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 January 23, 2013

Commission File Number	Registrant	State of Incorporation	IRS Employer Identification Number
1-7810	Energen Corporation	Alabama	63-0757759
2-38960	Alabama Gas Corporation	Alabama	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 January 23, 2013, Energen Corporation and Alabama Gas Corporation issued a press release announcing the fourth quarter and year-to-date 2012 financial results. The press release and supplemental financial information are attached hereto as Exhibit 99.1 and 99.2.

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.

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 January 23, 2013
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 ALABAMA GAS CORPORATION
January 24, 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 January 23, 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.

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. EDT	Contacts: Julie S. Ryland
	Wednesday, January 23, 2013	205.326.8421
	ENERGEN REPORTS 4TH QUARTER AND CY12 OPERATING AND FINANCIAL RESULTS DOUBLE-DIGIT GROWTH GENERATES RECORD 24.1 MMBOE OF PRODUCTION Highlights •     18% growth drives 2012 production to record 24.1 MMBOE •     2012 oil production increases approximately 40% from prior year •     2012 proved reserves total 346 MMBOE despite significantly lower natural gas and NGL prices •     100 net Upper Wolfcamp locations in Midland Basin added to Energen’s 2012 unproved reserves •     Permian Basin now home to 65% of the company’s proved reserves •     Liquids comprise 56% of Energen’s 3P reserves •     Guidance affirmed for 2013 capital and drilling plans and production and cash flows BIRMINGHAM, Alabama – Energen Corporation (NYSE: EGN) announced today that its earnings in the three months ended December 31, 2012, totaled $62.8 million, or $0.87 per diluted share. Excluding non-cash mark-to-market gains on certain financial commodity contracts, Energen’s adjusted net income (a non-GAAP measure) totaled $47.2 million, or $0.65 per diluted share, and compared with 4th quarter 2011 adjusted net income of $71.0 million, or $0.98 per diluted share. Non-cash, mark-to-market revenue gains in the 4th quarter 2012 were $24.7 million ($15.7 million after tax, or $0.22 per diluted share). Non-cash, mark-to-market revenue losses in the same period in 2011 totaled $90.8 million ($56.6 million after tax, or $0.78 per diluted share). [See “Non-GAAP Financial Measures” for more information and reconciliation.]

Relative to the same period a year ago, production in the 4th quarter of 2012 increased 14 percent and realized oil prices rose 3 percent. More than offsetting these gains were significantly lower natural gas and natural gas liquids (NGL) prices, increased depreciation expense (DD&A), and higher lease operating expense (LOE). Also in the 4^th quarter of 2012, Energen wrote off $5.3 million ($3.4 million after tax, or $0.05 per diluted share) of Delaware Basin leasehold set to expire in the first half of 2013; the bulk of this acreage was located west of the Pecos River in Reeves County, Texas. (See pp 9-10 for additional 4^th quarter information).

Consolidated adjusted EBITDA (a non-GAAP measure) totaled $209.3 million and compared with $208.5 million in the prior-year 4th quarter. The company’s oil and gas exploration and production unit, Energen Resources Corporation, had adjusted EBITDA of $175.3 million in the 4th quarter of 2012 and $177.2 million in the same period a year ago. [See “Non-GAAP Financial Measures” for more information and reconciliation.]

“2012 was an exciting year for Energen. Record activity in the Permian Basin led to excellent performances from our 3^rd Bone Spring and Wolfberry wells as well as double-digit production growth,” said James McManus, Energen’s chairman and chief executive officer.

“We expect our continued development of the 3^rd Bone Spring sand east of the Pecos River in the Delaware Basin and the vertical Wolfberry in the Midland Basin to drive strong, double-digit production growth in the Permian Basin in 2013.

“And, at the same time, we are looking forward to exploring the potential offered by emerging horizontal plays in the Midland and Delaware basins.”

2

2012 Financial Results

Energen’s 2012 net income totaled $253.6 million, or $3.51 per diluted share. Excluding non-cash items, adjusted net income (a non-GAAP measure) totaled $229.7 million, or $3.18 per diluted share, and compared with prior-year adjusted results of $283.0 million, or $3.91 per diluted share.

Non-cash items in 2012 were mark-to-market revenue gains on certain financial commodity contracts of $58.8 million ($37.2 million after tax, or 52 cents per diluted share) and a commodity price-related write-down of natural gas properties in East Texas of $21.5 million ($13.4 million after tax, or 19 cents per diluted share). Mark-to-market revenue losses in 2011 totaled $37.6 million ($23.4 million after tax, or 32 cents per diluted share). [See “Non-GAAP Financial Measures” for explanation and reconciliation.]

Excluding non-cash items, Energen Resources’ adjusted 2012 net income totaled $180.3 million as compared with $236.4 million in 2011.

