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

October 30, 2013

Commission File Number	Registrant	State of Incorporation	IRS Employer Identification Number
1-7810 2-38960	Energen Corporation Alabama Gas Corporation	Alabama Alabama	63-0757759 63-0022000

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 October 30, 2013, Energen Corporation and Alabama Gas 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 or Alabama Gas 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 or Alabama Gas 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 October 30, 2013
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 ALABAMA GAS CORPORATION
October 30, 2013	By	/s/ Charles W. Porter, Jr.
	Charles W. Porter, Jr. Vice President, Chief Financial Officer and Treasurer of Energen Corporation and Alabama Gas Corporation

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EXHIBIT INDEX

EXHIBIT NUMBER		DESCRIPTION
99.1	*	Press Release dated October 30, 2013
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: 6:30 a.m. EDT	Contacts:	Julie S. Ryland
Wednesday, October 30, 2013		205.326.8421

FOUR NEW WOLFCAMP A WELLS GENERATE EXCITING RATES

ENERGEN REPORTS 3RD QUARTER 2013 OPERATING, FINANCIAL RESULTS

NORTH LOUISIANA/EAST TEXAS ASSETS HELD FOR SALE

Highlights

— New Wolfcamp A well in Reeves County sets known record for peak 24-hour IP (3-phase) of 2,229 boepd

— New well data enhances Wolfcamp potential in southern Delaware and Midland basins

— 3^rd Bone Spring, Wolfberry performance continues to be strong

— Oil production increases 21% from prior-year 3rd quarter; Permian Basin production rises 36%

— North Louisiana/East Texas assets held for sale

BIRMINGHAM, Alabama – Energen Corporation (NYSE: EGN) has tested four new Wolfcamp A wells in the Permian Basin during the third quarter of 2013. All produced at attractive initial rates, and oil accounted for more than 50 percent of the product stream in each well. The Bodacious C7-19 #1H in eastern Reeves County produced at a peak 24-hour rate of 2,229 boepd, which is the highest initial production (IP) rate for a southern Delaware Wolfcamp well to have been publicly disclosed to date. [See locator maps at www.energen.com]

“We are very pleased with our latest Wolfcamp results and increasingly excited about the potential success of this play not only in the Midland Basin but in the southern Delaware Basin, as well,” said James McManus, Energen’s chairman and chief executive officer. “We are looking forward in 2014 to accelerating the pace of Wolfcamp development in the Midland Basin, where we are seeing great consistency in Wolfcamp A results in Glasscock County, and to continuing the delineation of our sizeable acreage position in the southern Delaware Basin. With approximately 180,000 net Permian acres identified as having Wolfcamp potential, Energen’s unrisked drilling inventory could approach 5,300 locations (based on 80-acre spacing and 4,400-foot lateral lengths) if the play is successful on a large-scale basis.”

Non-Core Assets Held-for-Sale

Energen has classified its non-core North Louisiana/East Texas properties as held-for-sale effective September 30, 2013. At year-end 2012, proved reserves associated with these properties totaled 20.4 billion cubic feet equivalent (Bcfe), of which more than 98 percent are natural gas.

As a result, included in third quarter and year-to-date 2013 financial results is a write down of the book value of the North Louisiana/East Texas assets to the estimated fair value. This non-cash impairment charge is $24.6 million ($15.7 million after taxes, or $0.22 per diluted share) and is included in discontinued operations on the company’s income statement along with income from these properties and the company’s recently sold Black Warrior Basin assets.

Third Quarter Earnings

For the three months ended September 30, 2013, Energen reported a consolidated net loss of $19.3 million, or $0.27 per diluted share. Excluding non-cash items, Energen’s adjusted income from all operations (a non-GAAP measure) totaled $36.1 million, or $0.50 per diluted share, in the third quarter of 2013; in the same period last year, adjusted income from all operations was $31.8 million, or $0.44 per diluted share.

Non-cash items in the current-year third quarter were mark-to-market revenue losses of $63.6 million ($39.7 million after tax, or $0.55 per diluted share) and a write-down of North Louisiana/East Texas assets totaling $24.6 million ($15.7 million after tax, or $0.22 per diluted share). In the third quarter of 2012, mark-to-market revenue losses totaled $46.8 ($29.7 million after tax, or $0.41 per diluted share). [See “Non-GAAP Financial Measures” beginning on pp. 15 for more information and reconciliation.]

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After excluding income from discontinued operations (Black Warrior Basin and North Louisiana/East Texas), Energen’s adjusted income from continuing operations in the third quarter 2013 totaled $34.2 million, or $0.47 per diluted share in 2013, as compared with $28.2 million, or $0.39 per diluted share, in 2012. [See “Non-GAAP Financial Measures” beginning on pp. 15 for more information and reconciliation.]

The impact of a 15 percent increase in production from continuing operations, including a 21 percent increase in oil volumes, and higher realized oil and natural gas prices was partially offset by increased depreciation, depletion and amortization expense (DD&A), lease operating expense including production taxes (LOE), and administrative expense.

Relative to the company’s budget, third quarter 2013 adjusted income from all operations ($0.50 per diluted share) was below expectations largely due to higher stock-based compensation expense ($0.04 per diluted share) and increased exploration expense ($0.07 per diluted share) primarily associated with the write-off of approximately 4,200 miscellaneous acres of unproved leasehold.

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

[See “Non-GAAP Financial Measures” beginning on pp. 15 for more information]

	3Q13				3Q12
	$MM		$/dil. sh.		$MM		$/dil. sh.
Net Income All Operations (GAAP)	$	(19,298)	$	(0.27)	$	2,046	$	0.03
Less: Non-cash Mark-to-Market gain/(loss)		(39,674)		(0.55)		(29,734)		(0.41)
Adjusted Net Income All Operations (Non-GAAP)	$	20,376	$	0.28	$	31,780	$	0.44
Less: Discontinued Operations
Non-cash North Louisiana Asset Impairment		(15,678)		(0.22)		--		--
Adj. Income All Operations (ex non-cash)	$	36,054		0.50	$	31,780	$	0.44
Income from Discontinued Operations		1,866		0.03		3,551		0.05
Adj. Income Continuing Operations (Non-GAAP)	$	34,188	$	0.47	$	28,229	$	0.39

Energen’s adjusted EBITDA from all operations (excluding non-cash items) totaled $210.1 million in the third quarter of 2013 and compared with $162.3 million in the prior-year third quarter. The company’s oil and gas

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exploration and production unit, Energen Resources Corporation, had adjusted EBITDA from all operations (excluding non-cash items) of $209.9 million in the third quarter of 2013 and $163.9 million in the same period a year ago. [See “Non-GAAP Financial Measures” beginning on pp. 15 for more information and reconciliation.]

