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

November 5, 2015

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 November 5, 2015, Energen Corporation issued a press release announcing the third 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 November 5, 2015
99.2	Supplemental Financial Information
99.3	Non-GAAP Financial Measures Reconciliation

2

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
November 6, 2015	By	/s/ Charles W. Porter, Jr.
		Charles W. Porter, Jr. Vice President, Chief Financial Officer and Treasurer of Energen Corporation

EXHIBIT INDEX

EXHIBIT NUMBER	DESCRIPTION
99.1	* Press Release dated November 5, 2015
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.

3

EX-99.1

	Exhibit 99.1 ENERGEN CORPORATION 605 Richard Arrington, Jr. Boulevard North Birmingham, Alabama 35203-2707 Telephone (205) 326-2700
	For Release: 4:30 p.m. ET                                                                                                Contacts:    Julie S. Ryland Thursday, November 5, 2015                                                                                                                   205.326.8421
	ENERGEN’S FIRST MIDDLE SPRABERRY WELLS GENERATE SOLID EARLY RATES 10,000’ Lateral Wells in Glasscock County Generate Excellent Results in Wolfcamp A, B and C 3Q15 Production Tops 64,000 BOEPD Highlights •    Results of three 10,000’ laterals in Glasscock County underscore capital efficiency of longer lateral length wells. •    Two Middle Spraberry wells generate exciting early results in Martin County. •    Latest Lower Spraberry result in Martin County, together with continued performance of Lower Spraberry wells drilled earlier this year, support the play’s attractive return potential. •    Development drilling program begins in Martin County; 27 Lower Spraberry, Wolfcamp A and Wolfcamp B wells drilled with 10 more to be drilled in 4th quarter. •    3Q15 production totaled 64,054 boepd, exceeding guidance midpoint by 2%. •    3Q15 oil production grew 20% from same period last year. •    CY15 production guidance midpoint reaffirmed at 22.7 MMBOE (62,252 boepd). •    Drilling continues in New Mexico to assess Mancos oil potential on company’s San Juan Basin acreage. •    D&C costs of 7,500’ lateral Wolfcamp A in Glasscock County trending down to $5.6 million. BIRMINGHAM, Alabama – For the 3 months ended September 30, 2015, Energen Corporation (NYSE: EGN) reported a GAAP net loss from all operations of $227.9 million, or $(2.89) per diluted share. Excluding mark-to-market derivatives losses, commodity price-related impairments primarily of proved properties in the Central Basin Platform, and other items, Energen’s adjusted income in the 3rd quarter of 2015 totaled $28.6 million, or $0.36 per diluted share. This compares with adjusted income from continuing operations in the 3rd quarter of 2014 of $38.9 million, or $0.53 per diluted share. The variance between the periods largely is attributable to a 20 percent decline in realized oil and natural gas liquids (NGL) prices and higher depreciation, depletion, and amortization expense (DD&A) associated with increased drilling activity, partially offset by a 20 percent increase in production, lower production and ad valorem taxes, lower effective tax rate, and decreased net general and administrative expenses (G&A). [See “Non-GAAP Financial Measures” beginning on pp 12 for more information and reconciliation.] Energen’s adjusted EBITDAX totaled $204.4 million in the 3rd quarter of 2015, up 2 percent from adjusted EBITDAX from continuing operations in the same period last year of $199.9 million. [See “Non-GAAP Financial Measures” beginning on pp 12 for more information and reconciliation.]

The company’s adjusted 3rd quarter earnings exceeded internal expectations by more than 50 percent largely due to the impact of decreased stock-based compensation on G&A expenses, lower-than-expected lease operating, marketing and transportation expenses (LOE), increased production, and lower production and ad valorem taxes, partially offset by lower commodity prices and higher DD&A. Production in the 3^rd quarter of 2015 exceeded the guidance range midpoint by 2 percent (approximately 1,200 boepd) primarily due to better-than-expected well performance from Wolfcamp wells in the Delaware Basin.

“Exciting, positive well results, together with better-than-expected production, expenses, and earnings, underscored Energen’s continued strong performance in the 3^rd quarter as a leading operator in the Permian Basin,” said James McManus, Energen’s chairman and chief executive officer.

“We are very pleased with the results of our first two Middle Spraberry wells, both of which were drilled in Martin County. The early results are very solid and have high oil content. We have another Middle Spraberry well in Martin County currently in the early stages of flow back. I believe the Middle Spraberry is another target in the Midland Basin that will add to our existing, extensive inventory of engineered, unrisked locations.

“Our three, 10,000 foot lateral wells in Glasscock County generated very strong 24-hour and peak 30-day average rates from the three Wolfcamp benches targeted. We will be monitoring closely the performance of these wells but believe that the internal rates of return of the Wolfcamp A and B at $60 flat oil prices could be at least 15 percentage points higher than returns on comparable 7,500 foot lateral wells. We are working now to identify how many 10,000 foot lateral wells our acreage can support and will certainly move forward to incorporate as many as we can in our future development plans.

“Our latest Lower Spraberry appraisal well in southern Martin County – together with the cumulative performances of the other Lower Spraberry wells drilled earlier this year in the northern part of our Midland Basin acreage footprint – continue to support this play’s attractive return potential.

“Our development well program in Glasscock County continued to generate solid results in the 3^rd quarter, and we continue to see drill-and-complete costs for a 7,500 foot lateral Wolfcamp A well trending down toward $5.6 million. We also have now expanded our development program to Martin County, where we are drilling Lower Spraberry wells along with Wolfcamp A and B.