Consolidated adjusted EBITDA (a non-GAAP measure) in 2012 totaled $845.3 million and increased 10 percent from 2011 adjusted EBITDA of $771.7 million. Energen Resources’ adjusted 2012 EBITDA totaled $708.6 million and compared with 2011 adjusted EBITDA of $645.7 million. [See “Non-GAAP Financial Measures” for more information and reconciliation.].

Production in 2012 increased 18 percent year-over-year, including a 40 percent increase in oil production; and the average realized sales price of oil increased 5 percent. The company’s decreased net income relative to 2011 was driven largely by substantially lower natural gas and NGL prices, increased DD&A expense, and higher LOE.

Production (MMBOE)

Commodity	2012		2011		Change
Oil		8.8		6.3		40	%
NGL		2.6		2.2		18	%
Natural Gas		12.7		12.0		6	%
Total		24.1		20.5		18	%

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Production by Area (MMBOE)

Area	2012		2011		Change
Permian Basin		11.2		7.8		44	%
San Juan Basin		9.9		9.6		3	%
Other		3.0		3.1		(3	)%

Average Realized Sales Prices

Commodity	2012		2011		Change
Oil (per barrel)	$	83.45	$	79.72		5	%
NGL (per gallon)	$	0.79	$	0.96		(18	)%
Natural Gas (per Mcf)	$	3.79	$	5.39		(30	)%

Total LOE per unit in 2012 increased approximately 1 percent from the prior year to $12.73 per BOE. Base LOE and marketing and transportation expenses increased 5 percent to $10.41 per BOE largely due to increased water disposal costs, ad valorem taxes, and equipment rental partially offset by lower operations and maintenance expense. Commodity price-driven production taxes declined approximately 14 percent on a per-unit basis to $2.32 per unit.

DD&A expense per unit in 2012, excluding the first quarter write-down of natural gas properties in East Texas, increased approximately 32 percent from the same period last year to $15.50 per BOE; this increase generally reflected year-over-year increases in development costs.

ALAGASCO

Energen’s utility operations under Alagasco generated net income of $49.4 million in 2012; this $2.8 million increase from 2011 reflects the utility’s ability to earn on a higher level of equity representing investment in utility plant.

4

3^rd Bone Spring and Wolfberry Programs Generate Excellent Results in 2012

Energen Resources’ 3rd Bone Spring and Wolfberry programs wrapped up a successful 2012 with continued strong results in the 4^th quarter.

In the company’s horizontal 3^rd Bone Spring program in the Delaware Basin, Energen Resources tested 10 gross (10 net) wells in the 4^th quarter of 2012 that had an average initial stabilized rate of 1,007 BOE per day (61% oil). The 30-day average production rate of 7 gross (7 net) wells tested was 609 BOE per day (57% oil).

For the calendar year 2012, Energen Resources drilled 42 gross (40 net) 3^rd Bone Spring wells. The average initial stabilized rate of 38 gross (35 net) wells was 1,031 BOE per day (68% oil). The 30-day average production rate of 35 gross (32 net) wells with sufficient production history was 661 BOE per day (65% oil).

On the east side of the Pecos River, the company’s core holdings total approximately 30,000 net acres, of which 9,500 remain undeveloped. Energen Resources estimates that it has approximately 59 potential locations remaining to be drilled on 160-acre spacing in this core area.

Energen Resources’ vertical Wolfberry program in the Midland Basin finished the year strong. During 2012 the company drilled 172 gross (167 net) Wolfberry wells. Some 179 gross (172 net) wells — including 7 drilled in late 2011 – were completed and tested at an average initial stabilized rate of 90 BOE per day (75% oil); the average 30-day rate of the wells was 76 BOE per day (77% oil).

Through acquisition of proved property and leasehold during 2012, Energen Resources now has approximately 65,000 net acres in the Midland Basin that are prospective for the vertical Wolfberry play; approximately 34,000 net acres remain undeveloped. Based on 40-acre spacing, Energen Resources estimates that it has 850 potential locations remaining to be drilled; 20-acre downspacing could add another 800 locations.

Testing of the horizontal Wolfcamp shale continues in the Delaware Basin. The 4 wells remaining in the 2012 drilling program are in various stages of completion or testing. Successful results from these wells could help prove up the Wolfcamp potential in this region and add substantially to the company’s drilling inventory in the Delaware Basin.

5

Year-end Proved Reserves Total 346 MMBOE

Energen’s proved reserves at year-end 2012 totaled a record 346 MMBOE and were essentially unchanged from the prior year as record production and price-related, downward revisions offset the addition of previously classified unproved reserves and acquisition-related reserves. Oil and NGL reserves represent 61 percent of total proved reserves and are expected to increase as Energen continues to focus on the exploration and development of the liquids-rich Permian Basin.

Natural gas and NGL prices used for calculating reserves were down substantially in 2012 relative to 2011. Reserves pricing in 2012 was $2.76 per Mcf of gas vs $4.12 per Mcf in 2011; $0.88 per gallon of NGL (before transportation and fractionation) vs $1.23 per gallon in 2011; and $94.71 per barrel of oil vs $96.19 per barrel in the prior year.

