIONARY STATEMENTS: The SEC permits oil and gas companies to disclose in SEC filings only proved, probable and possible reserves that meet the SEC’s definitions for such terms, and price and cost sensitivities for such reserves, and prohibits disclosure of resources that do not constitute such reserves. Outside of SEC filings, we use the terms “estimated ultimate recovery” or “EUR,” reserve or resource “potential,” “contingent resources” and other descriptions of volumes of non-proved reserves or resources potentially recoverable through additional drilling or recovery techniques. These estimates are inherently more speculative than estimates of proved reserves and are subject to substantially greater risk of actually being realized. We have not risked EUR estimates, potential drilling locations, and resource potential estimates. Actual locations drilled and quantities that may be ultimately recovered may differ substantially from estimates. We make no commitment to drill all of the drilling locations that have been attributed these quantities. Factors affecting ultimate recovery include the scope of our on-going drilling program, which will be directly affected by the availability of capital, drilling, and production costs, availability of drilling and completion services and equipment, drilling results, lease expirations, regulatory approvals, and geological and mechanical factors. Estimates of unproved reserves, type/decline curves, per-well EURs, and resource potential may change significantly as development of our oil and gas assets provides additional data. Additionally, initial production rates contained in this news release are subject to decline over time and should not be regarded as reflective of sustained production levels.

Financial, operating, and support data pertaining to all reporting periods included in this release are

unaudited and subject to revision.

19

EX-99.2

Exhibit 99.2

CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)

For the 3 months ending December 31, 2015 and 2014

	4th Quarter
(in thousands, except per share data)	2015			2014			Change
Revenues
Oil, natural gas liquids and natural gas sales	$	167,751		$	286,747		$	(118,996	)
Gain on derivative instruments, net		25,048			325,521			(300,473	)
Total revenues		192,799			612,268			(419,469	)
Operating Costs and Expenses
Oil, natural gas liquids and natural gas production		52,447			74,571			(22,124	)
Production and ad valorem taxes		11,597			20,961			(9,364	)
Depreciation, depletion and amortization		159,784			148,996			10,788
Asset impairment		825,918			235,301			590,617
Exploration		2,604			6,872			(4,268	)
General and administrative		54,794			28,553			26,241
Accretion of discount on asset retirement obligations		1,729			1,958			(229	)
(Gain) loss on sale of assets and other		(524	)		833			(1,357	)
Total operating costs and expenses		1,108,349			518,045			590,304
Operating Income (Loss)		(915,550	)		94,223			(1,009,773	)
Other Income (Expense)
Interest expense		(10,022	)		(10,397	)		375
Other income		80			134			(54	)
Total other expense		(9,942	)		(10,263	)		321
Income (Loss) From Continuing Operations Before Income Taxes		(925,492	)		83,960			(1,009,452	)
Income tax expense (benefit)		(334,686	)		17,441			(352,127	)
Income (Loss) From Continuing Operations		(590,806	)		66,519			(657,325	)
Discontinued Operations, net of tax
Loss from discontinued operations		—			(1,143	)		1,143
Gain on disposal of discontinued operations, net		—			42			(42	)
Loss From Discontinued Operations		—			(1,101	)		1,101
Net Income (Loss)	$	(590,806	)	$	65,418		$	(656,224	)
Diluted Earnings Per Average Common Share
Continuing operations	$	(7.50	)	$	0.91		$	(8.41	)
Discontinued operations		—			(0.02	)		0.02
Net Income (Loss)	$	(7.50	)	$	0.89		$	(8.39	)
Basic Earnings Per Average Common Share
Continuing operations	$	(7.50	)		0.91		$	(8.41	)
Discontinued operations		—			(0.01	)		0.01
Net Income (Loss)	$	(7.50	)	$	0.90		$	(8.40	)
Diluted Avg. Common Shares Outstanding		78,783			73,343			5,440
Basic Avg. Common Shares Outstanding		78,783			72,988			5,795
Dividends Per Common Share	$	0.02		$	0.02		$	0.0

CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)