“As we look ahead to 2016, we will be return-driven, financially disciplined, and flexible. Based on strip prices for 2016 in the January timeframe, we will focus our capital on those projects that generate the highest internal rates of return and at a level of investment that allows us to maintain a debt-to-EBITDAX multiple of 2.0-2.5 times,” McManus said. “Our strong balance sheet provides us with excellent flexibility to adjust as conditions change. We have outstanding assets in the Midland and Delaware Basins that support a rich inventory of opportunities, and we plan to develop those assets in a manner that supports long-term value creation for our shareholders.”

2

3rd Quarter Financial Review

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

[See “Non-GAAP Financial Measures” beginning on pp 12 for more information]

	3Q15						3Q14
	$M			$/dil. sh.			$M			$/dil. sh.
Net Income/(Loss) All Operations (GAAP)	$	(227,904	)	$	(2.89	)	$	457,251		$	6.22
Less: Non-cash mark-to-market gains/(losses)		(784	)		(0.01	)		94,142			1.28
Less: Asset impairments, dry hole expenses		(255,703	)		(3.25	)		(118,823	)		(1.62	)
Less: Income/(loss) associated w/ San Juan Basin divestment		(41	)		0.00			6,443			0.09
Less: Discontinued operations		—			—			436,620			5.94
Adj. Income Continuing Operations (Non-GAAP)	$	28,624		$	0.36		$	38,869		$	0.53

Note: Per share amounts may not sum due to rounding

Production from Continuing Operations (excludes production associated with San Juan divestiture)

Commodity	3Q15				3Q14				Change			2Q15
	MBOE		boepd		MBOE		boepd					MBOE		boepd
Oil		3,610		39,239		3,011		32,728		20	%		3,595		39,505
NGL		1,056		11,478		890		9,674		19	%		1,060		11,648
Natural Gas		1,227		13,337		995		10,815		23	%		1,151		12,648
Total		5,893		64,054		4,896		53,217		20	%		5,806		63,802

Note: Totals may not sum due to rounding

Production from Continuing Operations (excludes production associated with San Juan divestiture)

Area	3Q15				3Q14				Change			2Q15
	MBOE		boepd		MBOE		boepd					MBOE		boepd
Midland Basin		2,970		32,283		1,877		20,402		58	%		2,956		32,484
Wolfcamp/Spraberry		1,944		21,130		586		6,370					1,777		19,527
Wolfberry		1,026		11,152		1,291		14,033					1,179		12,956
Delaware Basin		1,519		16,511		1,524		16,565		0	%		1,449		15,923
3rd Bone Spring/Other		997		10,837		1,219		13,250					963		10,582
Wolfcamp		522		5,674		305		3,315					486		5,341
Central Basin Platform		902		9,804		998		10,848		(10	)%		918		10,088
Total Permian Basin		5,391		58,598		4,399		47,815		23	%		5,323		58,495
San Juan Basin/Other		502		5,457		497		5,402		1	%		483		5,308
Total		5,893		64,054		4,896		53,217		20	%		5,806		63,802

Note: Totals may not sum due to rounding

3

Average Realized Sales Prices from Continuing Operations (excludes production associated with San Juan divestiture)

Commodity	3Q15		3Q14			Change
Oil (per barrel)	$	71.64	$	84.34			(15	)%
NGL (per gallon)	$	0.25	$	0.71			(65	)%
Natural Gas (per Mcf)	$	3.69	$	3.70	*		0	%

* 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 3Q14 was $4.27 per Mcf.

Average Prices from Continuing Operations Before Effects of Hedges (excludes production associated with San Juan divestiture)

Commodity	3Q15		3Q14		Change
Oil (per barrel)	$	44.47	$	86.34		(49	)%
NGL (per gallon)	$	0.25	$	0.68		(63	)%
Natural Gas (per Mcf)	$	2.29	$	3.69		(38	) %

Expenses from Continuing Operations and Excluding San Juan Basin Assets sold March 31, 2015

(per BOE, except interest expense)

Expenses	3Q15			3Q14		Change
LOE*	$	9.26		$	10.59		(13	)%
Production & ad valorem taxes	$	2.25		$	4.43		(49	)%
DD&A	$	25.17		$	25.05		1	%
Net G&A	$	3.85	†	$	5.80		(34	)%
Interest ($MM)	$	10.1		$	11.5		(12	)%

* Production costs + workovers and repairs + marketing and transportation

† Excludes $0.16 per BOE for pension and pension settlement expenses

3rd Quarter Comparisons, 2015 vs 2014 (excluding San Juan Basin assets sold March 31, 2015)

• The success of Energen’s Wolfcamp development program led to a 58 percent increase in Midland Basin production and a 23 percent increase in total Permian Basin production.

• The company’s average realized oil price fell 15 percent to $71.64 per barrel, while the realized price of NGL dropped 65 percent. Excluding the impact of commodity and differential hedges, the average realized price of oil would have been $44.47 per barrel.

• LOE per unit declined 13 percent to $9.26 per barrel largely due to lower workover and repair expense, lower power costs, and lower water disposal costs, partially offset increased equipment rental expenses. Per-unit production and ad valorem taxes declined 49 percent.

• Per-unit DD&A expense was essentially unchanged.

• Per-unit net G&A expense of $3.85 per BOE (excluding pension and pension settlement expenses) declined 34 percent from the same period a year ago largely due decreased stock-based compensation and lower expenses for professional and legal services.

• Interest expense declined 12 percent largely due to a prior year write off of debt issuance costs associated with our $600 million Senior Term Loans.

4

Liquidity Update

The Fall 2015 redetermination of Energen’s borrowing base resulted in a $200 million reduction in its line of credit. The Company’s new line of credit is $1.4 billion.

As of September 30, 2015, Energen had borrowings of $196.5 million on its line of credit and cash/cash equivalents of $0.7 million, for total liquidity available on the new borrowing base of $1.2 billion. Long-term debt at the end of September totaled $553.6 million.