The bulk of proved reserves added through acquisition were vertical Wolfberry in the Midland Basin. Of reserves that moved from unproved to proved, approximately 50 percent were 3^rd Bone Spring sands in the Delaware Basin, approximately 45 percent were vertical Wolfberry in the Midland Basin, and approximately 5 percent were waterfloods in the Central Basin Platform. Twenty-five percent of Energen’s proved reserves are undeveloped.

Proved Reserves by Basin (MMBOE)

Basin	YE11		2012 Production			2012 Acquisitions		Additions		Price/Other Revisions			YE12
Permian		183.6		(11.2	)		12.3		56.9		(16.6	)		225.0
San Juan Basin		129.6		(9.9	)		0.0		0.9		(19.7	)		100.9
Black Warrior/Other		29.9		(3.0	)		0.0		0.1		(6.5	)		20.5
TOTAL		343.1		(24.1	)		12.3		57.9		(42.8	)		346.4

Proved Reserves by Commodity (MMBOE)

Commodity	2012		2011		% Change
Oil		155.3		129.6		19.8
Natural gas liquids		56.2		54.0		4.1
Natural gas		134.9		159.5		(15.4	)
TOTAL		346.4		343.1		1.0

6

100 Net Upper Wolfcamp Locations Added to Midland Basin Unproved Reserves

Probable and possible reserves at year-end 2012 declined to 407 MMBOE. Substantially lower gas and NGL prices resulted in the loss of approximately 137 MMBOE of unproved San Juan reserves at the end of the 2012. In the Delaware Basin, 3^rd Bone Spring reserves west side of the Pecos River were revised down by some 64 MMBOE. Approximately 54 MMBOE of prior-year unproved reserves – primarily in the Delaware and Midland basins – were proved up.

The company added net reserves of approximately 36 MMBOE for 100 net Upper Wolfcamp locations in Glasscock County; this represents gross EURs of 460 MBOE per well assuming 160-acre spacing and 4,400’ horizontal lengths. Energen also gained 18 MMBOE of unproved Wolfberry reserves through acquisition.

Potential reserves not yet reflected in Energen’s probable and possible reserves include Wolfberry downspacing, horizontal Cline in the Midland Basin, horizontal Wolfcamp in the Delaware Basin, and horizontal Avalon shale in the Delaware Basin. Energen also has identified 685 net horizontal Wolfcamp locations (Upper, Middle, and Lower) that are not currently included in the company’s unproved reserves.

Oil and natural gas liquids now comprise more than 55 percent of Energen’s proved and unproved (3P) reserves, and the Permian Basin is home to 52 percent of the company’s 3P reserves.

YE2012 3P Reserves (MMBOE)

Basin	Proved		Probable		Possible		Total Unproved		3P Total
Permian		225.0		62.8		101.6		164.4		389.4
•  Delaware Basin		35.7		4.6		3.4		8.0		43.7
•  Midland Basin		110.1		44.8		38.6		83.4		193.5
•  Central Basin Platform		79.2		13.4		59.6		73.0		152.2
San Juan		100.9		49.4		188.5		237.9		338.9
Other		20.5		2.0		2.3		4.3		24.7
TOTAL		346.4		114.2		292.4		406.6		753.0

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

7

2013 Capital, Production Outlook Affirmed

Energen today affirmed its guidance for 2013 capital, production, cash flows, and earnings.

2013e Capital, Drilling, and Production Summary

	2013e Capital		2013e Wells		2013e		Production
	($MM)		Gross (Net)		Rig Count		2013e		2012
Midland Basin	$	465		185  (173)		10-11		5.6		3.5
Wolfberry	$	420		179  (167)		9-10
Wolfcamp/Cline	$	45		6      (6)		1
Delaware Basin	$	325		44    (38)		6		4.6		2.9
3rd Bone Spring	$	240		32    (28)		4
Wolfcamp/Wolfbone	$	85		12    (10)		2
Other Permian*	$	85		110    (88)		1-2		4.5		4.8
San Juan Basin/Other	$	25		0		0		11.4		12.9
TOTAL	$	900		339  (299)		17-19		26.1		24.1

* Includes 5 gross (4 net) injector wells

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Production (MMBOE)

Commodity	2013e		2012		Change
Oil		10.6		8.8		20	%
NGL		3.4		2.6		31	%
Natural Gas		12.1		12.7		(5	)%
Total		26.1		24.1		8	%

Energen’s guidance range for 2013 consolidated after-tax cash flows is $917-$946 million. Energen Resources’ after-tax cash flows are estimated to be $822-$851 million, and Alagasco’s utility operations are expected to generate after-tax cash flows of approximately $95 million. Net income in 2013 is estimated to be $219-$248 million, or $3.03-$3.43 per diluted share, and includes $22.2 million, or 31 cents per diluted share, of potential dry hole expense. Guidance does not include non-cash, mark-to-market gains or losses. [See “Non-GAAP Financial Measures” for more information and reconciliation.]