For the 12 months ending December 31, 2015 and 2014

	Year-to-date
(in thousands, except per share data)	2015			2014			Change
Revenues
Oil, natural gas liquids and natural gas sales	$	763,261		$	1,344,194		$	(580,933	)
Gain on derivative instruments, net		115,293			335,019			(219,726	)
Total revenues		878,554			1,679,213			(800,659	)
Operating Costs and Expenses
Oil, natural gas liquids and natural gas production		228,380			274,432			(46,052	)
Production and ad valorem taxes		57,380			102,063			(44,683	)
Depreciation, depletion and amortization		593,789			548,564			45,225
Asset impairment		1,292,308			416,801			875,507
Exploration		14,878			28,090			(13,212	)
General and administrative		149,132			122,052			27,080
Accretion of discount on asset retirement obligations		7,108			7,608			(500	)
(Gain) loss on sale of assets and other		(26,570	)		2,642			(29,212	)
Total operating costs and expenses		2,316,405			1,502,252			814,153
Operating Income (Loss)		(1,437,851	)		176,961			(1,614,812	)
Other Income (Expense)
Interest expense		(43,108	)		(37,771	)		(5,337	)
Other income		223			1,181			(958	)
Total other expense		(42,885	)		(36,590	)		(6,295	)
Income (Loss) From Continuing Operations Before Income Taxes		(1,480,736	)		140,371			(1,621,107	)
Income tax expense (benefit)		(535,005	)		40,728			(575,733	)
Income (Loss) From Continuing Operations		(945,731	)		99,643			(1,045,374	)
Discontinued Operations, net of tax
Income from discontinued operations		—			29,292			(29,292	)
Gain on disposal of discontinued operations, net		—			439,097			(439,097	)
Income From Discontinued Operations		—			468,389			(468,389	)
Net Income (Loss)	$	(945,731	)	$	568,032		$	(1,513,763	)
Diluted Earnings Per Average Common Share
Continuing operations	$	(12.43	)	$	1.36		$	(13.79	)
Discontinued operations		—			6.39			(6.39	)
Net Income (Loss)	$	(12.43	)	$	7.75		$	(20.18	)
Basic Earnings Per Average Common Share
Continuing operations	$	(12.43	)	$	1.37		$	(13.80	)
Discontinued operations		—			6.42			(6.42	)
Net Income (Loss)	$	(12.43	)	$	7.79		$	(20.22	)
Diluted Avg. Common Shares Outstanding		76,078			73,275			2,803
Basic Avg. Common Shares Outstanding		76,078			72,897			3,181
Dividends Per Common Share	$	0.08		$	0.47		$	(0.39	)

CONSOLIDATED BALANCE SHEETS (UNAUDITED)

As of December 31, 2015 and December 31, 2014

(in thousands)	December 31, 2015		December 31, 2014
ASSETS
Current Assets
Cash and cash equivalents	$	1,272	$	1,852
Accounts receivable, net		63,097		157,678
Inventories		11,255		14,251
Assets held for sale		93,739		395,797
Derivative instruments		56,963		322,337
Prepayments and other		20,014		27,445
Total current assets		246,340		919,360
Property, Plant and Equipment
Oil and natural gas properties, net		4,302,332		5,152,748
Other property and equipment, net		48,358		46,389
Total property, plant and equipment, net		4,350,690		5,199,137
Other postretirement assets		3,881		—
Other assets		12,782		19,761
TOTAL ASSETS	$	4,613,693	$	6,138,258
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current Liabilities
Accounts payable	$	64,742	$	101,453
Accrued taxes		5,801		5,530
Accrued wages and benefits		28,563		21,553
Accrued capital costs		79,206		207,461
Revenue and royalty payable		60,493		72,047
Liabilities related to assets held for sale		12,789		24,230
Pension liabilities		15,685		24,609
Deferred income taxes		—		79,164
Derivative instruments		459		988
Other		19,783		23,288
Total current liabilities		287,521		560,323
Long-term debt		776,087		1,038,563
Asset retirement obligations		89,990		94,060
Pension and other postretirement liabilities		—		15,935
Deferred income taxes		552,369		1,000,486
Other long-term liabilities		11,866		14,287
Total liabilities		1,717,833		2,723,654
Total Shareholders’ Equity		2,895,860		3,414,604
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY	$	4,613,693	$	6,138,258

SELECTED BUSINESS SEGMENT DATA (UNAUDITED)