Energen’s adjusted EBITDA from continuing operations (excluding mark-to-market) totaled $208.3 million in the third quarter of 2013 and compared with $158.8 million in the prior-year third quarter. Energen Resources had adjusted EBITDA from continuing operations (excluding mark-to-market) of $208.1 million in the third quarter of 2013 and $160.4 million in the same period a year ago. [See “Non-GAAP Financial Measures” beginning on pp. 15 for more information and reconciliation.]

Wolfcamp Shale Exploration Results

(Locator map available at www. Energen.com)

MIDLAND BASIN WOLFCAMP

Well

County

Target  Zone

Lateral  length

Stimulation/  Frac Stages

Peak 24-Hour IP

Peak 30-day Average

Boepd

Oil   (Bopd)

NGL   (Bpd)

Gas   (Mcfd)

Boepd

Oil   (Bopd )

NGL   (Bpd)

Gas (Mcfd)

Llano 8-  8A 101H

Glasscock

A

4,250’

Slick water/  17

784

538

136

662

683

446

131

638

The early performance of the Llano 8-8A 101H, which was drilled in Glasscock County approximately 4 miles northwest of the Lavaca 38-101 #1H that was tested last quarter, was consistent with the Lavaca well. The Llano 8-8A 101H tested at peak 24-hour IP rate of 784 boepd (69% oil, 17% NGL, and 14% gas). The peak 30-day rate was 683 boepd (65% oil 19% NGL, and 16% gas).

Energen plans to drill 7 gross (7 net) Wolfcamp wells in Glasscock County this year. Three wells currently are in various stages of drilling and completion: one is an A-bench well with a 5,300 foot lateral, and two are B-bench wells with 6,700-foot laterals. Two spuds previously slated for December are now expected to be drilled in January.

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Delaware Basin

Well

County

Target  Zone

Lateral  length

Stimulation/  Frac Stages

Peak 24-Hour IP

Peak 30-day Average

Boepd

Oil  (Bopd)

NGL  (Bpd)

Gas  (Mcfd)

Boepd

Oil (Bopd)

NGL  (Bpd)

Gas (Mcfd)

Bodacious  C7-19 #1H

Reeves

A

4,500’

Slick water/  19

2,229

1,375

458

2,375

1,671

1,015

352

1,824

University  25-17 #1H

Ward

A

4,000’

Slick water/  17

1,079

760

167

914

769

500

141

771

Well

County

Target  Zone

Lateral  length

Stimulation/  Frac Stages

Peak 24-Hour IP

Peak 20-day Average

Boepd

Oil  (Bopd)

NGL  (Bpd)

Gas  (Mcfd)

Boepd

Oil  (Bopd)

NGL  (Bpd)

Gas (Mcfd)

Benton  3-12 #1H

Reeves

A

4,700

Slick water/  19

1,462

812

306

2,069

1,163

632

250

1,690

Energen’s second Reeves County Wolfcamp A well was drilled further east in the southern Delaware Basin. The Bodacious C7-19 #1H, tested at an outstanding peak 24-hour IP rate of 2,229 boepd; this 3-stream rate was 62% oil, 20% NGL, and 18% gas. The peak 30-day average rate (3-stream) was 1,671 boepd (61% oil, 21% NGL, 18% gas).

Also in Reeves County, close to the Pecos River near the intersection of Loving, Ward, and Reeves counties, Energen drilled the Benton 3-12 #1H that tested at a peak 24-hour IP rate of 1,462 boepd. This 3-stream rate was 56% oil, 21% NGL, and 23% gas. The peak 20-day average rate (3- stream) was 1,163 boepd (54% oil, 21% NGL, and 25% gas).

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The University 25-17 #1H in Ward County produced at a peak 24-hour initial rate (3-stream) of 1,079 boepd (70% oil, 16% NGL, 14% gas); the peak 30-day average rate (3-stream) was 769 boepd (65% oil, 18% NGL, and 17% gas).

Energen expects to drill a total of 10 gross (9 net) Wolfcamp wells in the basin this year. Three wells in Reeves County, including two B-bench wells, currently are in various stages of drilling, completion, and flow-back.

Permian Basin Development Results

Vertical Wolfberry Wells Continue Strong Performance

Energen Resources’ vertical Wolfberry wells continued to generate strong results in the third quarter. Forty-five gross (42 net) wells tested at an average peak 24-hour initial production rate (2-stream) of 129 boepd (68% oil). The peak 30-day average rate (2-stream) was 122 boepd (69% oil).

Energen has drilled 116 gross (106 net) Wolfberry wells through the first nine months of the year and plans to drill another 21 gross (20 net) wells in the fourth quarter. Energen estimates that its 26,700 net undeveloped Wolfberry acres in the Midland Basin support 668 net drilling locations on 40-acre spacing.

3^rd Bone Spring Development Wells Continue Solid Performance

In the company’s horizontal 3rd Bone Spring program in the southern Delaware Basin, Energen Resources tested 9 gross (9 net) wells in the third quarter of 2013 that had an average 24-hour peak rate (2-stream) of 1,153 boepd (66% oil). The 30-day average production rate (2-stream) of 8 gross (8 net) wells tested was 642 boepd (69% oil).

Energen plans to drill another 11 gross (10 net) wells in the fourth quarter – 4 net wells more than originally planned. On the east side of the Pecos River, the company’s core 3^rd Bone Spring holdings total approximately 30,000 net acres, of which 5,700 remain undeveloped. Energen Resources estimates that it has 36 potential locations remaining to be drilled on 160-acre spacing in this core area.

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Third Quarter 2013 Financial & Operating Results

ENERGEN RESOURCES

Excluding non-cash items, Energen Resources’ adjusted income from all operations totaled $45.1 million in the third quarter of 2013 and $42.1 million in the same period a year ago. Energen Resources’ adjusted income from continuing operations totaled $43.3 million in the third quarter of 2013 and $38.6 million in the same period a year ago.

Production from continuing operations in the third quarter increased 15 percent year-over-year. Oil and natural gas liquids (NGL) volumes increased 27 percent, reflecting the company’s focus on its assets in the liquids-rich Permian Basin. Third quarter production in the Permian Basin grew 36 percent year-over-year, including 62 percent in the Midland Basin and 78 percent in the Delaware Basin.

