10-Q/A

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, DC 20549

____________________________________________

FORM 10-Q/A

Amendment No. 1

x QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 FOR THE QUARTERLY PERIOD ENDED SEPTEMBER 30, 2012

OR

o  TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 FOR THE TRANSITION PERIOD FROM ______________ TO _______________

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 35203-2707

Telephone Number 205/326-2700

http://www.energen.com

Alabama Gas Corporation, a wholly owned subsidiary of Energen Corporation, meets the conditions set forth in General Instruction H(1)(a) and (b) of Form 10-Q and is therefore filing this Form with reduced disclosure format pursuant to General Instruction H(2).

Indicate by a check mark whether the registrants (1) have filed all reports required to be filed by Section 13 or 15(d) of the Securities and Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrants were required to file such reports), and (2) have been subject to such filing requirements for the past 90 days. YES x NO o

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding

12 months (or for such shorter period that the registrant was required to submit and post such files).

Energen Corporation	YES	x	NO	o
Alabama Gas Corporation	YES	x	NO	o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

Energen Corporation - Large accelerated filer x Accelerated filer o Non-accelerated filer o Smaller reporting company o

Alabama Gas Corporation - Large accelerated filer o Accelerated filer o Non-accelerated filer x Smaller reporting company o

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).

Energen Corporation	YES	o	NO	x
Alabama Gas Corporation	YES	o	NO	x

Indicate the number of shares outstanding of each of the issuers’ classes of common stock, as of October 30, 2012.

Energen Corporation	$0.01 par value	72,146,547 shares
Alabama Gas Corporation	$0.01 par value	1,972,052 shares

EXPLANATORY NOTE

This Amendment No. 1 to our Quarterly Report on Form 10-Q for the quarter ended September 30, 2012, previously filed with the Securities and Exchange Commission (the Commission) on November 7, 2012, is being filed for the sole purpose of correcting the ending totals on the Consolidated Condensed Statements of Comprehensive Income. In connection with generation of the XBRL document for filing with the Commission, typographical errors resulted in incorrect Comprehensive Income or Loss totals for the three months ended September 30, 2012 and 2011 and for the nine months ended September 30, 2012. These totals have been corrected in this filing. Except as described above, no other changes have been made to the original filing and this Form 10-Q/A does not amend any other items or disclosures in the original filing.

ENERGEN CORPORATION AND ALABAMA GAS CORPORATION

FORM 10-Q/A FOR THE QUARTER ENDED SEPTEMBER 30, 2012

TABLE OF CONTENTS

		Page
PART I: FINANCIAL INFORMATION
Item 1.	Financial Statements (Unaudited)
	(a) Consolidated Condensed Statements of Income of Energen Corporation	4
	(b) Consolidated Condensed Statements of Comprehensive Income of Energen Corporation	5
	(c) Consolidated Condensed Balance Sheets of Energen Corporation	6
	(d) Consolidated Condensed Statements of Cash Flows of Energen Corporation	8
	(e) Condensed Statements of Income of Alabama Gas Corporation	9
	(f) Condensed Balance Sheets of Alabama Gas Corporation	10
	(g) Condensed Statements of Cash Flows of Alabama Gas Corporation	12
	(h) Notes to Unaudited Condensed Financial Statements	13
Item 2.	Management's Discussion and Analysis of Financial Condition and Results of Operations	29
	Selected Business Segment Data of Energen Corporation	40
Item 3.	Quantitative and Qualitative Disclosures about Market Risk	42
Item 4.	Controls and Procedures	43
PART II: OTHER INFORMATION
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	44
Item 6.	Exhibits	44
SIGNATURES		45

3

PART I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

CONSOLIDATED CONDENSED STATEMENTS OF INCOME
ENERGEN CORPORATION
(Unaudited)
	Three months ended						Nine months ended
	September 30,						September 30,
(in thousands, except per share data)	2012			2011			2012			2011
Operating Revenues
Oil and gas operations	$	233,515		$	318,952		$	856,940		$	779,834
Natural gas distribution	61,809			59,616			327,183			415,497
Total operating revenues	295,324			378,568			1,184,123			1,195,331
Operating Expenses
Cost of gas	20,924			21,748			94,179			185,916
Operations and maintenance	128,587			111,749			351,861			318,763
Depreciation, depletion and amortization	104,338			72,802			300,863			199,559
Asset impairment	—			—			21,545			—
Taxes, other than income taxes	20,110			20,129			65,868			69,399
Accretion expense	1,907			1,728			5,581			5,066
Total operating expenses	275,866			228,156			839,897			778,703
Operating Income	19,458			150,412			344,226			416,628
Other Income (Expense)
Interest expense	(17,198		)	(11,976		)	(48,458		)	(30,843		)
Other income	1,523			619			3,740			1,727
Other expense	(84		)	(2,074		)	(305		)	(1,449		)
Total other expense	(15,759		)	(13,431		)	(45,023		)	(30,565		)
Income Before Income Taxes	3,699			136,981			299,203			386,063
Income tax expense	1,653			49,382			108,464			140,871
Net Income	$	2,046		$	87,599		$	190,739		$	245,192
Diluted Earnings Per Average Common Share	$	0.03		$	1.21		$	2.64		$	3.39
Basic Earnings Per Average Common Share	$	0.03		$	1.22		$	2.64		$	3.40
Dividends Per Common Share	$	0.140		$	0.135		$	0.420		$	0.405
Diluted Average Common Shares Outstanding	72,316			72,375			72,301			72,409
Basic Average Common Shares Outstanding	72,130			72,068			72,121			72,045