Midland Basin Development Program Results

Development program wells drilled in 3Q15 (gross/net)	18/18
Development program wells completed in 3Q15 (gross/net)	31/30
Development program wells awaiting completion at end of 3Q15 (gross/net)	31/31
Development program wells awaiting completion at YE15e (gross/net)	48/48

In its 2-well, pad-drilling development program in Glasscock County, Energen tested 18 Wolfcamp A and B wells with lateral lengths of 6,700 feet and 7,500 feet during the 3rd quarter of 2015. These wells generated average peak 24-hour IP rates (3-stream) of 1,050 boepd (76% oil) and peak 30-day average rates (3-stream) of 704 boepd (62% oil). These average rates were generally comparable to the development wells tested in the 2nd quarter and higher than those tested in the 1^st quarter; the gassier product mix reflects the area where these wells were drilled. These latest wells used a similar completion design that continues to generate encouraging results as the company works to further enhance the economics of its development program.

Since the development program’s inception in 2014, Energen has tested 75 gross (74 net) wells that generated average peak 24-hour IPs (3-stream) of 959 boepd (80% oil) and peak 30-day average rates (3-stream) of 733 boepd (71% oil). A supplemental slide posted at www.energen.com shows that the average production from these wells — normalized to a 7,000’ lateral length.

During the 3^rd quarter, Energen expanded its development program to Martin County, where it has drilled 27 gross (27 net) Lower Spraberry, Wolfcamp A, and Wolfcamp B wells. Another 10 gross (10 net) wells are slated to be drilled in Martin County in the 4^th quarter.

Energen’s total 2015 Midland Basin development program calls for the drilling of 98 gross (97 net) wells in Glasscock and Martin counties. As of September 30, 81 gross (80 net) wells had been drilled to total depth, leaving 17 gross (17 net) wells to be drilled in the 4th quarter. Three development rigs are expected to run in the 4^th quarter. No further development well completions are slated in 2015.

The company currently estimates that 48 gross (48 net) wells in the 2015 program will be completed in 2016 including all 37 gross (37 net) Martin County development wells.

5

Midland and Delaware Basin Appraisal Program Results

Energen tested seven new appraisal wells in the Permian Basin during the 3rd quarter of 2015, including three, 10,000 foot lateral wells in Glasscock County and its first two Middle Spraberry wells, both in Martin County. [See locator maps at www.energen.com]

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
Cole Ranch 35 #107H	WCA/Glasscock		10,366		9,749		46		1,385		74		15		11		1,145		70		17		13
Cole Ranch 35 #207H	WCB/Glasscock		10,428		9,805		44		1,651		65		19		16		1,197		64		20		17
Cole Ranch 35 #307H	WCC/Glasscock		10,366		9,924		46		1,447		40		36		25		1,065		39		36		25
Dickenson SN 20-17 03 #503H	LSB/Martin		6,996		6,509		31		963		78		13		10		672		76		14		11
Dickenson SN 20-17 03 #603H	MSB/Martin		7,013		6,408		30		790		78		13		9		634		76		14		10
Jones Holton #601H	MSB/Martin		7,473		7,068		33		948		79		12		9		858		79		12		9

* Represents distance from vertical departure to toe

Note: Totals may not foot due to rounding

Energen’s three, 10,000 foot lateral wells drilled in Glasscock County generated very strong 24-hour and average 30-day peak rates from the Wolfcamp A, Wolfcamp B, and Wolfcamp C. These three wells averaged a peak 30-day average rate of more than 1,135 boepd, with the oil content ranging from 70 percent in the Wolfcamp A to 64 percent in the Wolfcamp B to 39 percent in the Wolfcamp C.

Energen also tested its first two Middle Spraberry wells, both of which were drilled in different areas of Martin County. The early results of these two wells are very strong, with high oil content and modest declines from their peak 24-hour rates to their peak 30-day average rates.

The company’s most recent Lower Spraberry appraisal well was drilled in southern Martin County near the heart of a vertical Spraberry field. It generated a strong peak 24-hour IP rate of 963 boepd (78% oil) and a peak 30-day average rate of 672 boepd (76% oil). The strength of this well suggests that the company’s exposure to areas of the greatest Spraberry depletion associated with older vertical drilling is limited to approximately 2,000 net acres in northern Midland County (as compared with an earlier estimate of 5,000 net acres).

Together with the cumulative performances of the four Lower Spraberry wells drilled earlier this year in Martin, Midland, and Howard counties, this well further supports the attractive return potential of the Lower Spraberry in the northern part of Energen’s acreage footprint in the Midland Basin. [See cumulative oil performance over time and potential economics of the company’s four northern Midland Basin Lower Spraberry wells at www.energen.com]

6

Energen currently is drilling its last of 8 gross (8 net) Wolfcamp shale wells in its Midland Basin appraisal program for 2015 — a Wolfcamp A test in Midland County. The final six Spraberry wells in the 2015 appraisal program are in various stages of completion and flow back; three are in Glasscock County and three in Martin County.

Delaware 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

Falcon State 28-36 #1H

WCA/Winkler

4,895

4,389

21

1,049

74

14

12

818

75

13

12

* Represents distance from vertical departure to toe

The last of 8 gross (8 net) appraisal wells in Energen’s 2015 Delaware Basin drilling program was the Falcon State 28-36 #1H. Drilled into the Wolfcamp A in Winkler County in the northeastern portion of the Texas Delaware Basin, the well generated strong early results with a peak 24-hour IP of 1,049 (74% oil) and peak 30-day average of 818 boepd (75% oil).

San Juan Basin Mancos Appraisal Program

Energen currently is drilling its fourth Mancos oil formation appraisal well in the San Juan Basin. The first two wells are currently flowing back, and a third well currently is completing. The first two wells were drilled in Rio Arriba County; the others are located in San Juan County. The company plans to drill and complete 7 gross (7 net) wells by year-end 2015; an eighth planned well will be drilled and completed in early 2016. These wells are designed to test the company’s 91,000 net acres with Mancos oil potential.