Production (MBOE)

Commodity	3Q13		3Q12		Change
Continuing Operations
Oil		2,764		2,275		21  %
NGL		874		600		46  %
Natural Gas		2,478		2,437		2  %
Total Continuing Operations		6,116		5,312		15  %
Total Discontinued Operations		642		714		(10) %
Total All Operations		6,758		6,026		12  %
Production from Continuing Operations by Area (MBOE)
Area	3Q13		3Q12		Change
Midland Basin		1,407		871		62  %
Delaware Basin		1,301		732		78  %
Central Basin Platform		1,106		1,207		(8) %
Total Permian Basin		3,814		2,810		36  %
San Juan Basin/Other		2,302		2,502		(8) %
Total Continuing Operations		6,116		5,312		15  %

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Average Realized Sales Prices from Continuing Operations

Commodity	3Q13		3Q12		Change
Oil (per barrel)	$	89.67	$	82.76		8  %
NGL (per gallon)	$	0.75	$	0.78		(4) %
Natural Gas (per Mcf)	$	4.06	$	3.66		11  %

Per-unit LOE from continuing operations in the third quarter of 2013 increased approximately 8 percent from the same period a year ago to $14.39 per barrel of oil equivalent (BOE). Base LOE and marketing and transportation expenses increased approximately 4.5 percent to $11.29 per BOE largely due to increased workovers and repairs and gathering and water disposal expenses, partially offset by lower expected ad valorem taxes. Commodity price-driven production taxes increased approximately 22 percent on a per-unit basis to $3.10 per unit.

Per-unit DD&A expense from continuing operations in the 3rd quarter of 2013 totaled $20.27 per BOE, increasing approximately 26 percent from the same period last year largely due to year-over-year increases in development costs and production and to the impact of reduced year-end 2012 natural gas reserves resulting from lower commodity prices.

Per-unit net G&A expense increased approximately 39 percent in the third quarter of 2013 to $4.84 per BOE primarily due to increased compensation expense tied to Energen’s stock price.

ALAGASCO

Energen’s utility operations under Alagasco generated a seasonal net loss of $9.0 million in the third quarter of 2013 as compared with a net loss of $10.0 million in the same period a year ago.

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Year-to-Date 2013 Financial & Operating Results

CONSOLIDATED

For the nine months ended September 30, 2013, Energen’s consolidated net income totaled $120.5 million, or $1.67 per diluted share. Excluding non-cash items, Energen’s year-to-date adjusted income from all operations (a non-GAAP measure) totaled $166.9 million, or $2.31 per diluted share; in the same period last year, adjusted income from all operations was $182.2 million, or $2.52 per diluted share.

Non-cash items in the current year-to-date period were mark-to-market revenue losses of $48.5 million ($30.7 million after tax, or $0.43 per diluted share) and a write-down of assets being held for sale in North Louisiana/East Texas totaling $24.6 million ($15.7 million after tax, or $0.22 per diluted share). In the same period in 2012, mark-to-market revenue gains totaled $34.0 ($22.0 million after tax, or $0.30 per diluted share) and a commodity price-driven write-down of East Texas assets totaled $21.5 million ($13.4 million, or 19 cents per diluted share). [See “Non-GAAP Financial Measures” beginning on pp. 15 for more information and reconciliation.]

After excluding income from discontinued operations (Black Warrior Basin and North Louisiana/East Texas), Energen’s adjusted income from continuing operations in the year-to-date 2013 totaled $160.6 million, or $2.22 per diluted share in 2013, as compared with $172.7 million, or $2.39 per diluted share, in 2012. [See “Non-GAAP Financial Measures” beginning on pp. 15 for more information and reconciliation.]

Energen’s adjusted EBITDA from all operations (excluding non-cash items) totaled $675.6 million in the first nine months of 2013 and compared with $605.5 million in the same period last year. Energen Resources’ adjusted EBITDA from all operations (excluding non-cash items) was $571.3 million in the first nine months of 2013 and $502.8 million in the same period a year ago. [See “Non-GAAP Financial Measures” beginning on pp. 15 for more information and reconciliation.]

Energen’s adjusted EBITDA from continuing operations (excluding mark-to-market) totaled $669.3 million in the year-to-date period 2013 and compared with $596.1 million in the same period a year ago. Energen Resources had adjusted EBITDA from continuing operations (excluding mark-to-market) of $565.0 million in the year-to-date period 2013 and $493.3 million in the same period a year ago. [See “Non-GAAP Financial Measures” beginning on pp. 15 for more information and reconciliation.]

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Reconciliation of GAAP Net Income to Adjusted Income from Continuing Operations

[See “Non-GAAP Financial Measures” on pp. 15 for more information]

	YTD13				YTD12
	$MM		$/dil. sh.		$MM		$/dil. sh.
Net Income All Operations (GAAP)	$	120,461	$	1.67	$	190,739	$	2.64
Less: Non-cash Mark-to-Market gain/(loss)		(30,733)		(0.43)		21,987		0.30
Adjusted Net Income All Operations (Non-GAAP)	$	151,194	$	2.09	$	168,752	$	2.33
Less: Discontinued Operations
Non-cash Asset Impairment		(15,678)		(0.22)		(13,416)		(0.19)
Adj. Income All Operations (ex non-cash)	$	166,872		2.31	$	182,168	$	2.52
Income from Discontinued Operations		6,269		0.09		9,432		0.13
Adj. Income Continuing Operations (Non-GAAP)	$	160,603	$	2.22	$	172,736	$	2.39

ENERGEN RESOURCES

Excluding non-cash items, Energen Resources’ adjusted income from all operations totaled $128.9 million through the first nine months of 2013 and $145.0 million in the same period a year ago. Energen Resources’ adjusted income from continuing operations totaled $122.6 million in the current year-to-date period and $135.6 million in the same period a year ago.

Year-to-date 2013 production from continuing operations increased 10 percent year-over-year. Oil and NGL volumes increased 21 percent, reflecting the company’s focus on its assets in the liquids-rich Permian Basin. In the Permian Basin, year-to-date production grew 28 percent year-over-year, including 40 percent in the Midland Basin and 82 percent in the Delaware Basin.