The accompanying notes are an integral part of these unaudited consolidated condensed financial statements.

4

CONSOLIDATED CONDENSED STATEMENTS OF COMPREHENSIVE INCOME
ENERGEN CORPORATION
(Unaudited)
	Three months ended						Nine months ended
	September 30,						September 30,
(in thousands)	2012			2011			2012			2011
Net Income	$	2,046		$	87,599		$	190,739		$	245,192
Other comprehensive income (loss):
Current period change in fair value of commodity derivative instruments, net of tax of ($30,622), $105,683, $30,621 and $76,616	(49,962		)	172,430			49,961			125,005
Reclassification adjustment for commodity derivative instruments, net of tax of ($4,924), ($6,399), ($14,303) and ($6,181)	(8,034		)	(10,440		)	(23,337		)	(10,085		)
Pension and postretirement plans:
Amortization of net obligation at transition, net of taxes of $25, $24, $75 and $72	47			44			140			133
Amortization of prior service cost, net of taxes of $30, $26, $89 and $78	55			48			166			145
Amortization of net loss, net of taxes of $413, $318, $1,238 and $953	766			591			2,300			1,770
Current period change in fair value of pension and postretirement plans, net of taxes of ($4,073), ($5,988), ($4,073) and ($5,988)	(7,564		)	(11,121		)	(7,564		)	(11,121		)
Total pension and postretirement plans	(6,696		)	(10,438		)	(4,958		)	(9,073		)
Current period change in fair value of interest rate swap, net of tax of ($375) and ($1,205)	(697		)	—			(2,240		)	—
Reclassification adjustment for interest rate swap, net of tax of $142 and $422	263			—			783			—
Comprehensive Income (Loss)	$	(63,080	)	$	239,151		$	210,948		$	351,039

The accompanying notes are an integral part of these unaudited consolidated condensed financial statements.

5

CONSOLIDATED CONDENSED BALANCE SHEETS
ENERGEN CORPORATION
(Unaudited)
(in thousands)	September 30, 2012		December 31, 2011
ASSETS
Current Assets
Cash and cash equivalents	$	47,137	$	9,541
Accounts receivable, net of allowance for doubtful accounts of $6,649 at September 30, 2012, and $12,946 at December 31, 2011	194,473		231,925
Inventories
Storage gas inventory	36,849		44,047
Materials and supplies	33,596		26,420
Liquified natural gas in storage	3,505		3,545
Regulatory asset	56,188		57,143
Income tax receivable	5,526		7,343
Deferred income taxes	32,993		48,818
Prepayments and other	16,998		15,386
Total current assets	427,265		444,168
Property, Plant and Equipment
Oil and gas properties, successful efforts method	6,110,988		5,166,368
Less accumulated depreciation, depletion and amortization	1,662,144		1,382,526
Oil and gas properties, net	4,448,844		3,783,842
Utility plant	1,395,454		1,358,266
Less accumulated depreciation	560,279		544,838
Utility plant, net	835,175		813,428
Other property, net	23,953		23,506
Total property, plant and equipment, net	5,307,972		4,620,776
Other Assets
Regulatory asset	94,869		95,633
Long-term derivative instruments	43,137		31,056
Deferred charges and other	46,586		45,783
Total other assets	184,592		172,472
TOTAL ASSETS	$	5,919,829	$	5,237,416

The accompanying notes are an integral part of these unaudited consolidated condensed financial statements.