Capital, Production, and Financial Guidance

Energen today said its 2015 drilling and development capital is now estimated to be $1.0 billion, or $43 million lower than the prior estimate. This is largely the result of the addition of three net Lower Spraberry development wells, a decrease in development program costs, and other miscellaneous adjustments.

The company’s production guidance range for the year remains 22.2 - 23.2 MMBOE (60,882-63,622 boepd), with a midpoint of 22.7 MMBOE (62,252 boepd). This reflects an increase of approximately 19 percent from comparable, adjusted 2014 production volumes of 19.1 MMBOE (52,320 boepd).

7

2015 Capital Summary

	2015e Capital ($MM)			Operated Wells to Be Drilled
				Gross (Net)
Midland Basin	$	810			125	(123	)
Wolfcamp
Development		460			83	(82	)
Appraisal		66			8	(8	)
Spraberry
Development		90			15	(15	)
Appraisal		83			12	(12	)
Wolfberry		16			7	(6	)
SWD/Facilities		84
Non-operated/Other		11
Delaware Basin	$	135			14	(13	)
Bone Spring		17			3	(2	)
Wolfcamp		69			8	(8	)
Wolfbone		15			3	(3	)
SWD/Facilities		26
Non-operated/Other		8
Other Permian	$	6			0	(0	)
Waterflood injectors		0
Facilities/C02		0
Non-operated/Other		6
San Juan Basin/Other	$	60			7	(7	)
Mancos		30			7	(7	)
Facilities		13
Non-operated/Other		17
Net Carry/ARO/Other	$	(9	)
Drilling & Development	$	1,002			146	(143	)
Acquisitions/Lease	$	66
Total Capital	$	1,068

Note: “Facilities” capital includes artificial lift and central gathering facilities; “Other”

Capital includes payadds and refracs

Production by Product (Excluding San Juan Basin Divestiture)

Commodity	2015e Midpoint				2014				% change
	MMBOE		boepd		MMBOE		boepd
Oil		14.3		39,126		11.8		32,323		21	%
NGL		4.0		10,847		3.4		9,337		16	%
Natural Gas		4.5		12,279		3.9		10,660		15	%
Total Continuing Operations		22.7		62,252		19.1		52,320		19	%

NOTE: Totals may not sum due to rounding

8

Production by Play (Excluding San Juan Basin Divestiture)

Area	2015e Midpoint				2014				Change (boepd)
	MMBOE		boepd		MMBOE		boepd
Midland Basin		11.8		32,373		7.4		20,293		60	%
Wolfcamp/Spraberry		7.7		21,142		2.1		5,827
Wolfberry		4.1		11,230		5.3		14,466
Delaware Basin		5.4		14,764		5.8		15,995		(8	)%
3rd Bone Spring/Other		3.7		10,038		4.6		12,731
Wolfcamp		1.7		4,726		1.2		3,264
Central Basin Platform		3.6		9,910		4.1		11,104		(11	)%
Total Permian Basin		20.8		57,047		17.3		47,392		20	%
San Juan Basin/Other		1.9		5,205		1.8		4,929		6	%
Total		22.7		62,252		19.1		52,320		19	%

NOTE: Totals may not sum due to rounding

Production by Basin/Quarter (Excluding San Juan Divestiture)

Basin	1Q15a				2Q15a				3Q15a				4Q15e Midpoint
	MMBOE		boepd		MMBOE		boepd		MMBOE		boepd		MMBOE		boepd
Midland Basin		2.3		25,778		3.0		32,484		3.0		32,283		3.6		38,804
Delaware Basin		1.2		13,611		1.4		15,923		1.5		16,511		1.2		13,000
Central Basin Platform/Other		0.9		10,100		0.9		10,088		0.9		9,804		0.9		9,652
San Juan Basin/Other		0.4		4,611		0.5		5,308		0.5		5,457		0.5		5,435
Total Production		4.9		54,100		5.8		63,802		5.9		64,054		6.2		66,891

NOTE: Totals may not sum due to rounding

Production by Commodity/Quarter (Excluding San Juan Basin Divestiture)

Commodity	1Q15a				2Q15a				3Q15a				4Q15e Midpoint
	MMBOE		boepd		MMBOE		boepd		MMBOE		boepd		MMBOE		boepd
Oil		3.2		35,922		3.6		39,505		3.6		39,239		3.8		41,772
NGL		0.7		8,133		1.1		11,648		1.1		11,478		1.1		12,087
Gas		0.9		10,044		1.2		12,648		1.2		13,337		1.2		13,033
Total Production		4.9		54,100		5.8		63,802		5.9		64,054		6.2		66,891

NOTE: Totals may not sum due to rounding

9

4Q15 AND CY15 FINANCIAL GUIDANCE

Energen’s estimated expenses, excluding San Juan Basin divestiture, are as follows:

Per BOE, except where noted	4Q15	CY15
LOE (production costs, marketing & transportation)	$9.75-$10.15	$9.50-$10.10
Production & ad valorem taxes (% of revenues, excluding hedges)	7.8%
DD&A expense*	$23.75-$24.25	$24.55-$25.60
General & administrative expense, net†	$4.60-$5.00	$5.00-$5.50
Exploration expense (seismic, delay rentals, etc.)	$0.80-$0.90	$0.40-$0.50
Interest expense ($MM)	$9.5-$10.5	$40.0-$46.0
FF&E ($MM)	$1.5-$1.9	$6.0-$6.4
Accretion of discount on ARO ($MM)	$1.5-$1.9	$6.5-$6.9
Effective tax rate (%)	34-36%	33-35%

* Subject to year-end, 4^th quarter, look-back adjustment

† Excludes $5.19 per BOE in 4Q15 and $1.63 per BOE in CY15 for pension and pension settlement expenses.