For the 3 months ending December 31, 2015 and 2014

	4th Quarter
(in thousands, except sales price and per unit data)	2015			2014			Change
Operating and production data from continuing operations
Oil, natural gas liquids and natural gas sales
Oil	$	140,505		$	211,916		$	(71,411	)
Natural gas liquids		12,240			20,293			(8,053	)
Natural gas		15,006			54,538			(39,532	)
Total	$	167,751		$	286,747		$	(118,996	)
Open non-cash mark-to-market gains (losses) on derivative instruments
Oil	$	(92,484	)	$	230,490		$	(322,974	)
Natural gas liquids		—			(1,316	)		1,316
Natural gas		(11,586	)		32,286			(43,872	)
Total	$	(104,070	)	$	261,460		$	(365,530	)
Closed gains (losses) on derivative instruments
Oil	$	115,519		$	50,945		$	64,574
Natural gas liquids		—			4,990			(4,990	)
Natural gas		13,599			8,126			5,473
Total	$	129,118		$	64,061		$	65,057
Total revenues	$	192,799		$	612,268		$	(419,469	)
Production volumes
Oil (MBbl)		3,584			3,213			371
Natural gas liquids (MMgal)		45.3			43.1			2.2
Natural gas (MMcf)		7,830			14,646			(6,816	)
Total production volumes (MBOE)		5,967			6,681			(714	)
Average daily production volumes
Oil (MBbl/d)		39.0			34.9			4.1
Natural gas liquids (MMgal/d)		0.5			0.5			—
Natural gas (MMcf/d)		85.1			159.2			(74.1	)
Total average daily production volumes (MBOE/d)		64.9			72.6			(7.7	)
Average realized prices excluding effects of open non-cash mark-to-market derivative instruments
Oil (per barrel)	$	71.44		$	81.81		$	(10.37	)
Natural gas liquids (per gallon)	$	0.27		$	0.59		$	(0.32	)
Natural gas (per Mcf)	$	3.65		$	4.28		$	(0.63	)
Average realized prices excluding effects of all derivative instruments
Oil (per barrel)	$	39.20		$	65.96		$	(26.76	)
Natural gas liquids (per gallon)	$	0.27		$	0.47		$	(0.20	)
Natural gas (per Mcf)	$	1.92		$	3.72		$	(1.80	)
Costs per BOE
Oil, natural gas liquids and natural gas production expenses	$	8.79		$	11.16		$	(2.37	)
Production and ad valorem taxes	$	1.94		$	3.14		$	(1.20	)
Depreciation, depletion and amortization	$	26.54		$	22.08		$	4.46
Exploration expense	$	0.44		$	1.03		$	(0.59	)
General and administrative*	$	9.18		$	4.27		$	4.91
Net capital expenditures	$	149,119		$	425,045		$	(275,926	)

* Includes pension and pension settlement expenses of $4.40 and $0.83 for the three months ended December 31, 2015 and 2014, respectively.

SELECTED BUSINESS SEGMENT DATA (UNAUDITED)

For the 12 months ending December 31, 2015 and 2014

	Year-to-date
(in thousands, except sales price and per unit data)	2015			2014		Change
Operating and production data from continuing operations
Oil, natural gas liquids and natural gas sales
Oil	$	631,663		$	988,868	$	(357,205	)
Natural gas liquids		48,856			110,918		(62,062	)
Natural gas		82,742			244,408		(161,666	)
Total	$	763,261		$	1,344,194	$	(580,933	)
Open non-cash mark-to-market gains (losses) on derivative instruments
Oil	$	(242,227	)	$	271,200	$	(513,427	)
Natural gas liquids		—			287		(287	)
Natural gas		(39,525	)		43,958		(83,483	)
Total	$	(281,752	)	$	315,445	$	(597,197	)
Closed gains (losses) on derivative instruments
Oil	$	346,404		$	4,377	$	342,027
Natural gas liquids		—			6,218		(6,218	)
Natural gas		50,641			8,979		41,662
Total	$	397,045		$	19,574	$	377,471
Total revenues	$	878,554		$	1,679,213	$	(800,659	)
Production volumes
Oil (MBbl)		14,023			11,814		2,209
Natural gas liquids (MMgal)		170.7			172.3		(1.6	)
Natural gas (MMcf)		35,604			58,602		(22,998	)
Total production volumes (MBOE)		24,022			25,684		(1,662	)
Average daily production volumes
Oil (MBbl/d)		38.4			32.4		6.0
Natural gas liquids (MMgal/d)		0.5			0.5		—
Natural gas (MMcf/d)		97.5			160.6		(63.1	)
Total average daily production volumes (MBOE/d)		65.8			70.4		(4.6	)
Average realized prices excluding effects of open non-cash mark-to-market derivative instruments
Oil (per barrel)	$	69.75		$	84.07	$	(14.32	)
Natural gas liquids (per gallon)	$	0.29		$	0.68	$	(0.39	)
Natural gas (per Mcf)	$	3.75		$	4.32	$	(0.57	)
Average realized prices excluding effects of all derivative instruments
Oil (per barrel)	$	45.04		$	83.70	$	(38.66	)
Natural gas liquids (per gallon)	$	0.29		$	0.64	$	(0.35	)
Natural gas (per Mcf)	$	2.32		$	4.17	$	(1.85	)
Costs per BOE
Oil, natural gas liquids and natural gas production expenses	$	9.51		$	10.68	$	(1.17	)
Production and ad valorem taxes	$	2.39		$	3.97	$	(1.58	)
Depreciation, depletion and amortization	$	24.72		$	21.36	$	3.36
Exploration expense	$	0.62		$	1.09	$	(0.47	)
General and administrative*	$	6.21		$	4.75	$	1.46
Net capital expenditures	$	1,040,610		$	1,372,510	$	(331,900	)