6

CONSOLIDATED CONDENSED BALANCE SHEETS
ENERGEN CORPORATION
(Unaudited)
(in thousands, except share and per share data)	September 30, 2012			December 31, 2011
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current Liabilities
Long-term debt due within one year	$	—		$	1,000
Notes payable to banks	480,000			15,000
Accounts payable	264,930			302,048
Accrued taxes	55,416			32,359
Customers' deposits	23,563			23,950
Amounts due customers	21,828			21,065
Accrued wages and benefits	24,618			35,258
Regulatory liability	27,372			58,279
Royalty payable	38,313			22,592
Other	27,191			32,328
Total current liabilities	963,231			543,879
Long-term debt	1,153,591			1,153,700
Deferred Credits and Other Liabilities
Asset retirement obligation	115,191			107,340
Pension and other postretirement liabilities	82,993			62,532
Regulatory liability	77,692			87,234
Long-term derivative instruments	11,110			34,663
Deferred income taxes	885,839			806,127
Other	9,093			9,778
Total deferred credits and other liabilities	1,181,918			1,107,674
Commitments and Contingencies
Shareholders’ Equity
Preferred stock, cumulative $0.01 par value, 5,000,000 shares authorized	—			—
Common shareholders’ equity
Common stock, $0.01 par value; 150,000,000 shares authorized, 75,062,599 shares issued at September 30, 2012, and 75,007,412 shares issued at December 31, 2011	751			750
Premium on capital stock	491,416			482,918
Capital surplus	2,802			2,802
Retained earnings	2,261,332			2,100,885
Accumulated other comprehensive income (loss), net of tax
Unrealized gain on hedges, net	35,897			9,273
Pension and postretirement plans	(43,542		)	(38,584		)
Interest rate swap	(2,398		)	(941		)
Deferred compensation plan	3,433			3,511
Treasury stock, at cost: 3,031,622 shares at September 30, 2012, and 3,036,549 shares at December 31, 2011	(128,602		)	(128,451		)
Total shareholders' equity	2,621,089			2,432,163
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY	$	5,919,829		$	5,237,416

The accompanying notes are an integral part of these unaudited consolidated condensed financial statements.

7

CONSOLIDATED CONDENSED STATEMENTS OF CASH FLOWS
ENERGEN CORPORATION
(Unaudited)
Nine months ended September 30, (in thousands)	2012			2011
Operating Activities
Net income	$	190,739		$	245,192
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization	300,863			199,559
Asset impairment	21,545			—
Accretion expense	5,581			5,066
Deferred income taxes	80,724			120,656
Bad debt expense	370			3,197
Exploratory expense	11,420			10,773
Change in derivative fair value	(23,933		)	(59,581		)
Gain on sale of assets	(420		)	(5,991		)
Other, net	17,047			5,913
Net change in:
Accounts receivable	46,798			48,585
Inventories	62			(15,493		)
Accounts payable	(12,791		)	(26,877		)
Amounts due customers, including gas supply pass-through	(52,466		)	7,342
Income tax receivable	1,817			39,347
Pension and other postretirement benefit contributions	(5,056		)	(5,025		)
Other current assets and liabilities	20,819			21,286
Net cash provided by operating activities	603,119			593,949
Investing Activities
Additions to property, plant and equipment	(898,202		)	(634,427		)
Acquisitions, net of cash acquired	(104,200		)	(106,578		)
Proceeds from sale of assets	2,420			7,401
Other, net	(746		)	(946		)
Net cash used in investing activities	(1,000,728		)	(734,550		)
Financing Activities
Payment of dividends on common stock	(30,292		)	(29,188		)
Issuance of common stock	1,164			6,221
Issuance of long-term debt	—			399,952
Payment of long-term debt	(1,143		)	(5,407		)
Net change in short-term debt	465,000			(230,000		)
Tax benefit on stock compensation	514			922
Other	(38		)	(3,162		)
Net cash provided by financing activities	435,205			139,338
Net change in cash and cash equivalents	37,596			(1,263		)
Cash and cash equivalents at beginning of period	9,541			22,659
Cash and Cash Equivalents at End of Period	$	47,137		$	21,396

The accompanying notes are an integral part of these unaudited consolidated condensed financial statements.

8

CONDENSED STATEMENTS OF INCOME
ALABAMA GAS CORPORATION
(Unaudited)
	Three months ended						Nine months ended
	September 30,						September 30,
(in thousands)	2012			2011			2012			2011
Operating Revenues	$	61,809		$	59,616		$	327,183		$	415,497
Operating Expenses
Cost of gas	20,924			21,748			94,179			185,916
Operations and maintenance	37,235			33,001			107,470			106,535
Depreciation and amortization	10,572			9,980			31,551			29,606
Income taxes
Current	(9,242		)	(9,414		)	13,567			3,456
Deferred	3,264			3,664			9,431			16,626
Taxes, other than income taxes	5,821			5,568			23,718			27,899
Total operating expenses	68,574			64,547			279,916			370,038
Operating Income (Loss)	(6,765		)	(4,931		)	47,267			45,459
Other Income (Expense)
Allowance for funds used during construction	187			260			452			652
Other income	787			326			1,925			941
Other expense	(84		)	(913		)	(254		)	(720		)
Total other income (expense)	890			(327		)	2,123			873
Interest Charges
Interest on long-term debt	3,423			3,025			10,270			9,106
Other interest expense	741			810			1,915			1,882
Total interest charges	4,164			3,835			12,185			10,988
Net Income (Loss)	$	(10,039	)	$	(9,093	)	$	37,205		$	35,344

The accompanying notes are an integral part of these unaudited condensed financial statements.