4Q15 Hedges

The company’s hedge position for the last three months of 2015 is:

Commodity	Hedge Volumes		Production @ Midpoint		Hedge %			NYMEXe Price
Oil		3.5 MMBO		3.8 MMBO		91	%	$	78.28 per barrel
Natural Gas		7.0 Bcf		7.2 Bcf		97	%	$	4.25 per Mcf
NGL		—		1.1 MMBOE		—			—

Note: Known actuals included

In the table 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 4^th quarter oil transportation charges of $2.22 per barrel; and average realized NGL prices will be net of transportation and fractionation fees that are estimated to average $0.11 per gallon in the Permian Basin and $0.12-$0.17 per gallon in the San Juan Basin for the remainder of the year.

Hedges also are in place that limit the company’s exposure to the Midland to Cushing differential. Energen has hedged the WTS Midland to WTI Cushing (sour oil) differential for 0.5 million barrels of oil production at an average price of -$4.30 per barrel and the WTI Midland to WTI Cushing (sweet oil) differential for 1.9 million barrels at an average price of -$4.55 per barrel. Energen estimates that approximately 80 percent of its oil production for the remainder of the year will be sweet. Gas basis assumptions for all open contracts (November-December) are -$0.09 per Mcf (basis actuals in October were approximately -$0.14 per Mcf).

10

Energen’s assumptions for the commodity prices of unhedged production for the remainder of 2015 are $48.35 per barrel of oil (October-December), $2.57 per Mcf of gas (November-December), and $0.47 per gallon of NGL (October-December). Assumed prices for unhedged Midland to Cushing basis differentials for sweet and sour oil (October-December) are +$0.34 and +$0.40, respectively. Every 1-cent change in the average price of NGL from $0.47 per gallon is estimated to have a cash flows impact of approximately $300,000.

Energen estimates that price realizations in the 4th quarter of 2015 (pre-hedge) will be approximately:

• Crude oil (% of NYMEX/WTI)                             94%

• Natural gas (% of NYMEX/Henry Hub)               87%

• NGL (after T&F) (% of NYMEX/WTI)                27%

Conference Call

Energen will hold its quarterly conference call Friday, November 6, 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. The company has 1.1 billion barrels of oil-equivalent proved, probable, and possible reserves and another 2.2 billion barrels of oil-equivalent 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 STATEMENT: 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 timing and amount of future production of oil, natural gas liquids and natural gas, price realizations, nature and timing of capital expenditures for exploration and development, plans for funding operations and drilling program capital expenditures, 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. 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 filing. 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.

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

11

EX-99.2

Exhibit 99.2

CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)

For the 3 months ending September 30, 2015 and 2014

	3rd Quarter
(in thousands, except per share data)	2015			2014			Change
Revenues
Oil, natural gas liquids and natural gas sales	$	188,398		$	350,773		$	(162,375	)
Gain on derivative instruments, net		107,173			147,735			(40,562	)
Total revenues		295,571			498,508			(202,937	)
Operating Costs and Expenses
Oil, natural gas liquids and natural gas production		54,598			67,720			(13,122	)
Production and ad valorem taxes		13,366			25,729			(12,363	)
Depreciation, depletion and amortization		149,781			139,104			10,677
Asset impairment		399,394			178,912			220,482
Exploration		493			8,417			(7,924	)
General and administrative		23,631			27,784			(4,153	)
Accretion of discount on asset retirement obligations		1,700			1,924			(224	)
Loss on sale of assets and other		822			747			75
Total costs and expenses		643,785			450,337			193,448
Operating Income (Loss)		(348,214	)		48,171			(396,385	)
Other Income (Expense)
Interest expense		(10,084	)		(11,522	)		1,438
Other income		56			37			19
Total other expense		(10,028	)		(11,485	)		1,457
Income (Loss) From Continuing Operations Before Income Taxes		(358,242	)		36,686			(394,928	)
Income tax expense (benefit)		(130,338	)		16,055			(146,393	)
Income (Loss) From Continuing Operations		(227,904	)		20,631			(248,535	)
Discontinued Operations, net of tax
Loss from discontinued operations		—			(3,485	)		3,485
Gain on disposal of discontinued operations		—			440,105			(440,105	)
Income From Discontinued Operations		—			436,620			(436,620	)
Net Income (Loss)	$	(227,904	)	$	457,251		$	(685,155	)
Diluted Earnings Per Average Common Share
Continuing operations	$	(2.89	)	$	0.28		$	(3.17	)
Discontinued operations		—			5.94			(5.94	)
Net Income (Loss)	$	(2.89	)	$	6.22		$	(9.11	)
Basic Earnings Per Average Common Share
Continuing operations	$	(2.89	)		0.28		$	(3.17	)
Discontinued operations		—			5.98			(5.98	)
Net Income (Loss)	$	(2.89	)	$	6.26		$	(9.15	)
Diluted Avg. Common Shares Outstanding		78,742			73,507			5,235
Basic Avg. Common Shares Outstanding		78,742			73,093			5,649
Dividends Per Common Share	$	0.02		$	0.15		$	(0.13	)

CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)