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

Lease Operating expense
Base, marketing, and transportation	$	10.25
Production taxes	$	2.48
DD&A expense	$	18.46
General & Administrative expense, net	$	3.57
Interest expense	$	2.27

Approximately 70 percent of the company’s total estimated production in 2013 is hedged, including 84 percent of estimated oil production, 31 percent of estimated NGL production, and 69 percent of estimated natural gas. Assumed prices applicable to Energen Resources unhedged volumes are $90.00 per barrel of oil, $0.89 per gallon of NGL, and $3.50 per Mcf of natural gas.

Hedges also are in place that limit the company’s exposure to the Midland to Cushing differential to only about 40 percent of its estimated oil production in 2013. Energen Resources has hedged the WTS Midland to WTI Cushing (sour oil) differential for 3.6 million barrels of oil production at an average price of $3.03 per barrel and the WTI Midland to WTI Cushing differential for 2.8 million barrels at an average price of $1.01 per barrel.

Energen’s 2013 guidance includes assumed prices applicable to Energen Resources’ unhedged oil basis differentials; on an annualized basis, these are $3.35 per barrel (sour) and $2.90 per barrel (WTI Midland to WTI Cushing). Energen estimates that 64 percent of its oil production in 2013 will be sweet.

The company’s current hedge position for 2013 is as follows:

Commodity	Hedge Volumes		Estimated Production		Hedge %			NYMEX Price
Oil		8.9 MMBO		10.6 MMBO		84	%	$	90.95 per barrel
NGL		44.5 MMgal		143.4 MMgal		31	%	$	1.02 per gallon
Natural Gas		50.0 Bcf		72.7 Bcf		69	%	$	4.63 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 $0.15 per Mcf.

10

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 in 2013; and average realized NGL prices will be net of transportation and fractionation fees that are estimated to average $0.11-$0.16 per gallon in 2013. The company also has basin-specific natural gas contracts whereby Energen Resources will receive the contracted hedge price.

Gains and losses from the change in fair value of derivative instruments that do not qualify for cash flow hedge accounting are reported in operating revenues each applicable reporting period and, therefore, can cause non-cash earnings volatility.

Sensitivity of 2013e Cash Flows and Earnings to Changes in Commodity Prices

Changes in commodity prices for the remainder of the year are estimated to have the following 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 $750,000, or 1.0 cent per diluted share.

• Every 1-cent change in the average price of liquids from $0.89 per gallon represents an estimated net impact of approximately $760,000, or 1.0 cent per diluted share.

• Every 10-cent change in the average NYMEX price of gas from $3.50 represents an estimated net impact of $1.0 million, or 1.4 cents per diluted share.

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

The company’s utility subsidiary has the opportunity to earn a return on average equity that is estimated to be approximately $375-$380 million in 2013.

4Q12 Financial Data

Excluding non-cash mark-to-market revenue gains, Energen Resources generated adjusted 4^th quarter 2012 net income of $34.9 million as compared with $59.9 million in 2011. [See “Non-GAAP Financial Measures” for more information and reconciliation.]

11

Production (MBOE)

Commodity	4Q12		4Q11		Change
Oil		2,339		1,744		34	%
NGL		692		591		17	%
Natural Gas		3,185		3,135		2	%
Total		6,216		5,470		14	%

Production by Area (MBOE)

Area	4Q12		4Q11		Change
Permian Basin		3,082		2,216		39	%
San Juan Basin		2,446		2,480		(1	)%
Other		688		774		(11	)%

Average Realized Sales Prices

Commodity	4Q12		4Q11		Change
Oil (per barrel)	$	80.65	$	78.52		3	%
NGL (per gallon)	$	0.77	$	0.97		(21	)%
Natural Gas (per Mcf)	$	3.87	$	5.14		(25	)%

Total LOE per unit in the 4^th quarter of 2012 increased approximately 18 percent from the same period a year ago to $13.81 per BOE. Base LOE and marketing and transportation expenses increased approximately 26 percent to $11.48 per BOE largely due to increased water disposal costs, workovers, ad valorem taxes, and equipment rental partially offset by lower operations and maintenance expense. Commodity price-driven production taxes declined approximately 10 percent on a per-unit basis to $2.32 per unit.

DD&A expense per unit in the 4^th quarter of 2012 increased approximately 28 percent from the same period last year to $17.19 per BOE; this increase generally reflected year-over-year increases in development costs.

ALAGASCO

Energen’s utility operations under Alagasco generated net income of $12.2 million in the 4^th quarter of 2012; this $0.9 million increase from the same period last year reflects the utility’s ability to earn on a higher level of equity representing investment in utility plant.