Production (MBOE)

Commodity	YTD13		YTD12		Change
Continuing Operations
Oil		7,670		6,414		20  %
NGL		2,345		1,881		25  %
Natural Gas		7,238		7,346		(1) %
Total Continuing Operations		17,253		15,641		10  %
Total Discontinued Operations		1,906		2,209		(14) %
Total All Operations		19,159		17,850		7  %

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Production from Continuing Operations by Area (MBOE)

Area	YTD13		YTD12		Change
Midland Basin		3,615		2,589		40  %
Delaware Basin		3,443		1,891		82  %
Central Basin Platform		3,328		3,635		(8) %
Total Permian Basin		10,386		8,115		28  %
San Juan Basin/Other		6,867		7,526		(9) %
Total Continuing Operations		17,253		15,641		10  %

Average Realized Sales Prices from Continuing Operations

Commodity	YTD13		YTD12		Change
Oil (per barrel)	$	87.59	$	84.47		4  %
NGL (per gallon)	$	0.74	$	0.80		(8) %
Natural Gas (per Mcf)	$	4.14	$	3.64		14  %

Per-unit LOE from continuing operations in the first nine months of 2013 increased approximately 18 percent from the same period a year ago to $15.07 per BOE. Base LOE and marketing and transportation expenses increased approximately 20 percent to $12.20 per BOE largely due to increased workovers and repairs, equipment rental, water disposal and gathering costs, and environmental compliance. Commodity price-driven production taxes increased approximately 13 percent on a per-unit basis to $2.87 per unit.

Per-unit DD&A expense from continuing operations in the first nine months of 2013 totaled $19.10 per BOE, increasing approximately 23 percent from the same period last year largely due to year-over-year increases in development costs and production and to the impact of reduced year-end 2012 natural gas reserves resulting from lower commodity prices.

Per-unit net G&A expense in the 2013 year-to-date period increased approximately 31 percent from the same period last year to $4.73 per BOE. This largely was due to increased stock-based compensation.

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ALAGASCO

Alagasco generated net income of $37.6 million through the first nine months of 2013. In the same period last year. The utility’s net income in the same period a year ago totaled $37.2 million.

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2013 Guidance

Energen’s guidance range for production from continuing operations for 2013 is 23.4-23.8 MMBOE, which is slightly below prior guidance for all operations after adjusting for 2.0 MMBOE of estimated discontinued operations. (Energen’s prior guidance for production from all operations was 25.7-26.1 MMBOE, issued on August 28; adjusting for discontinued operations, the prior guidance equated to production from continuing operations of 23.7-24.1 MMBOE).

The decrease in the production guidance range largely reflects lower gas and NGL volumes in the San Juan Basin, lower NGL production in the Permian Basin, and less oil production in the Delaware Basin. In the San Juan Basin, production is less than expected largely due to unanticipated workovers on some high-volume wells, unscheduled third-party plant downtime, pipeline imbalances, and delays/reduction in scheduled pay-adds. Most of these impacts were felt in the 3^rd quarter. Lower NGL production in the Permian Basin is due to drier gas being produced by some 3^rd Bone Spring wells and price-driven ethane rejection in the Midland Basin; the impact of these factors was felt in the 3^rd quarter and expected to continue for the remainder of the year. In the Delaware Basin, oil production is being hampered by interference issues in highly fractured areas in the 3^rd Bone Spring play.

Drilling capital in 2013 is estimated to be $1.08 billion in 2013, up $80 million from the prior estimate. The increase largely is due to increased drilling costs (largely related to mechanical drilling challenges in the company’s exploratory program and to overages in some development drilling), additional working interest (primarily in the Midland Basin), and a net increase in costs associated with program changes; the latter includes four additional 3^rd Bone Spring wells, additional facilities in the Delaware Basin, and increased non-operated projects partially offset by a reduction in testing, exploratory spuds, and lower drill-and-complete costs on numerous 3^rd Bone Spring wells.

Production (MMBOE)

Commodity	2013e  Production Midpoint	2012
Oil	10.5		8.8
NGL	3.3		2.6
Natural Gas	9.8		9.8
Production from Continuing Operations	23.4-23.8		21.2
Production from Discontinued Operations	2.0		2.9

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2013e Revised Drilling and Production Summary

	Operated  Wells Drilled Gross (Net)		Production  Midpoint
Midland Basin		144  (133)		5.3
Wolfberry		137  (126)		5.2
Wolfcamp		7      (7)		0.1
Delaware Basin		49    (46)		4.8
3rd Bone Spring		38    (36)		4.3
Wolfcamp		10      (9)		0.5
Wolfbone		1      (1)
Other Permian*		81    (78)		4.4
San Juan Basin/Other		(0)		9.1
Production from Continuing Operations				23.6
Production from Discontinued Operations				2.0

 * Includes 2 gross (2 net) injector wells

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2013e Capital Summary

Basin	Capital  ($MM)
Midland Basin	$	500
Delaware Basin	$	470
Other Permian	$	85
San Juan Basin/Other	$	25
Total	$	1,080

Energen’s revised guidance range for 2013 consolidated after-tax cash flows (excluding disposal gains or losses) is $889-$904 million. Energen Resources’ after-tax cash flows are estimated to be $788-$803 million, and Alagasco is expected to generate after-tax cash flows of approximately $101 million. In addition, the company has received net proceeds of approximately $150 million from the October sale of its Black Warrior Basin assets; these proceeds have been used to reduce short-term debt. [See “Non-GAAP Financial Measures” beginning on pp 15 for more information and reconciliation.]

Energen narrowed and lowered its range of guidance for 2013 income from all operations (excluding mark-to-market and disposal gains or losses) to $3.10-$3.30 per diluted share to reflect increased stock-based compensation, increased exploration expense for 3^rd quarter leasehold write-off, and lower production. Income from continuing operations in 2013 is estimated to be $3.05-$3.25 per diluted share.

In addition to the mark-to-market gains or losses recognized quarterly on derivative instruments, we expect a net gain on the disposal of assets in 2013. This is the result of a gain of $35.0 million ($23.2 million after tax) to be booked in the 4^th quarter for the October 2013 sale of the company’s Black Warrior Basin assets. Because this gain will more than offset the loss on the impairment of North Louisiana/East Texas assets that was recognized in the third quarter, the resulting net gain (after tax) on disposal for 2013 will be $7.5 million.

15

Energen Resources’ estimated exploration and production expenses from continuing operations per BOE in 2013 are:

Lease Operating expense
Base, marketing, and transportation	$  11.55 - $  11.75
Production taxes	$    2.75 - $    2.95
DD&A expense	$  19.05 - $  19.25
General & Administrative expense, net	$    4.65 - $    4.85
Interest expense	$    2.15 - $    2.35

Approximately 78 percent of the company’s total estimated production for the remainder of 2013 is hedged. Assumed prices applicable to Energen Resources’ unhedged volumes for the remainder of the year are $90.00 per barrel of oil, $0.86 per gallon of NGL, and $4.00 per Mcf of natural gas.