For the 9 months ending September 30, 2015 and 2014

	Year-to-date
(in thousands, except per share data)	2015			2014			Change
Revenues
Oil, natural gas liquids and natural gas sales	$	595,510		$	1,057,447		$	(461,937	)
Gain on derivative instruments, net		90,245			9,498			80,747
Total revenues		685,755			1,066,945			(381,190	)
Operating Costs and Expenses
Oil, natural gas liquids and natural gas production		175,933			199,861			(23,928	)
Production and ad valorem taxes		45,783			81,102			(35,319	)
Depreciation, depletion and amortization		434,005			399,568			34,437
Asset impairment		466,390			181,500			284,890
Exploration		12,274			21,218			(8,944	)
General and administrative		94,338			93,499			839
Accretion of discount on asset retirement obligations		5,379			5,650			(271	)
(Gain) loss on sale of assets and other		(26,046	)		1,809			(27,855	)
Total costs and expenses		1,208,056			984,207			223,849
Operating Income (Loss)		(522,301	)		82,738			(605,039	)
Other Income (Expense)
Interest expense		(33,086	)		(27,374	)		(5,712	)
Other income		143			1,047			(904	)
Total other expense		(32,943	)		(26,327	)		(6,616	)
Income (Loss) From Continuing Operations Before Income Taxes		(555,244	)		56,411			(611,655	)
Income tax expense (benefit)		(200,319	)		23,287			(223,606	)
Income (Loss) From Continuing Operations		(354,925	)		33,124			(388,049	)
Discontinued Operations, net of tax
Income from discontinued operations		—			30,435			(30,435	)
Gain on disposal of discontinued operations		—			439,055			(439,055	)
Income From Discontinued Operations		—			469,490			(469,490	)
Net Income (Loss)	$	(354,925	)	$	502,614		$	(857,539	)
Diluted Earnings Per Average Common Share
Continuing operations	$	(4.72	)	$	0.45		$	(5.17	)
Discontinued operations		—			6.41			(6.41	)
Net Income (Loss)	$	(4.72	)	$	6.86		$	(11.58	)
Basic Earnings Per Average Common Share
Continuing operations	$	(4.72	)	$	0.45		$	(5.17	)
Discontinued operations		—			6.45			(6.45	)
Net Income (Loss)	$	(4.72	)	$	6.90		$	(11.62	)
Diluted Avg. Common Shares Outstanding		75,125			73,238			1,887
Basic Avg. Common Shares Outstanding		75,125			72,861			2,264
Dividends Per Common Share	$	0.06		$	0.45		$	(0.39	)

CONSOLIDATED BALANCE SHEETS (UNAUDITED)

As of September 30, 2015 and December 31, 2014

(in thousands)	September 30, 2015		December 31, 2014
ASSETS
Current Assets
Cash and cash equivalents	$	701	$	1,852
Accounts receivable, net of allowance		99,297		157,678
Inventories		18,184		14,251
Assets held for sale		—		395,797
Derivative instruments		153,816		322,337
Prepayments and other		12,667		27,445
Total current assets		284,665		919,360
Property, Plant and Equipment
Oil and natural gas properties, net		5,182,497		5,152,748
Other property and equipment, net		48,739		46,389
Total property, plant and equipment, net		5,231,236		5,199,137
Other assets		15,646		19,761
TOTAL ASSETS	$	5,531,547	$	6,138,258
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current Liabilities
Accounts payable	$	79,623	$	101,453
Accrued taxes		27,555		5,530
Accrued wages and benefits		25,103		21,553
Accrued capital costs		101,486		207,461
Revenue and royalty payable		58,480		72,047
Liabilities related to assets held for sale		—		24,230
Pension liabilities		29,789		24,609
Deferred income taxes		9,908		79,164
Derivative instruments		3,079		988
Other		13,513		23,288
Total current liabilities		348,536		560,323
Long-term debt		750,081		1,038,563
Asset retirement obligations		100,781		94,060
Deferred income taxes		853,360		1,000,486
Noncurrent derivative instruments		2,924		—
Other long-term liabilities		10,968		30,222
Total liabilities		2,066,650		2,723,654
Total Shareholders’ Equity		3,464,897		3,414,604
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY	$	5,531,547	$	6,138,258

SELECTED BUSINESS SEGMENT DATA (UNAUDITED)

For the 3 months ending September 30, 2015 and 2014

	3rd 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	$	160,531		$	260,447		$	(99,916	)
Natural gas liquids		11,001			31,259			(20,258	)
Natural gas		16,866			59,067			(42,201	)
Total	$	188,398		$	350,773		$	(162,375	)
Open non-cash mark-to-market gains (losses) on derivative instruments
Oil	$	5,760		$	128,346		$	(122,586	)
Natural gas liquids		—			1,276			(1,276	)
Natural gas		(6,924	)		17,665			(24,589	)
Total	$	(1,164	)	$	147,287		$	(148,451	)
Closed gains (losses) on derivative instruments
Oil	$	98,072		$	(6,012	)	$	104,084
Natural gas liquids		—			873			(873	)
Natural gas		10,265			5,587			4,678
Total	$	108,337		$	448		$	107,889
Total revenues	$	295,571		$	498,508		$	(202,937	)
Production volumes
Oil (MBbl)		3,610			3,017			593
Natural gas liquids (MMgal)		44.4			46.5			(2.1	)
Natural gas (MMcf)		7,362			15,156			(7,794	)
Total production volumes (MBOE)		5,893			6,651			(758	)
Average daily production volumes
Oil (MBbl/d)		39.2			32.8			6.4
Natural gas liquids (MMgal/d)		0.5			0.5			—
Natural gas (MMcf/d)		80.0			164.7			(84.7	)
Total average daily production volumes (MBOE/d)		64.1			72.3			(8.2	)
Average realized prices excluding effects of open non-cash mark-to-market derivative instruments
Oil (per barrel)	$	71.64		$	84.33		$	(12.69	)
Natural gas liquids (per gallon)	$	0.25		$	0.69		$	(0.44	)
Natural gas (per Mcf)	$	3.69		$	4.27		$	(0.58	)
Average realized prices excluding effects of all derivative instruments
Oil (per barrel)	$	44.47		$	86.33		$	(41.86	)
Natural gas liquids (per gallon)	$	0.25		$	0.67		$	(0.42	)
Natural gas (per Mcf)	$	2.29		$	3.90		$	(1.61	)
Costs per BOE
Oil, natural gas liquids and natural gas production expenses	$	9.26		$	10.18		$	(0.92	)
Production and ad valorem taxes	$	2.27		$	3.87		$	(1.60	)
Depreciation, depletion and amortization	$	25.42		$	20.91		$	4.51
Exploration expense	$	0.08		$	1.27		$	(1.19	)
General and administrative*	$	4.01		$	4.18		$	(0.17	)
Net capital expenditures	$	230,900		$	356,725		$	(125,825	)

* Includes pension and pension settlement expenses of $0.16 and $0.53 for the three months ended September 30, 2015 and 2014, respectively.