* Includes pension and pension settlement expenses of $1.30 and $0.74 for the twelve months ended December 31, 2015 and 2014, respectively.

EX-99.3

Exhibit 99.3

Non-GAAP Financial Measures

Adjusted Net Income is a Non-GAAP financial measure (GAAP refers to generally accepted accounting principles) which excludes certain non-cash mark-to-market derivative financial instruments. Adjusted income from continuing operations further excludes impairment losses, certain pension and pension settlement expenses, income associated with the San Juan divestment (completed in the first quarter of 2015), gains and losses on disposal of discontinued operations and income and losses from discontinued operations. Energen believes that excluding the impact of these items is more useful to analysts and investors in comparing the results of operations and operational trends between reporting periods and relative to other oil and gas producing companies.

	Quarter Ended 12/31/2015
Energen Net Income ($ in millions except per share data)	Net Income			Per Diluted Share
Net Income (Loss) All Operations (GAAP)		(590.8	)		(7.50	)
Non-cash mark-to-market losses (net of $37.1 tax)		67.0			0.85
Asset impairment, other (net of $297.9 tax)		528.1			6.70
Pension and pension settlement expenses (net of $9.4 tax)		16.9			0.21
Loss associated w/ San Juan Basin divestment (net of $0.0 tax)		0.1			0.00
Adjusted Income from Continuing Operations (Non-GAAP)		21.3			0.27
	Quarter Ended 12/31/2014
Energen Net Income ($ in millions except per share data)	Net Income			Per Diluted Share
Net Income (Loss) All Operations (GAAP)		65.4			0.89
Non-cash mark-to-market gains (net of $94.1 tax)		(167.3	)		(2.28	)
Asset impairment, other (net of $93.9 tax)		141.9			1.94
Pension and pension settlement expenses (net of $2.0 tax)		3.6			0.05
Income associated w/ San Juan Basin divestment (net of $3.6 tax)		(6.5	)		(0.09	)
Adjusted Net Income from All Operations (Non-GAAP)		37.1			0.51
Loss from discontinued operations (net of $0.2 tax)		1.1			0.02
Gain from discontinued operations (net of $0.0 tax)		(0.0	)		(0.00	)
Adjusted Income from Continuing Operations (Non-GAAP)		38.2			0.52
	Year-to-Date Ended 12/31/2015
Energen Net Income ($ in millions except per share data)	Net Income			Per Diluted Share
Net Income (Loss) All Operations (GAAP)		(945.7	)		(12.43	)
Non-cash mark-to-market losses (net of $100.5 tax)		181.3			2.38
Asset impairment, other (net of $468.4 tax)		831.0			10.92
Pension and pension settlement expenses (net of $11.2 tax)		20.1			0.26
Loss associated w/ San Juan Basin divestment (net of $13.1 tax)		(22.1	)		(0.29	)
Adjusted Income from Continuing Operations (Non-GAAP)		64.5			0.85
	Year-to-Date Ended 12/31/2014
Energen Net Income ($ in millions except per share data)	Net Income			Per Diluted Share
Net Income (Loss) All Operations (GAAP)		568.0			7.75
Non-cash mark-to-market gains (net of $113.7 tax)		(201.8	)		(2.75	)
Asset impairment, other (net of $162.9 tax)		263.2			3.59
Pension and pension settlement expenses (net of $6.8 tax)		12.2			0.17
Income associated w/ San Juan Basin divestment (net of $20.6 tax)		(37.4	)		(0.51	)
Adjusted Net Income from All Operations (Non-GAAP)		604.2			8.25
Income from discontinued operations (net of $17.9 tax)		(29.3	)		(0.40	)
Gain from discontinued operations (net of $285.5 tax)		(439.1	)		(5.99	)
Adjusted Income from Continuing Operations (Non-GAAP)		135.8			1.85