Hedges also are in place that limit the company’s exposure to the Midland to Cushing differential to approximately 30 percent of its estimated oil production for the remainder of 2013. Energen Resources has hedged the WTS Midland to WTI Cushing (sour oil) differential for 0.9 million barrels of oil production at an average price of $2.99 per barrel and the WTI Midland to WTI Cushing differential for 1.1 million barrels at an average price of $1.00 per barrel.

Energen’s 2013 guidance includes assumed prices applicable to Energen Resources’ unhedged oil basis differentials for the remainder of the year. They are $4.25 per barrel (sour oil) and $3.00 per barrel (WTI Midland to WTI Cushing). Energen estimates that approximately 68 percent of its oil production for the remainder of 2013 is sweet.

16

The company’s current hedge position for the last quarter of 2013 is as follows:

Commodity	Hedge  Volumes	2013e Production (Contg Ops) Midpoint	Hedge %	NYMEX Price
Oil	2.4 MMBO	2.8    MMBO	86 %	$      91.44 per barrel
NGL	12.0 MMgal	40.9    MMgal	29 %	$       1.02 per gallon
Natural Gas	13.5 Bcf	15.3    Bcf	89 %	$       4.62 per Mcf

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 Resources’ assumed San Juan and Permian basis differentials of $0.19 per Mcf.

Average realized oil and gas prices for Energen Resources’ 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 oil transportation charges of approximately $2.50 per barrel for the remainder of 2013; and average realized NGL prices will be net of transportation and fractionation fees that are estimated to average $0.11-$0.17 per gallon for the remainder of 2013. The company also has basin-specific natural gas contracts whereby Energen Resources will receive the contracted hedge price.

Given Energen’s hedge position for the remainder of the year, changes in commodity prices are not expected to have a significant impact on Energen’s 2013 cash flows. Every $1.00 change in the average NYMEX price of oil from $90 per barrel represents an estimated net impact of $175,000; every 1-cent change in the average price of liquids from $0.86 per gallon represents an estimated net impact of approximately $210,000; and every 10-cent change in the average NYMEX price of gas from $4.00 represents an estimated net impact of $30,000.

Price-related events such as substantial basis differential changes could cause earnings sensitivities to be different from those outlined above.

At the end of September 2013, Alagasco was on track to earn within its allowed range of return on average equity of $375-$380 million.

17

ENERGEN HEDGE POSITION STRONG IN 2014

Energen has built a strong hedge position in 2014 and has already started establishing its hedge position in 2015.

The company’s 2014 hedges are as follows:

Commodity	Hedge Volumes	NYMEX Price
Oil	9.8  MMBO	$  92.64 per barrel
Natural Gas	51.8  Bcf	$    4.59 per Mcf

The company’s 2015 hedges are as follows:

Commodity	Hedge Volumes	NYMEX Price
Oil	5.8  MMBO	$  88.85 per barrel
Natural Gas	6.0  Bcf	$    4.26 per Mcf

Basin-specific contract prices for natural gas have been converted for comparability purposes to a NYMEX-equivalent price by adding to them Energen Resources’ assumed San Juan and Permian basis differentials of $0.19 per Mcf in 2014 and 2015.

Average realized oil and gas prices for Energen Resources’ production associated with NYMEX contracts and unhedged production will reflect the impact of basis differentials; average realized oil prices also will reflect transportation charges; and average realized NGL prices will be net of transportation and fractionation fees.

18

CONFERENCE CALL

Energen will hold its quarterly conference call today, Wednesday, October 30, at 10:30 a.m. EDT. Members of the investment community may participate by calling 1-866-939-3921. 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. Through Energen Resources Corporation, the company has approximately 750 million barrels of oil-equivalent proved, probable, and possible reserves. These all-domestic reserves are located mainly in the Permian and San Juan basins. For more information, go to http://www.energen.com.

FORWARD LOOKING STATEMENT: This release contains statements expressing expectations of future plans, objectives and performance that constitute forward-looking statements made pursuant to the Safe Harbor provision of the Private Securities Litigation Reform Act of 1995. Except as otherwise disclosed, the Company’s forward-looking statements do not reflect the impact of possible or pending acquisitions, divestitures or restructurings. We undertake no obligation to correct or update any forward-looking statements, whether as a result of new information, future events or otherwise. All statements based on future expectations rather than on historical facts are forward-looking statements that are dependent on certain events, risks and uncertainties that could cause actual results to differ materially from those anticipated. In addition, the Company cannot guarantee the absence of errors in input data, calculations and formulas used in its estimates, assumptions and forecasts. A more complete discussion of risks and uncertainties that could affect future results of Energen and its subsidiaries is included in the Company’s periodic reports filed with the Securities and Exchange Commission.

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 September 30, 2013 and 2012

	3rd Quarter
(in thousands, except per share data)	2013		2012		Change
Operating Revenues
Oil and gas operations	$	272,038	$	214,620	$	57,418
Natural gas distribution		48,368		61,809		(13,441)
Total operating revenues		320,406		276,429		43,977
Operating Expenses
Cost of gas		20,435		20,924		(489)
Operations and maintenance		141,271		123,730		17,541
Depreciation, depletion and amortization		136,123		96,634		39,489
Taxes, other than income taxes		24,858		19,572		5,286
Accretion expense		1,771		1,605		166
Total operating expenses		324,458		262,465		61,993
Operating Income (Loss)		(4,052)		13,964		(18,016)
Other Income (Expense)
Interest expense		(17,689)		(17,195)		(494)
Other income		13,062		1,488		11,574
Other expense		(434)		(84)		(350)
Total other expense		(5,061)		(15,791)		10,730
Income (Loss) from Continuing Operations Before Income Taxes		(9,113)		(1,827)		(7,286)
Income tax expense (benefit)		(3,627)		(322)		(3,305)
Income (Loss) from Continuing Operations		(5,486)		(1,505)		(3,981)
Discontinued Operations, Net of Taxes
Income (loss) from discontinued operations		1,866		3,551		(1,685)
Gain (loss) on disposal		(15,678)		–		(15,678)
Income (Loss) from Discontinued Operations		(13,812)		3,551		(17,363)
Net Income (Loss)	$	(19,298)	$	2,046	$	(21,344)
Diluted Earnings Per Average Common Share			$		$
Continuing operations		(0.08)		(0.02)		(0.06)
Discontinued operations		(0.19)		0.05		(0.24)
Net Income (Loss)	$	(0.27)	$	0.03	$	(0.30)
Basic Earnings Per Average Common Share	$		$		$
Continuing operations		(0.08)		(0.02)		(0.06)
Discontinued operations		(0.19)		0.05		(0.24)
Net Income (Loss)	$	(0.27)	$	0.03	$	(0.30)
Diluted Avg. Common Shares Outstanding		72,346		72,316		30
Basic Avg. Common Shares Outstanding		72,346		72,130		216
Dividends Per Common Share	$	0.145	$	0.14	$	0.005

CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)

For the 9 months ending September 30, 2013 and 2012

	Year-to-date
(in thousands, except per share data)	2013		2012		Change
Operating Revenues
Oil and gas operations	$	875,350	$	799,339	$	76,011
Natural gas distribution		390,567		327,183		63,384
Total operating revenues		1,265,917		1,126,522		139,395
Operating Expenses
Cost of gas		163,448		94,179		69,269
Operations and maintenance		413,401		336,568		76,833
Depreciation, depletion and amortization		365,355		276,465		88,890
Taxes, other than income taxes		77,955		64,314		13,641
Accretion expense		5,187		4,691		496
Total operating expenses		1,025,346		776,217		249,129
Operating Income (Loss)		240,571		350,305		(109,734)
Other Income (Expense)
Interest expense		(51,751)		(48,447)		(3,304)
Other income		15,578		3,678		11,900
Other expense		(631)		(305)		(326)
Total other expense		(36,804)		(45,074)		8,270
Income (Loss) from Continuing Operations Before Income Taxes		203,767		305,231		(101,464)
Income tax expense (benefit)		73,897		110,508		(36,611)
Income (Loss) from Continuing Operations	$	129,870	$	194,723	$	(64,853)
Discontinued Operations, Net of Taxes
Income (loss) from operations		6,269		(3,984)		10,253
Gain (loss) on disposal		(15,678)		–		(15,678)
Income (Loss) from Discontinued Operations		(9,409)		(3,984)		(5,425)
Net Income (Loss)		120,461		190,739		(70,278)
Diluted Earnings Per Average Common Share	$		$		$
Continuing operations		1.80		2.69		(0.89)
Discontinued operations		(0.13)		(0.05)		(0.08)
Net Income (Loss)	$	1.67	$	2.64	$	(0.97)
Basic Earnings Per Average Common Share	$		$		$
Continuing operations		1.80		2.70		(0.90)
Discontinued operations		(0.13)		(0.06)		(0.07)
Net Income (Loss)	$	1.67	$	2.64	$	(0.97)
Diluted Avg. Common Shares Outstanding		72,272		72,301		(29)
Basic Avg. Common Shares Outstanding		72,220		72,121		99
Dividends Per Common Share	$	0.435	$	0.42	$	0.015

CONSOLIDATED BALANCE SHEETS (UNAUDITED)

As of September 30, 2013 and December 31, 2012

(in thousands)	September 30, 2013		December 31, 2012
ASSETS
Current Assets
Cash and cash equivalents	$	12,413	$	9,704
Accounts receivable, net of allowance		200,043		277,900
Inventories		61,684		63,994
Regulatory asset		11,213		45,515
Assets held for sale		183,862		–
Other		63,371		28,007
Total current assets		532,586		425,120
Property, Plant and Equipment
Oil and gas properties, net		4,997,661		4,673,886
Utility plant, net		876,570		842,643
Other property, net		29,733		25,107
Total property, plant and equipment, net		5,903,964		5,541,636
Other Assets
Regulatory asset		89,004		110,566
Long-term derivative instruments		12,786		40,577
Other		76,532		57,991
Total other assets		178,322		209,134
TOTAL ASSETS	$	6,614,872	$	6,175,890
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current Liabilities
Long-term debt due within one year	$	125,000	$	50,000
Notes payable to banks		901,000		643,000
Accounts payable		256,109		257,579
Regulatory liability		40,168		45,116
Other		219,012		164,087
Total current liabilities		1,541,289		1,159,782
Long-term debt		1,028,509		1,103,528
Deferred Credits and Other Liabilities
Regulatory liability		81,414		80,404
Deferred income taxes		979,898		905,601
Long-term derivative instruments		1,961		11,305
Other		212,135		238,580
Total deferred credits and other liabilities		1,275,408		1,235,890
Total Shareholders’ Equity		2,769,666		2,676,690
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY	$	6,614,872	$	6,175,890

SELECTED BUSINESS SEGMENT DATA (UNAUDITED)

For the 3 months ending September 30, 2013 and 2012

	3rd Quarter
(in thousands, except sales price data)	2013		2012		Change
Oil and Gas Operations (GAAP)
Operating revenues from continuing operations
Natural gas	$	62,073	$	49,422	$	12,651
Oil		183,950		147,710		36,240
Natural gas liquids		26,292		17,566		8,726
Other		(277)		(78)		(199)
Total (GAAP)	$	272,038	$	214,620	$	57,418
Oil and Gas Operations excluding mark-to-market (Non-GAAP)
Operating revenues from continuing operations
Natural gas	$	60,389	$	53,581	$	6,808
Oil		247,839		188,279		59,560
Natural gas liquids		27,647		19,590		8,057
Other		(277)		(78)		(199)
Total (Non-GAAP)*	$	335,598	$	261,372	$	74,226
Production volumes
Natural gas (MMcf)		14,868		14,622		246
Oil (MBbl)		2,764		2,275		489
Natural gas liquids (MMgal)		36.7		25.2		11.5
Total production volumes (MMcfe)		36,696		31,872		4,824
Total production volumes (MBOE)		6,116		5,312		804
Revenue per unit of production including effects of designated cash flow hedges
Natural gas (Mcf)	$	4.06	$	3.66	$	0.40
Oil (barrel)	$	89.67	$	82.76	$	6.91
Natural gas liquids (gallon)	$	0.75	$	0.78	$	(0.03)
Revenue per unit of production excluding effects of all derivative instruments
Natural gas (Mcf)	$	3.39	$	2.69	$	0.70
Oil (barrel)	$	103.22	$	86.55	$	16.67
Natural gas liquids (gallon)	$	0.68	$	0.68	$	–
Other data
Lease operating expense (LOE)
LOE and other	$	69,086	$	57,397	$	11,689
Production taxes		18,939		13,531		5,408
Total	$	88,025	$	70,928	$	17,097
Depreciation, depletion and amortization	$	125,060	$	86,062	$	38,998
General and administrative expense	$	29,626	$	18,468	$	11,158
Capital expenditures	$	257,759	$	323,037	$	(65,278)
Exploration expenditures	$	8,949	$	10,644	$	(1,695)
Operating income	$	18,607	$	26,913	$	(8,306)

*Operating revenues excluding mark-to-market losses of $63,560 and $46,752 in third quarter 2013 and 2012,  respectively.