SELECTED BUSINESS SEGMENT DATA (UNAUDITED)

For the 9 months ending September 30, 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	$	491,158		$	776,952		$	(285,794	)
Natural gas liquids		36,616			90,625			(54,009	)
Natural gas		67,736			189,870			(122,134	)
Total	$	595,510		$	1,057,447		$	(461,937	)
Open non-cash mark-to-market gains (losses) on derivative instruments
Oil	$	(149,743	)	$	40,710		$	(190,453	)
Natural gas liquids		—			1,603			(1,603	)
Natural gas		(27,939	)		11,672			(39,611	)
Total	$	(177,682	)	$	53,985		$	(231,667	)
Closed gains (losses) on derivative instruments
Oil	$	230,885		$	(46,568	)	$	277,453
Natural gas liquids		—			1,228			(1,228	)
Natural gas		37,042			853			36,189
Total	$	267,927		$	(44,487	)	$	312,414
Total revenues	$	685,755		$	1,066,945		$	(381,190	)
Production volumes
Oil (MBbl)		10,439			8,601			1,838
Natural gas liquids (MMgal)		125.5			129.2			(3.7	)
Natural gas (MMcf)		27,774			43,956			(16,182	)
Total production volumes (MBOE)		18,055			19,003			(948	)
Average daily production volumes
Oil (MBbl/d)		38.2			31.5			6.7
Natural gas liquids (MMgal/d)		0.5			0.5			—
Natural gas (MMcf/d)		101.7			161.0			(59.30	)
Total average daily production volumes (MBOE/d)		66.1			69.6			(3.50	)
Average realized prices excluding effects of open non-cash mark-to-market derivative instruments
Oil (per barrel)	$	69.17		$	84.92		$	(15.75	)
Natural gas liquids (per gallon)	$	0.29		$	0.71		$	(0.42	)
Natural gas (per Mcf)	$	3.77		$	4.34		$	(0.57	)
Average realized prices excluding effects of all derivative instruments
Oil (per barrel)	$	47.05		$	90.33		$	(43.28	)
Natural gas liquids (per gallon)	$	0.29		$	0.70		$	(0.41	)
Natural gas (per Mcf)	$	2.44		$	4.32		$	(1.88	)
Costs per BOE
Oil, natural gas liquids and natural gas production expenses	$	9.75		$	10.52		$	(0.77	)
Production and ad valorem taxes	$	2.54		$	4.27		$	(1.73	)
Depreciation, depletion and amortization	$	24.04		$	21.03		$	3.01
Exploration expense	$	0.68		$	1.12		$	(0.44	)
General and administrative*	$	5.23		$	4.92		$	0.31
Net capital expenditures	$	891,491		$	950,993		$	(59,502	)

* Includes pension and pension settlement expenses of $0.28 and $0.71 for the nine months ended September 30, 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, income associated with certain divestments, 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 9/30/2015
Energen Net Income ($ in millions except per share data)	Net Income			Per Diluted Share
Net Income (Loss) All Operations (GAAP)		(227.9	)		(2.89	)
Non-cash mark-to-market losses (net of $0.4 tax)		0.8			0.01
Asset impairment, other (net of $144.2 tax)		255.7			3.25
Loss associated w/ San Juan Basin divestment (net of $0.0 tax)		0.0			0.00
Adjusted Income from Continuing Operations (Non-GAAP)		28.6			0.36

	Quarter Ended 9/30/2014
Energen Net Income ($ in millions except per share data)	Net Income			Per Diluted Share
Net Income (Loss) All Operations (GAAP)		457.3			6.22
Non-cash mark-to-market gains (net of $53.1 tax)		(94.1	)		(1.28	)
Asset impairment, other (net of $67.6 tax)		118.8			1.62
Income associated w/ San Juan Basin divestment (net of $3.6 tax)		(6.4	)		(0.09	)
Adjusted Net Income from All Operations (Non-GAAP)		475.5			6.47
Loss from discontinued operations (net of $2.5 tax)		3.5			0.05
Gain from discontinued operations (net of $286.3 tax)		(440.1	)		(5.99	)
Adjusted Income from Continuing Operations (Non-GAAP)		38.9			0.53

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 certain divestments, impairment losses, certain non-cash mark-to-market derivative financial instruments, 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 9/30
($ in millions)	2015			2014
Energen Net Income (Loss) (GAAP)		(227.9	)		457.3
(Income) Loss associated w/ San Juan Basin divestment, net of tax		0.0			(6.4	)
Adjusted Net Income from Continuing Operations (Non-GAAP)		(227.9	)		450.8
Interest expense		10.1			11.5
Income tax expense (benefit) *		(130.3	)		12.5
Depreciation, depletion and amortization *		149.8			123.9
Accretion expense *		1.7			1.5
Exploration expense *		0.0			(2.9	)
Dry hole expense *		0.5			7.5
Adjustment for asset impairment		399.4			178.9
Adjustment for mark-to-market (gains) losses *		1.2			(147.3	)
Adjustment for loss from discontinued operations, net of tax		0.0			3.5
Adjustment for gain on disposal from discontinued operations, net of tax		0.0			(440.1	)
Energen Adjusted EBITDAX from Continuing Operations (Non-GAAP)		204.4			199.9

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 Ended 9/30/2015 and 9/30/2014.