Note: Amounts may not sum due to rounding

Non-GAAP Financial Measures

Earnings before interest, taxes, depreciation, depletion, amortization and exploration expenses (EBITDAX) is a Non-GAAP financial measure (GAAP refers to generally accepted accounting principles). Adjusted EBITDAX from continuing operations further excludes income associated with the San Juan divestment (completed in the first quarter of 2015), impairment losses, certain non-cash mark-to-market derivative financial instruments, certain pension and pension settlement expenses, income and losses from discontinued operations and gains and losses on disposal of discontinued operations. Energen believes these measures allow analysts and investors to understand the financial performance of the company from core business operations, without including the effects of capital structure, tax rates and depreciation. Further, this measure is useful in comparing the company and other oil and gas producing companies.

Reconciliation To GAAP Information	Quarter Ended 12/31
($ in millions)	2015			2014
Energen Net Income (Loss) (GAAP)		(590.8	)		65.4
(Income) Loss associated w/ San Juan Basin divestment, net of tax		0.1			(6.5	)
Adjusted Net Income from Continuing Operations (Non-GAAP)		(590.7	)		58.9
Interest expense		10.0			10.4
Income tax expense (benefit) *		(334.6	)		13.8
Depreciation, depletion and amortization *		159.8			137.0
Accretion expense *		1.7			1.6
Exploration expense *		2.5			5.9
Dry hole expense *		0.1			0.5
Adjustment for asset impairment		825.9			235.3
Adjustment for mark-to-market (gains) losses *		104.1			(261.5	)
Adjustment for pension and pension settlement expenses		26.2			5.5
Adjustment for loss from discontinued operations, net of tax		0.0			1.1
Adjustment for gain on disposal from discontinued operations, net of tax		0.0			(0.0	)
Energen Adjusted EBITDAX from Continuing Operations (Non-GAAP)		205.0			208.6
Reconciliation To GAAP Information	Year-to-Date Ended 12/31
($ in millions)	2015			2014
Energen Net Income (Loss) (GAAP)		(945.7	)		568.0
(Income) Loss associated w/ San Juan Basin divestment, net of tax		(22.1	)		(37.4	)
Adjusted Net Income from Continuing Operations (Non-GAAP)		(967.8	)		530.7
Interest expense		43.1			37.8
Income tax expense (benefit) *		(548.1	)		20.1
Depreciation, depletion and amortization *		585.7			492.5
Accretion expense *		6.7			6.0
Exploration expense *		7.8			14.6
Dry hole expense *		7.1			9.2
Adjustment for asset impairment		1,292.3			416.8
Adjustment for mark-to-market (gains) losses *		281.8			(315.4	)
Adjustment for pension and pension settlement expenses		31.3			18.9
Adjustment for loss from discontinued operations, net of tax		0.0			(29.3	)
Adjustment for gain on disposal from discontinued operations, net of tax		0.0			(439.1	)
Energen Adjusted EBITDAX from Continuing Operations (Non-GAAP)		739.8			762.9

Note: Amounts may not sum due to rounding

* Amount adjusted to exclude San Juan Basin divestment in either current or prior period. See reconciliation to GAAP Information for the Quarter and Year-to-Date Ended 12/31/2015 and 12/31/2014.

Non-GAAP Financial Measures

The consolidated statement of income excluding certain divestments is a Non-GAAP financial measure (GAAP refers to generally accepted accounting principles). Energen believes excluding information associated with the divestment of assets held in the San Juan Basin (completed in the first quarter of 2015) provides analysts and investors useful information to understand the financial performance of the company from ongoing business operations. Further, this information is useful in comparing the company and other oil and gas producing companies operating primarily in the Permian Basin.