Natural Gas Distribution
Operating revenues
Residential	$	31,201	$	30,658	$	543
Commercial and industrial		18,194		17,695		499
Transportation		13,197		13,505		(308)
Other		(14,224)		(49)		(14,175)
Total	$	48,368	$	61,809	$	(13,441)
Gas delivery volumes (MMcf)
Residential		1,384		1,378		6
Commercial and industrial		1,272		1,246		26
Transportation		11,237		11,252		(15)
Total		13,893		13,876		17
Other data
Depreciation and amortization	$	11,063	$	10,572	$	491
Capital expenditures	$	20,980	$	18,813	$	2,167
Operating income (loss)	$	(22,544)	$	(12,743)	$	(9,801)

SELECTED BUSINESS SEGMENT DATA (UNAUDITED)

For the 9 months ending September 30, 2013 and 2012

	Year-to-date
(in thousands, except sales price data)	2013		2012		Change
Oil and Gas Operations (GAAP)
Operating revenues from continuing operations
Natural gas	$	196,311	$	156,308	$	40,003
Oil		607,975		578,167		29,808
Natural gas liquids		71,556		64,970		6,586
Other		(492)		(106)		(386)
Total (GAAP)	$	875,350	$	799,339	$	76,011
Oil and Gas Operations excluding mark-to-market (Non-GAAP)
Operating revenues from continuing operations
Natural gas	$	179,701	$	160,429	$	19,272
Oil		671,836		541,812		130,024
Natural gas liquids		72,764		63,169		9,595
Other		(492)		(106)		(386)
Total (Non-GAAP)*	$	923,809	$	765,304	$	158,505
Production volumes
Natural gas (MMcf)		43,428		44,076		(648)
Oil (MBbl)		7,670		6,414		1,256
Natural gas liquids (MMgal)		98.5		79.0		19.5
Total production volumes (MMcfe)		103,518		93,846		9,672
Total production volumes (MBOE)		17,253		15,641		1,612
Revenue per unit of production including effects of designated cash flow hedges
Natural gas (Mcf)	$	4.14	$	3.64	$	0.50
Oil (barrel)	$	87.59	$	84.47	$	3.12
Natural gas liquids (gallon)	$	0.74	$	0.80	$	(0.06)
Revenue per unit of production excluding effects of all derivative instruments
Natural gas (Mcf)	$	3.51	$	2.51	$	1.00
Oil (barrel)	$	92.69	$	89.92	$	2.77
Natural gas liquids (gallon)	$	0.65	$	0.78	$	(0.13)
Other data
Lease operating expense (LOE)
LOE and other	$	210,455	$	159,052	$	51,403
Production taxes		49,598		39,882		9,716
Total	$	260,053	$	198,934	$	61,119
Depreciation, depletion and amortization	$	332,690	$	244,914	$	87,776
General and administrative expense	$	81,570	$	56,521	$	25,049
Capital expenditures	$	892,691	$	957,913	$	(65,222)
Exploration expenditures	$	13,902	$	13,382	$	52
Operating income	$	181,948	$	280,897	$	(98,949)

* Operating revenues excluding mark-to-market loss of $48,459 and gain of $34,035 in 2013 and 2012, respectively.

Natural Gas Distribution
Operating revenues
Residential	$	259,492	$	201,537	$	57,955
Commercial and industrial		103,419		84,889		18,530
Transportation		45,261		42,765		2,496
Other		(17,605)		(2,008)		(15,597)
Total	$	390,567	$	327,183	$	63,384
Gas delivery volumes (MMcf)
Residential		15,379		11,601		3,778
Commercial and industrial		7,434		6,137		1,297
Transportation		34,733		34,835		(102)
Total		57,546		52,573		4,973
Other data
Depreciation and amortization	$	32,665	$	31,551	$	1,114
Capital expenditures	$	67,790	$	51,786	$	16,004
Operating income	$	58,968	$	70,265	$	(11,297)

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 and asset impairments of natural gas properties. Adjusted Net Income from continuing operations further excludes income 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 9/30/2013
Consolidated Net Income ($ in millions except per share data)	Net Income			Per Diluted     Share
Net Income (GAAP)		(19.3	)		(0.27	)
Non-cash mark-to-market losses (net of $23.9 tax)		39.7			0.55
Non-cash impairment charge (net of $8.9 tax) (1)		15.7			0.22
Adjusted Net Income from All Operations, excluding non-cash items (Non-GAAP)		36.1			0.50
Income from discontinued operations (net of $1.1 tax)		(1.9	)		(0.03	)
Adjusted Net Income from Continuing Operations (Non-GAAP)		34.2			0.47

	Quarter Ended 9/30/2012
Consolidated Net Income ($ in millions except per share data)	Net Income			Per Diluted     Share
Net Income (GAAP)		2.0			0.03
Non-cash mark-to-market losses (net of $17.1 tax)		29.7			0.41
Adjusted Net Income from All Operations, excluding non-cash items (Non-GAAP)		31.8			0.44
Income from discontinued operations (net of $2.0 tax)		(3.6	)		(0.05	)
Adjusted Net Income from Continuing Operations (Non-GAAP)		28.2			0.39

	Year-to-Date Ended 9/30/2013
Consolidated Net Income ($ in millions except per share data)	Net Income			Per Diluted     Share
Net Income (GAAP)		120.5			1.67
Non-cash mark-to-market losses (net of $17.8 tax)		30.7			0.43
Non-cash impairment charge (net of $8.9 tax) (1)		15.7			0.22
Adjusted Net Income from All Operations, excluding non-cash items (Non-GAAP)		166.9			2.31
Income from discontinued operations (net of $1.1 tax)		(6.3	)		(0.09	)
Adjusted Net Income from Continuing Operations (Non-GAAP)		160.6			2.22

	Year-to-Date Ended 9/30/2012
Consolidated Net Income ($ in millions except per share data)	Net Income			Per Diluted     Share
Net Income (GAAP)		190.7			2.64
Non-cash mark-to-market gains (net of $12.0 tax)		(22.0	)		(0.30	)
Non-cash write-down of natural gas properties (net of $8.1 tax) (2)		13.4			0.19
Adjusted Net Income from All Operations, excluding non-cash items (Non-GAAP)		182.2			2.52
Income from discontinued operations (net of $2.0 tax)		(9.4	)		(0.13	)
Adjusted Net Income from Continuing Operations (Non-GAAP)		172.7			2.39

Note: Amounts may not sum due to rounding

(1) Current year-to-date and quarter-to-date loss on impairment ($15.7) included in gain (loss) on disposal of discontinued operations on the income statement

(2) Prior year-to-date write down of natural gas properties ($13.4) included in income (loss) from discontinued operations on the income statement

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 and asset impairments of natural gas properties. Adjusted Net Income from continuing operations further excludes income 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.