12

ENERGEN MAINTAINS STRONG HEDGE POSITIONS THROUGH 2014

Energen Resources has hedges in place through 2014 to help protect its future cash flows from commodity.

Energen Resources’ 2014 hedges are as follows:

Commodity	Hedge Volumes		NYMEX Price
Oil		9.8 MMBO	$	92.64 per barrel
Natural Gas		46.1 Bcf	$	4.61 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 $0.16 per Mcf and $0.13, respectively.

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 transportation charges; and average realized NGL prices will be net of transportation and fractionation fees. The company has basin-specific natural gas contracts whereby Energen Resources will receive the contracted hedge price. Gains and losses from the change in fair value of derivative instruments that do not qualify for cash flow hedge accounting are reported in operating revenues each applicable reporting period and, therefore, can cause non-cash earnings volatility.

CONFERENCE CALL

Energen will hold its quarterly conference call Thursday, January 24, at 11:00 a.m. EDT. Members of the investment community may participate by calling 1-866-901-2585. A live audio Webcast of the program as well as a replay may be accessed through Energen’s 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.

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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.

14

EX-99.2

Exhibit 99.2

CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)

For the 3 months ending December 31, 2012 and 2011

	4th Quarter
(in thousands, except per share data)	2012			2011			Change
Operating Revenues
Oil and gas operations	$	308,640		$	168,692		$	139,948
Natural gas distribution		124,406			119,456			4,950
Total operating revenues		433,046			288,148			144,898
Operating Expenses
Cost of gas		48,049			47,607			442
Operations and maintenance		126,022			100,356			25,666
Depreciation, depletion and amortization		118,735			84,438			34,297
Taxes, other than income taxes		23,121			22,335			786
Accretion expense		1,953			1,771			182
Total operating expenses		317,880			256,507			61,373
Operating Income		115,166			31,641			83,525
Other Income (Expense)
Interest expense		(17,098	)		(13,979	)		(3,119	)
Other income		708			1,706			(998	)
Other expense		(598	)		(106	)		(492	)
Total other expense		(16,988	)		(12,379	)		(4,609	)
Income Before Income Taxes		98,178			19,262			78,916
Income tax expense		35,355			4,830			30,525
Net Income	$	62,823		$	14,432		$	48,391
Diluted Earnings Per Average Common Share	$	0.87		$	0.20		$	0.67
Basic Earnings Per Average Common Share	$	0.87		$	0.20		$	0.67
Diluted Avg. Common Shares Outstanding		72,319			72,269			50
Basic Avg. Common Shares Outstanding		72,138			72,082			56
Dividends Per Common Share	$	0.14		$	0.135		$	0.005

1

CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)

For the 12 months ending December 31, 2012 and 2011

	Year-to-date
(in thousands, except per share data)	2012			2011			Change
Operating Revenues
Oil and gas operations	$	1,165,580		$	948,526		$	217,054
Natural gas distribution		451,589			534,953			(83,364	)
Total operating revenues		1,617,169			1,483,479			133,690
Operating Expenses
Cost of gas		142,228			233,523			(91,295	)
Operations and maintenance		477,883			419,119			58,764
Depreciation, depletion and amortization		419,598			283,997			135,601
Asset impairment		21,545			—			21,545
Taxes, other than income taxes		88,989			91,734			(2,745	)
Accretion expense		7,534			6,837			697
Total operating expenses		1,157,777			1,035,210			122,567
Operating Income		459,392			448,269			11,123
Other Income (Expense)
Interest expense		(65,556	)		(44,822	)		(20,734	)
Other income		4,448			2,334			2,114
Other expense		(903	)		(456	)		(447	)
Total other expense		(62,011	)		(42,944	)		(19,067	)
Income Before Income Taxes		397,381			405,325			(7,944	)
Income tax expense		143,819			145,701			(1,882	)
Net Income	$	253,562		$	259,624		$	(6,062	)
Diluted Earnings Per Average Common Share	$	3.51		$	3.59		$	(0.08	)
Basic Earnings Per Average Common Share	$	3.52		$	3.60		$	(0.08	)
Diluted Avg. Common Shares Outstanding		72,316			72,332			(16	)
Basic Avg. Common Shares Outstanding		72,119			72,056			63
Dividends Per Common Share	$	0.56		$	0.54		$	0.02

2

CONSOLIDATED BALANCE SHEETS (UNAUDITED)