Energen Net Income (Loss) Excluding San Juan Divestment
Reconciliation to GAAP Information	Quarter Ended
	December 31, 2015
(in thousands except per share and production data)
	GAAP			$/BOE		San Juan Basin			$/BOE		Non-GAAP			$/BOE
Revenues
Oil, natural gas liquids and natural gas sales	$	167,751				$	11				$	167,740
Gain (loss) on derivative instruments		25,048				$	—					25,048
Total Revenues		192,799					11					192,788
Operating Costs and Expenses
Oil, natural gas liquids & natural gas production		52,447		$	8.79		(1	)	$	0.00		52,448		$	8.79
Production and ad valorem taxes		11,597		$	1.94		1		$	0.00		11,596		$	1.94
O&G Depreciation, depletion and amortization		158,371		$	26.54		—		$	0.00		158,371		$	26.54
FF&E Depreciation, depletion and amortization		1,413		$	0.24		—		$	0.00		1,413		$	0.24
Asset impairment		825,918					—					825,918
Exploration		2,604					—					2,604
General and administrative		54,794		$	9.18		—		$	0.00		54,794		$	9.18
Accretion of discount on asset retirement obligations		1,729					—					1,729
(Gain) loss on sale of assets and other		(524	)				113					(637	)
Total costs and expenses		1,108,349					113					1,108,236
Operating Income (Loss)		(915,550	)				(102	)				(915,448	)
Other Income/(Expense)
Interest Expense		(10,022	)				—					(10,022	)
Other income		80					—					80
Total other expense		(9,942	)				—					(9,942	)
Income (Loss) from Continuing Operations Before Income Taxes		(925,492	)				(102	)				(925,390	)
Income tax expense (benefit)		(334,686	)				(37	)				(334,649	)
Income (Loss) From Continuing Operations		(590,806	)				(65	)				(590,741	)
Discontinued Operations, net of tax
Income (loss) from discontinued operations		—					—					—
Gain on Disposal of discontinued ops		—					—					—
Income from discontinued ops		—					—					—
Net Income (Loss)	$	(590,806	)			$	(65	)			$	(590,741	)
Diluted Earnings Per Average Common Share
Continuing Operations	$	(7.50	)			$	—				$	(7.50	)
Discontinued Operations	$	—				$	—				$	—
Net Income (Loss)	$	(7.50	)			$	—				$	(7.50	)
Basic earning Per Average Common Share
Continuing Operations	$	(7.50	)			$	—				$	(7.50	)
Discontinued Operations	$	—				$	—				$	—
Net Income (Loss)	$	(7.50	)			$	—				$	(7.50	)
Oil		3,584					—					3,584
NGL		1,078					—					1,078
Natural Gas		1,305					—					1,305
Total Production (mboe)		5,967					—					5,967
Total Production (boepd)		64,859					—					64,859

Note: Amounts may not sum due to rounding

Non-GAAP Financial Measures

The consolidated statement of income excluding certain divestments is a Non-GAAP financial measure (GAAP refers to generally accepted accounting principles). Energen believes excluding information associated with the divestment of assets held in the San Juan Basin (completed in the first quarter of 2015) provides analysts and investors useful information to understand the financial performance of the company from ongoing business operations. Further, this information is useful in comparing the company and other oil and gas producing companies operating primarily in the Permian Basin.

Energen Net Income (Loss) Excluding San Juan Divestment
Reconciliation to GAAP Information	Quarter Ended
	December 31, 2014
(in thousands except per share and production data)
	GAAP			$/BOE		San Juan Basin			$/BOE			Non-GAAP			$/BOE
Revenues
Oil, natural gas liquids and natural gas sales	$	286,747				$	35,307					$	251,440
Gain (loss) on derivative instruments		325,521				$	4,609						320,912
Total Revenues		612,268					39,916						572,352
Operating Costs and Expenses
Oil, natural gas liquids & natural gas production		74,571		$	11.16		14,471		$	9.28			60,100		$	11.74
Production and ad valorem taxes		20,961		$	3.14		3,141		$	2.01			17,820		$	3.48
O&G Depreciation, depletion and amortization		147,487		$	22.08		11,933		$	7.65			135,554		$	26.47
FF&E Depreciation, depletion and amortization		1,509		$	0.23		70		$	0.04			1,439		$	0.28
Asset impairment		235,301					—						235,301
Exploration		6,872					396						6,476
General and administrative		28,553		$	4.27		(611	)	($	0.39	)		29,164		$	5.69
Accretion of discount on asset retirement obligations		1,958					398						1,560
(Gain) loss on sale of assets and other		833					—						833
Total costs and expenses		518,045					29,798						488,247
Operating Income (Loss)		94,223					10,118						84,105
Other Income/(Expense)
Interest Expense		(10,397	)				—						(10,397	)
Other income		134					—						134
Total other expense		(10,263	)				—						(10,263	)
Income (Loss) from Continuing Operations Before Income Taxes		83,960					10,118						73,842
Income tax expense (benefit)		17,441					3,596						13,845
Income (Loss) From Continuing Operations		66,519					6,522						59,997
Discontinued Operations, net of tax
Income (loss) from discontinued operations		(1,143	)				—						(1,143	)
Gain on Disposal of discontinued ops		42					—						42
Income from discontinued ops		(1,101	)				—						(1,101	)
Net Income (Loss)	$	65,418				$	6,522					$	58,896
Diluted Earnings Per Average Common Share
Continuing Operations	$	0.91				$	(0.09	)				$	0.82
Discontinued Operations	$	(0.02	)			$	—					$	(0.02	)
Net Income (Loss)	$	0.89				$	(0.09	)				$	0.80
Basic earning Per Average Common Share
Continuing Operations	$	0.91				$	(0.09	)				$	0.82
Discontinued Operations	$	(0.01	)			$	—					$	(0.01	)
Net Income (Loss)	$	0.90				$	(0.09	)				$	0.81
Oil		3,213					4						3,209
NGL		1,027					148						879
Natural Gas		2,441					1,408						1,033
Total Production (mboe)		6,681					1,560						5,121
Total Production (boepd)		72,620					16,957						55,663