Energen Resources Net Income ($ in millions)	Quarter Ended   9/30/2013			Year-to-date   9/30/2013
Net Income (GAAP)		(10.2	)		82.4
Non-cash mark-to-market losses (net of $23.9 and $17.8 tax)		39.7			30.7
Non-cash impairment charge (net of $8.9 and $8.9 tax) (1)		15.7			15.7
Adjusted Net Income from All Operations, excluding non-cash items (Non-GAAP)		45.1			128.9
Income from discontinued operations (net of $1.1 and $3.7 tax)		(1.9	)		(6.3	)
Adjusted Net Income from Continuing Operations (Non-GAAP)		43.3			122.6

Energen Resources Net Income ($ in millions)	Quarter Ended   9/30/2012			Year-to-date   9/30/2012
Net Income (GAAP)		12.4			153.6
Non-cash mark-to-market losses (gains) (net of $17.1 and ($12.0) tax)		29.7			(22.0	)
Non-cash write down of natural gas properties (net of $8.1 tax) (2)		-			13.4
Adjusted Net Income from All Operations, excluding non-cash items (Non-GAAP)		42.1			145.0
Income from discontinued operations (net of ($2.0) and $2.0 tax)		(3.6	)		(9.4	)
Adjusted Net Income from Continuing Operations (Non-GAAP)		38.6			135.6

Note: Amounts may not sum due to rounding

(1) Current year-to-date and quarter-to-date loss on impairment ($15.7) included in gain (loss) on disposal of discontinued operations on the income statement

(2) Prior year-to-date write down of natural gas properties ($13.4) included in income (loss) from discontinued operations on the income statement

Non-GAAP Financial Measures

Earnings before interest, taxes, depreciation, and amortization (EBITDA) is a Non-GAAP financial measure (GAAP refers to generally accepted accounting principles). Adjusted EBITDA from all operations reflects EBITDA adjusted for certain non-cash mark-to-market derivative financial instruments and asset impairments. Adjusted EBITDA from continuing operations further excludes income from 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	Year-to-Date  Ended 9/30					Quarter Ended 9/30
($ in millions)	2012			2013		2012			2013
Consolidated Net Income (GAAP)		190.7			120.5		2.0			(19.3	)
Interest expense		48.4			51.8		17.2			17.7
Income tax expense		110.5			73.9		(0.3	)		(3.6	)
Depreciation, depletion and amortization		276.5			365.4		96.6			136.1
Adjustment for asset impairment, net of tax (1)		13.4			15.7		-			15.7
Adjustment for mark-to-market (gains) losses		(34.0	)		48.5		46.8			63.6
Consolidated Adjusted EBITDA from All Operations, excluding non-cash items (Non-GAAP)		605.5			675.6		162.3			210.1
Adjustment for income from discontinued operations, net of tax		9.4			6.3		3.6			1.9
Consolidated Adjusted EBITDA from Continuing Operations (Non-GAAP)		596.1			669.3		158.8			208.3

Reconciliation To GAAP Information	Year-to-Date  Ended 9/30					Quarter Ended 9/30
($ in millions)	2012			2013		2012		2013
Energen Resources Net Income (GAAP)		153.6			82.4		12.4		(10.2	)
Interest expense		36.8			40.5		13.3		14.0
Income tax expense		88.1			51.5		5.4		1.8
Depreciation, depletion and amortization		244.9			332.7		86.1		125.1
Adjustment for asset impairment, net of tax (1)		13.4			15.7		-		15.7
Adjustment for mark-to-market (gains) losses		(34.0	)		48.5		46.8		63.6
Energen Resources Adjusted EBITDA from All Operations, excluding non-cash items (Non-GAAP)		502.8			571.3		163.9		209.9
Adjustment for income from discontinued operations, net of tax		9.4			6.3		3.6		1.9
Energen Resources Adjusted EBITDA from Continuing Operations (Non-GAAP)		493.3			565.0		160.4		208.1

Note: Amounts may not sum due to rounding

(1) Current year-to-date and quarter-to-date loss on impairment ($15.7) included in gain (loss) on disposal of discontinued operations on the income statement. Prior year-to-date write down of natural gas properties ($13.4) included in income (loss) from discontinued operations on the income statement.

Non-GAAP Financial Measures

After-tax Cash Flows is a Non-GAAP financial measure (GAAP refers to generally accepted accounting principles). Energen believes after-tax cash flows are relevant because they are a measure of cash available to fund the Company’s capital expenditures, dividends, debt reduction, and other investments. Adjusted after-tax cash flows excluding Alagasco provides a measure of cash flows available to fund the Company’s exploration and production activities.

Reconciliation To GAAP Information	Years Ended 12/31
($ in millions)	2011 Actual			2012 Actual			2013 Estimate (e)
Consolidated Net Income (GAAP)		260			254			225		240
Depreciation, depletion and amortization		284			441			530		530
Deferred income taxes		129			124			109		109
Exploratory expense		11			17			-		-
Other		53			(34	)		25		25
After-tax Cash Flows (Non-GAAP)		737			802			889		904
Changes in assets and liabilities and other adjustments		25			(66	)		27		27
Net Cash Provided by Operating Activities (GAAP)		762			736			916		931
Reconciliation To GAAP Information	Years Ended 12/31
($ in millions)	2011 Actual			2012 Actual			2013 Estimate (e)
Net Cash Provided by Operating Activities (GAAP)		762			736			916		931
Changes in assets and liabilities and other adjustments		(25	)		66			(27	)	(27	)
After-tax Cash Flow (Non-GAAP)		737			802			889		904
Less: AGC cash flows from operations and other		(115	)		(103	)		(101	)	(101	)
Adj. After-tax Cash Flows Excluding Alagasco (Non-GAAP)		622			699			788		803

(e) This estimate is a “forward-looking statement” as defined by the Securities and Exchange Commission. All statements based on future expectations rather than on historical facts are forward-looking statements that are dependent on certain events, risks and uncertainties that could cause actual results to differ materially from those anticipated. In addition, the Company cannot guarantee the absence of errors in input data, calculations and formulas used in its estimates, assumptions and forecasts. A discussion of risks and uncertainties, which could affect future results of Energen and its subsidiaries, is included in the Company’s periodic reports filed with the Securities and Exchange Commission.