As of December 31, 2012 and December 31, 2011

(in thousands)	December 31, 2012		December 31, 2011
ASSETS
Current Assets
Cash and cash equivalents	$	17,014	$	9,541
Accounts receivable, net of allowance		282,405		231,925
Inventories		63,994		74,012
Regulatory asset		45,515		57,143
Other		28,007		71,547
Total current assets		436,935		444,168
Property, Plant and Equipment
Oil and gas properties, net		4,673,886		3,783,842
Utility plant, net		842,643		813,428
Other property, net		25,107		23,506
Total property, plant and equipment, net		5,541,636		4,620,776
Other Assets
Regulatory asset		110,566		95,633
Long-term derivative instruments		40,577		31,056
Other		53,486		45,783
Total other assets		204,629		172,472
TOTAL ASSETS	$	6,183,200	$	5,237,416
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current Liabilities
Long-term debt due within one year	$	50,000	$	1,000
Notes payable to banks		643,000		15,000
Accounts payable		264,889		302,048
Regulatory liability		45,116		58,279
Other		164,087		167,552
Total current liabilities		1,167,092		543,879
Long-term debt		1,103,528		1,153,700
Deferred Credits and Other Liabilities
Regulatory liability		80,404		87,234
Deferred income taxes		905,601		806,127
Long-term derivative instruments		11,305		34,663
Other		238,580		179,650
Total deferred credits and other liabilities		1,235,890		1,107,674
Total Shareholders’ Equity		2,676,690		2,432,163
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY	$	6,183,200	$	5,237,416

3

SELECTED BUSINESS SEGMENT DATA (UNAUDITED)

For the 3 months ending December 31, 2012 and 2011

	4th Quarter
(in thousands, except sales price data)	2012			2011		Change
Oil and Gas Operations (GAAP)
Operating revenues
Natural gas	$	77,608		$	96,654	$	(19,046	)
Oil		211,067			47,490		163,577
Natural gas liquids		20,968			23,975		(3,007	)
Other		(1,003	)		573		(1,576	)
Total (GAAP)	$	308,640		$	168,692	$	139,948
Oil and Gas Operations excluding mark-to-market (Non-GAAP)
Operating revenues
Natural gas	$	74,002		$	96,654	$	(22,652	)
Oil		188,636			138,093		50,543
Natural gas liquids		22,290			24,184		(1,894	)
Other		(1,003	)		573		(1,576	)
Total (Non-GAAP)*	$	283,925		$	259,504	$	24,421
Production volumes
Natural gas (MMcf)		19,110			18,810		300
Oil (MBbl)		2,339			1,744		595
Natural gas liquids (MMgal)		29.1			24.8		4.3
Total production volumes (MMcfe)		37,296			32,820		4,476
Total production volumes (MBOE)		6,216			5,470		746
Revenue per unit of production including effects of designated cash flow hedges
Natural gas (Mcf)	$	3.87		$	5.14	$	(1.27	)
Oil (barrel)	$	80.65		$	78.52	$	2.13
Natural gas liquids (gallon)	$	0.77		$	0.97	$	(0.20	)
Revenue per unit of production excluding effects of all derivative instruments
Natural gas (Mcf)	$	3.27		$	3.45	$	(0.18	)
Oil (barrel)	$	81.09		$	90.89	$	(9.80	)
Natural gas liquids (gallon)	$	0.68		$	1.14	$	(0.46	)
Other data
Lease operating expense (LOE)
LOE and other	$	71,375		$	49,874	$	21,501
Production taxes		14,442			14,109		333
Total	$	85,817		$	63,983	$	21,834
Depreciation, depletion and amortization	$	108,016		$	74,128	$	33,888
General and administrative expense	$	14,453		$	16,973	$	(2,520	)
Capital expenditures	$	333,298		$	448,851	$	115,553
Exploration expenditures	$	5,976		$	514	$	5,462
Operating income	$	92,425		$	11,323	$	81,102

* Operating revenues excluding mark-to-market gains of $24,715 and losses of $90,812 in fourth quarter 2012 and 2011, respectively.

4

Natural Gas Distribution
Operating revenues
Residential	$	76,161	$	74,157	$	2,004
Commercial and industrial		30,822		29,186		1,636
Transportation		16,093		14,665		1,428
Other		1,330		1,448		(118	)
Total	$	124,406	$	119,456	$	4,950
Gas delivery volumes (MMcf)
Residential		4,413		4,407		6
Commercial and industrial		2,235		2,151		84
Transportation		13,271		10,901		2,370
Total		19,919		17,459		2,460
Other data
Depreciation and amortization	$	10,719	$	10,310	$	409
Capital expenditures	$	20,083	$	16,814	$	3,269
Operating income	$	22,951	$	20,675	$	2,276

5

SELECTED BUSINESS SEGMENT DATA (UNAUDITED)