Note: Amounts may not sum due to rounding

Non-GAAP Financial Measures

The consolidated statement of income excluding certain divestments is a Non-GAAP financial measure (GAAP refers to generally accepted accounting principles). Energen believes excluding information associated with the divestment of assets held in the San Juan Basin (completed in the first quarter of 2015) provides analysts and investors useful information to understand the financial performance of the company from ongoing business operations. Further, this information is useful in comparing the company and other oil and gas producing companies operating primarily in the Permian Basin.

Energen Net Income (Loss) Excluding San Juan Divestment
Reconciliation to GAAP Information	Year-to-Date Ended
	December 31, 2015
(in thousands except per share and production data)
	GAAP			$/BOE		San Juan Basin			$/BOE			Non-GAAP			$/BOE
Revenues
Oil, natural gas liquids and natural gas sales	$	763,261				$	24,246					$	739,015
Gain (loss) on derivative instruments		115,293				$	8,369						106,924
Total Revenues		878,554					32,615						845,939
Operating Costs and Expenses
Oil, natural gas liquids & natural gas production		228,380		$	9.51		14,526		$	9.77			213,854		$	9.49
Production and ad valorem taxes		57,380		$	2.39		1,908		$	1.28			55,472		$	2.46
O&G Depreciation, depletion and amortization		587,882		$	24.47		8,068		$	5.43			579,814		$	25.73
FF&E Depreciation, depletion and amortization		5,907		$	0.25		—		$	0.00			5,907		$	0.26
Asset impairment		1,292,308					—						1,292,308
Exploration		14,878					—						14,878
General and administrative		149,132		$	6.21		(560	)	($	0.38	)		149,692		$	6.64
Accretion of discount on asset retirement obligations		7,108					433						6,675
(Gain) loss on sale of assets and other		(26,570	)				(26,969	)					399
Total costs and expenses		2,316,405					(2,594	)					2,318,999
Operating Income (Loss)		(1,437,851	)				35,209						(1,473,060	)
Other Income/(Expense)
Interest Expense		(43,108	)				—						(43,108	)
Other income		223					—						223
Total other expense		(42,885	)				—						(42,885	)
Income (Loss) from Continuing Operations Before Income Taxes		(1,480,736	)				35,209						(1,515,945	)
Income tax expense (benefit)		(535,005	)				13,133						(548,138	)
Income (Loss) From Continuing Operations		(945,731	)				22,076						(967,807	)
Discontinued Operations, net of tax
Income (loss) from discontinued operations		—					—						—
Gain on Disposal of discontinued ops		—					—						—
Income from discontinued ops		—					—						—
Net Income (Loss)	$	(945,731	)			$	22,076					$	(967,807	)
Diluted Earnings Per Average Common Share
Continuing Operations	$	(12.43	)			$	(0.29	)				$	(12.72	)
Discontinued Operations	$	—				$	—					$	—
Net Income (Loss)	$	(12.43	)			$	(0.29	)				$	(12.72	)
Basic earning Per Average Common Share
Continuing Operations	$	(12.43	)			$	(0.29	)				$	(12.72	)
Discontinued Operations	$	—				$	—					$	—
Net Income (Loss)	$	(12.43	)			$	(0.29	)				$	(12.72	)
Oil		14,023					1						14,022
NGL		4,065					139						3,926
Natural Gas		5,934					1,347						4,587
Total Production (mboe)		24,022					1,487						22,535
Total Production (boepd)		65,814					4,074						61,740

Note: Amounts may not sum due to rounding

Non-GAAP Financial Measures

The consolidated statement of income excluding certain divestments is a Non-GAAP financial measure (GAAP refers to generally accepted accounting principles). Energen believes excluding information associated with the divestment of assets held in the San Juan Basin (completed in the first quarter of 2015) provides analysts and investors useful information to understand the financial performance of the company from ongoing business operations. Further, this information is useful in comparing the company and other oil and gas producing companies operating primarily in the Permian Basin.