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 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 September 30, 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	$	188,398				$	(2	)			$	188,400
Gain (loss) on derivative instruments		107,173					—					107,173
Total Revenues		295,571					(2	)				295,573
Operating Costs and Expenses
Oil, natural gas liquids & natural gas production		54,598		$	9.26		4		$	0.00		54,594		$	9.26
Production and ad valorem taxes		13,366		$	2.27		80		$	0.00		13,286		$	2.25
O&G Depreciation, depletion and amortization		148,298		$	25.17		—		$	0.00		148,298		$	25.17
FF&E Depreciation, depletion and amortization		1,483		$	0.25		—		$	0.00		1,483		$	0.25
Asset impairment		399,394					—					399,394
Exploration		493					—					493
General and administrative		23,631		$	4.01		—		$	0.00		23,631		$	4.01
Accretion of discount on asset retirement obligations		1,700					—					1,700
(Gain) loss on sale of assets and other		822					(22	)				844
Total costs and expenses		643,785					62					643,723
Operating Income (Loss)		(348,214	)				(64	)				(348,150	)
Other Income/(Expense)
Interest Expense		(10,084	)				—					(10,084	)
Other income		56					—					56
Total other expense		(10,028	)				—					(10,028	)
Income (Loss) from Continuing Operations Before
Income Taxes		(358,242	)				(64	)				(358,178	)
Income tax expense (benefit)		(130,338	)				(23	)				(130,315	)
Income (Loss) From Continuing Operations		(227,904	)				(41	)				(227,863	)
Discontinued Operations, net of tax
Income (loss) from discontinued operations		—					—					—
Gain on Disposal of discontinued ops		—					—					—
Income from discontinued ops		—					—					—
Net Income (Loss)	$	(227,904	)			$	(41	)			$	(227,863	)
Diluted Earnings Per Average Common Share
Continuing Operations	$	(2.89	)			$	—				$	(2.89	)
Discontinued Operations	$	—				$	—				$	—
Net Income (Loss)	$	(2.89	)			$	—				$	(2.89	)
Basic earning Per Average Common Share
Continuing Operations	$	(2.89	)			$	—				$	(2.89	)
Discontinued Operations	$	—				$	—				$	—
Net Income (Loss)	$	(2.89	)			$	—				$	(2.89	)
Oil		3,610					—					3,610
NGL		1,056					—					1,056
Natural Gas		1,227					—					1,227
Total Production (mboe)		5,893					—					5,893
Total Production (boepd)		64,054					—					64,054

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 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 September 30, 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	$	350,773				$	43,205					$	307,568
Gain (loss) on derivative instruments		147,735					5,525						142,210
Total Revenues		498,508					48,730						449,778
Operating Costs and Expenses
Oil, natural gas liquids & natural gas production		67,720		$	10.18		15,887		$	9.05			51,833		$	10.59
Production and ad valorem taxes		25,729		$	3.87		4,034		$	2.30			21,695		$	4.43
O&G Depreciation, depletion and amortization		137,773		$	20.71		15,128		$	8.62			122,645		$	25.05
FF&E Depreciation, depletion and amortization		1,331		$	0.20		49		$	0.03			1,282		$	0.26
Asset impairment		178,912					—						178,912
Exploration		8,417					3,848						4,569
General and administrative		27,784		$	4.18		(606	)	($	0.35	)		28,390		$	5.80
Accretion of discount on asset retirement obligations		1,924					394						1,530
(Gain) loss on sale of assets and other		747					—						747
Total costs and expenses		450,337					38,734						411,603
Operating Income (Loss)		48,171					9,996						38,175
Other Income/(Expense)
Interest Expense		(11,522	)				—						(11,522	)
Other income		37					—						37
Total other expense		(11,485	)				—						(11,485	)
Income (Loss) from Continuing Operations Before
Income Taxes		36,686					9,996						26,690
Income tax expense (benefit)		16,055					3,553						12,502
Income (Loss) From Continuing Operations		20,631					6,443						14,188
Discontinued Operations, net of tax
Income (Loss) from discontinued operations		(3,485	)				—						(3,485	)
Gain on Disposal of discontinued ops		440,105					—						440,105
Income from discontinued ops		436,620					—						436,620
Net Income (Loss)	$	457,251				$	6,443					$	450,808
Diluted Earnings Per Average Common Share
Continuing Operations	$	0.28				$	0.09					$	0.19
Discontinued Operations	$	5.94				$	—					$	5.94
Net Income (Loss)	$	6.22				$	0.09					$	6.13
Basic earning Per Average Common Share
Continuing Operations	$	0.28				$	0.09					$	0.19
Discontinued Operations	$	5.98				$	0.01					$	5.97
Net Income (Loss)	$	6.26				$	0.10					$	6.16
Oil		3,017					6						3,011
NGL		1,108					218						890
Natural Gas		2,526					1,531						995
Total Production (mboe)		6,651					1,755						4,896
Total Production (boepd)		72,293					19,076						53,217

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 held in the San Juan Basin 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 Reconciliation to GAAP Information	Quarter Ended June 30, 2015
	GAAP		San Juan Basin			Non-GAAP
Oil		3,594		(1	)		3,595
NGL		1,070		10			1,060
Natural Gas		1,189		38			1,151
Total Production (mboe)		5,853		47			5,806
Total Production (boepd)		64,319		516			63,802

Energen Production Excluding San Juan Divestment Reconciliation to GAAP Information	Year-to-Date Ended December 31, 2014
	GAAP		San Juan Basin		Non-GAAP
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		52,320

Note: Amounts may not sum due to rounding