For the 12 months ending December 31, 2012 and 2011

	Year-to-date
(in thousands, except sales price data)	2012		2011		Change
Oil and Gas Operations (GAAP)
Operating revenues
Natural gas	$	288,979	$	386,894	$	(97,915	)
Oil		790,345		467,320		323,025
Natural gas liquids		85,938		87,466		(1,528	)
Other		318		6,846		(6,528	)
Total (GAAP)	$	1,165,580	$	948,526	$	217,054
Oil and Gas Operations excluding mark-to-market (Non-GAAP)
Operating revenues
Natural gas	$	289,494	$	386,894	$	(97,400	)
Oil		731,559		504,793		226,766
Natural gas liquids		85,459		87,580		(2,121	)
Other		318		6,846		(6,528	)
Total (Non-GAAP)*	$	1,106,830	$	986,113	$	120,717
Production volumes
Natural gas (MMcf)		76,362		71,718		4,644
Oil (MBbl)		8,766		6,318		2,448
Natural gas liquids (MMgal)		108.1		91.4		16.7
Total production volumes (MMcfe)		144,396		122,688		21,708
Total production volumes (MBOE)		24,066		20,448		3,618
Revenue per unit of production including effects of designated cash flow hedges
Natural gas (Mcf)	$	3.79	$	5.39	$	(1.60	)
Oil (barrel)	$	83.45	$	79.72	$	3.73
Natural gas liquids (gallon)	$	0.79	$	0.96	$	(0.17	)
Revenue per unit of production excluding effects of all derivative instruments
Natural gas (Mcf)	$	2.71	$	3.93	$	(1.22	)
Oil (barrel)	$	87.56	$	90.53	$	(2.97	)
Natural gas liquids (gallon)	$	0.75	$	1.11	$	(0.36	)
Other data
Lease operating expense (LOE)
LOE and other	$	250,497	$	202,094	$	48,403
Production taxes		55,878		54,951		927
Total	$	306,375	$	257,045	$	49,330
Depreciation, depletion and amortization	$	377,328	$	244,081	$	133,247
Asset impairment	$	21,545	$	—	$	21,545
General and administrative expense	$	66,192	$	64,322	$	1,870
Capital expenditures	$	1,291,211	$	1,115,452	$	175,759
Exploration expenditures	$	19,363	$	13,110	$	6,253
Operating income	$	367,243	$	363,131	$	4,112

* Operating revenues excluding mark-to-market gains of $58,750 and losses of $37,587 in 2012 and 2011, respectively.

6

Natural Gas Distribution
Operating revenues
Residential	$	277,698		$	343,740		$	(66,042	)
Commercial and industrial		115,711			136,469			(20,758	)
Transportation		58,857			55,234			3,623
Other		(677	)		(490	)		(187	)
Total	$	451,589		$	534,953		$	(83,364	)
Gas delivery volumes (MMcf)
Residential		16,014			21,132			(5,118	)
Commercial and industrial		8,372			9,994			(1,622	)
Transportation		48,106			44,614			3,492
Total		72,492			75,740			(3,248	)
Other data
Depreciation and amortization	$	42,270		$	39,916		$	2,354
Capital expenditures	$	71,869		$	73,984		$	(2,115	)
Operating income	$	93,216		$	86,216		$	7,000

7

EX-99.3

Exhibit 99.3

Non-GAAP Financial Measures

The United States Securities and Exchange Commission requires public companies, such as Energen Corporation (the Company), to reconcile Non-GAAP (GAAP refers to generally accepted accounting principles) financial measures to related GAAP measures. Adjusted Net Income is a Non-GAAP financial measure which excludes certain non-cash mark-to-market derivative financial instruments and a commodity price-related write-down of natural gas properties. Energen believes that excluding the impact of these items is more useful to analysts and investors in comparing the results of operations and operational trends between reporting periods and relative to other oil and gas producing companies.

	Quarter Ended 12/31/2012
Consolidated Net Income ($ in millions except per share data)	Net Income			Per Diluted Share
Net Income (GAAP)		62.8			0.87
Non-cash mark-to-market gains (net of $9.0 tax)		(15.7	)		(0.22	)
Adjusted Net Income (Non-GAAP)		47.2			0.65
	Quarter Ended 12/31/2011
Consolidated Net Income ($ in millions except per share data)	Net Income			Per Diluted Share
Net Income (GAAP)		14.4			0.20
Non-cash mark-to-market losses (net of $34.2 tax)		56.6			0.78
Adjusted Net Income (Non-GAAP)		71.0			0.98
	Year-to-Date Ended 12/31/2012
Consolidated Net Income ($ in millions except per share data)	Net Income			Per Diluted Share
Net Income (GAAP)		253.6			3.51
Non-cash mark-to-market gains (net of $21.6 tax)		(37.2	)		(0.52	)
Non-cash write-down of natural gas properties (net of $8.1 tax)		13.4			0.19
Adjusted Net Income (Non-GAAP)		229.7			3.18
	Year-to-Date Ended 12/31/2011
Consolidated Net Income ($ in millions except per share data)	Net Income			Per Diluted Share
Net Income (GAAP)		259.6			3.59
Non-cash mark-to-market losses (net of $14.2 tax)		23.4			0.32
Adjusted Net Income (Non-GAAP)		283.0			3.91