Energen Net Income (Loss) Excluding San Juan Divestment
Reconciliation to GAAP Information	Year-to-Date Ended
	December 31, 2014
(in thousands except per share and production data)
	GAAP			$/BOE		San Juan Basin			$/BOE			Non-GAAP			$/BOE
Revenues
Oil, natural gas liquids and natural gas sales	$	1,344,194				$	169,997					$	1,174,197
Gain (loss) on derivative instruments		335,019				$	22,354						312,665
Total Revenues		1,679,213					192,351						1,486,862
Operating Costs and Expenses
Oil, natural gas liquids & natural gas production		274,432		$	10.68		59,736		$	9.07			214,696		$	11.24
Production and ad valorem taxes		102,063		$	3.97		15,085		$	2.29			86,978		$	4.55
O&G Depreciation, depletion and amortization		543,738		$	21.17		55,786		$	8.47			487,952		$	25.55
FF&E Depreciation, depletion and amortization		4,826		$	0.19		246		$	0.04			4,580		$	0.24
Asset impairment		416,801					—						416,801
Exploration		28,090					4,244						23,846
General and administrative		122,052		$	4.75		(2,294	)	($	0.35	)		124,346		$	6.51
Accretion of discount on asset retirement obligations		7,608					1,561						6,047
(Gain) loss on sale of assets and other		2,642					—						2,642
Total costs and expenses		1,502,252					134,364						1,367,888
Operating Income (Loss)		176,961					57,987						118,974
Other Income/(Expense)
Interest Expense		(37,771	)				—						(37,771	)
Other income		1,181					—						1,181
Total other expense		(36,590	)				—						(36,590	)
Income (Loss) from Continuing Operations Before Income Taxes		140,371					57,987						82,384
Income tax expense (benefit)		40,728					20,609						20,119
Income (Loss) From Continuing Operations		99,643					37,378						62,265
Discontinued Operations, net of tax
Income (loss) from discontinued operations		29,292					—						29,292
Gain on Disposal of discontinued ops		439,097					—						439,097
Income from discontinued ops		468,389					—						468,389
Net Income (Loss)	$	568,032				$	37,378					$	530,654
Diluted Earnings Per Average Common Share
Continuing Operations	$	1.36				$	(0.51	)				$	0.85
Discontinued Operations	$	6.39				$	—					$	6.39
Net Income (Loss)	$	7.75				$	(0.51	)				$	7.24
Basic earning Per Average Common Share
Continuing Operations	$	1.37				$	(0.52	)				$	0.85
Discontinued Operations	$	6.42				$	0.01					$	6.43
Net Income (Loss)	$	7.79				$	(0.51	)				$	7.28
Oil		11,814					16						11,798
NGL		4,103					695						3,408
Natural Gas		9,767					5,876						3,891
Total Production (mboe)		25,684					6,587						19,097
Total Production (boepd)		70,367					18,047						52,321

Note: Amounts may not sum due to rounding

Non-GAAP Financial Measures

Excluding production associated with certain divestments is a Non-GAAP financial measure (GAAP refers to generally accepted accounting principles). Energen believes excluding data associated with the divestment of assets in the San Juan Basin (including the completed sale in the first quarter of 2015) and non-core properties held for sale provides analysts and investors useful information to understand the financial performance of the company from ongoing business operations. Further, this measure is useful in comparing the company and other oil and gas producing companies operating primarily in the Permian Basin.

Energen Production Excluding San Juan Divestment and Planned Sales
Reconciliation to GAAP Information	Year-to-Date Ended
	December 31, 2015
	GAAP		San Juan Basin and Non-Core Assets		Non-GAAP
Oil		14,023		658		13,365
NGL		4,065		787		3,278
Natural Gas		5,934		2,358		3,576
Total Production (mboe)		24,022		3,803		20,219
Total Production (boepd)		65,814		10,420		55,397

Note: Amounts may not sum due to rounding