Note: Amounts may not sum due to rounding

Non-GAAP Financial Measures

The United States Securities and Exchange Commission requires public companies, such as Energen Corporation (the Company), to reconcile Non-GAAP (GAAP refers to generally accepted accounting principles) financial measures to related GAAP measures. Adjusted Net Income is a Non-GAAP financial measure which excludes certain non-cash mark-to-market derivative financial instruments and a commodity price-related write-down of natural gas properties. 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 12/31/2012			Year-to-date 12/31/2012
Net Income (GAAP)		50.6			204.1
Non-cash mark-to-market gains (net of $9.0 and $21.6 tax)		(15.7	)		(37.2	)
Non-cash write-down of natural gas properties (net of $8.1 tax)		—			13.4
Adjusted Net Income (Non-GAAP)		34.9			180.3
Energen Resources Net Income ($ in millions)	Quarter Ended 12/31/2011			Year-to-date 12/31/2011
Net Income (GAAP)		3.3			213.0
Non-cash mark-to-market losses (net of $34.2 and $14.2 tax)		56.6			23.4
Adjusted Net Income (Non-GAAP)		59.9			236.4

Non-GAAP Financial Measures

The United States Securities and Exchange Commission requires public companies, such as Energen Corporation (the Company), to reconcile Non-GAAP (GAAP refers to generally accepted accounting principles) financial measures to related GAAP measures. Earnings before interest, taxes, depreciation, and amortization (EBITDA) is a Non-GAAP financial measure. Energen believes this measure allows analysts and investors to understand the financial performance of the company by computing earnings from core business operations, without including the effects of capital structure, tax rates and depreciation. Further, this measure is useful in comparing profitability between the company and other oil and gas producing companies. Adjusted EBITDA excludes certain non-cash mark-to-market derivative financial instruments and a commodity price-related write-down of natural gas properties.

Reconciliation To GAAP Information ($ in millions)	Year-to-Date Ended 12/31					Quarter Ended 12/31
	2011		2012			2011			2012
Consolidated Net Income (GAAP)		259.6		253.6			14.4			62.8
Interest expense		44.8		65.6			14.0			17.1
Income tax expense		145.7		143.8			4.8			35.4
Depreciation, depletion and amortization		284.0		419.6			84.4			118.7
EBITDA (Non-GAAP)		734.1		882.5			117.7			234.0
Adjustment for asset impairment		—		21.5			—			—
Adjustment for mark-to-market (gains) / losses		37.6		(58.8	)		90.8			(24.7	)
Consolidated Adjusted EBITDA (Non-GAAP)		771.7		845.3			208.5			209.3
Reconciliation To GAAP Information ($ in millions)	Year-to-Date Ended 12/31					Quarter Ended 12/31
	2011		2012			2011			2012
Energen Resources Net Income (GAAP)		213.0		204.1			3.3			50.6
Interest expense		30.9		50.0			10.4			13.1
Income tax expense		120.1		114.4			(1.5	)		28.3
Depreciation, depletion and amortization		244.1		377.3			74.1			108.0
Energen Resources EBITDA (Non-GAAP)		608.1		745.8			86.4			200.0
Adjustment for asset impairment		—		21.5			—			—
Adjustment for mark-to-market (gains) / losses		37.6		(58.8	)		90.8			(24.7	)
Energen Resources Adjusted EBITDA (Non-GAAP)		645.7		708.6			177.2			175.3

Note: Amounts may not sum due to rounding

Non-GAAP Financial Measures

The United States Securities and Exchange Commission requires public companies, such as Energen Corporation (the Company), to reconcile Non-GAAP (GAAP refers to generally accepted accounting principles) financial measures to related GAAP measures. After-tax Cash Flows is a Non-GAAP financial measure. 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.

Reconciliation To GAAP Information ($ in millions)	Years Ended 12/31
	2011 Actual			2012 Actual			2013 Estimate (e)
Consolidated Net Income (Before asset impairment)		260			268			219		248
Asset impairment		—			(14	)		—		—
Consolidated Net Income (GAAP)		260			254			219		248
Depreciation, depletion and amortization (Including asset impairment)		284			441			530		530
Deferred income taxes, net		129			124			110		110
Exploratory expense		11			17			35		35
Other		53			(34	)		23		23
After-tax Cash Flows (Non-GAAP)		737			802			917		946
Changes in assets and liabilities and other adjustments		25			(64	)		—		—
Net Cash Provided by Operating Activities (GAAP)		762			738			917		946
Reconciliation To GAAP Information ($ in millions)	Years Ended 12/31
	2011 Actual			2012 Actual			2013 Estimate (e)
Net Cash Provided by Operating Activities (GAAP)		762			738			917		946
Changes in assets and liabilities and other adjustments		(25	)		64			—		—
After-tax Cash Flow (Non-GAAP)		737			802			917		946
Less: AGC cash flows from operations and other		(115	)		(103	)		(95	)	(95	)
Adj. After-tax Cash Flows Excluding Alagasco (Non-GAAP)		622			699			822		851

(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.