9

CONDENSED BALANCE SHEETS
ALABAMA GAS CORPORATION
(Unaudited)
(in thousands)	September 30, 2012			December 31, 2011
ASSETS
Property, Plant and Equipment
Utility plant	$	1,395,454		$	1,358,266
Less accumulated depreciation	560,279			544,838
Utility plant, net	835,175			813,428
Other property, net	42			43
Current Assets
Cash and cash equivalents	10,286			7,817
Accounts receivable
Gas	38,014			96,812
Other	5,092			6,858
Affiliated companies	—			2,841
Allowance for doubtful accounts	(5,800		)	(12,100		)
Inventories
Storage gas inventory	36,849			44,047
Materials and supplies	5,446			4,183
Liquified natural gas in storage	3,505			3,545
Regulatory asset	56,188			57,143
Income tax receivable	3,760			9,762
Deferred income taxes	19,718			21,986
Prepayments and other	6,336			4,422
Total current assets	179,394			247,316
Other Assets
Regulatory asset	94,869			95,633
Deferred charges and other	10,681			10,380
Total other assets	105,550			106,013
TOTAL ASSETS	$	1,120,161		$	1,166,800

The accompanying notes are an integral part of these unaudited condensed financial statements.

10

CONDENSED BALANCE SHEETS
ALABAMA GAS CORPORATION
(Unaudited)
(in thousands, except share data)	September 30, 2012		December 31, 2011
LIABILITIES AND CAPITALIZATION
Capitalization
Preferred stock, cumulative $0.01 par value, 120,000 shares authorized	$	—	$	—
Common shareholder's equity
Common stock, $0.01 par value; 3,000,000 shares authorized, 1,972,052 shares issued at September 30, 2012 and December 31, 2011	20		20
Premium on capital stock	31,682		31,682
Capital surplus	2,802		2,802
Retained earnings	319,257		310,234
Total common shareholder's equity	353,761		344,738
Long-term debt	250,103		250,246
Total capitalization	603,864		594,984
Current Liabilities
Notes payable to banks	25,000		15,000
Accounts payable	53,899		110,552
Affiliated companies	24,867		—
Accrued taxes	24,689		26,861
Customers' deposits	23,563		23,950
Amounts due customers	21,828		21,065
Accrued wages and benefits	7,533		12,971
Regulatory liability	27,372		58,279
Other	9,516		9,250
Total current liabilities	218,267		277,928
Deferred Credits and Other Liabilities
Deferred income taxes	188,509		181,492
Pension and other postretirement liabilities	31,069		21,383
Regulatory liability	77,692		87,234
Long-term derivative instruments	—		3,070
Other	760		709
Total deferred credits and other liabilities	298,030		293,888
Commitments and Contingencies
TOTAL LIABILITIES AND CAPITALIZATION	$	1,120,161	$	1,166,800

The accompanying notes are an integral part of these unaudited condensed financial statements.

11

CONDENSED STATEMENTS OF CASH FLOWS
ALABAMA GAS CORPORATION
(Unaudited)
Nine months ended September 30, (in thousands)	2012			2011
Operating Activities
Net income	$	37,205		$	35,344
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	31,551			29,606
Deferred income taxes	9,431			16,626
Bad debt expense	364			3,184
Other, net	4,681			227
Net change in:
Accounts receivable	29,539			41,085
Inventories	5,975			(6,173		)
Accounts payable	(17,222		)	(22,155		)
Amounts due customers, including gas supply pass-through	(52,466		)	7,342
Income tax receivable	6,002			6,807
Pension and other postretirement benefit contributions	(2,044		)	(2,108		)
Other current assets and liabilities	(9,795		)	(8,474		)
Net cash provided by operating activities	43,221			101,311
Investing Activities
Additions to property, plant and equipment	(49,746		)	(57,424		)
Other, net	2,490			177
Net cash used in investing activities	(47,256		)	(57,247		)
Financing Activities
Dividends	(28,182		)	(29,183		)
Payment of long-term debt	(143		)	(5,407		)
Net increases in advances from affiliates	24,867			370
Net change in short-term debt	10,000			(20,000		)
Other	(38		)	—
Net cash provided by (used in) financing activities	6,504			(54,220		)
Net change in cash and cash equivalents	2,469			(10,156		)
Cash and cash equivalents at beginning of period	7,817			16,910
Cash and Cash Equivalents at End of Period	$	10,286		$	6,754

The accompanying notes are an integral part of these unaudited condensed financial statements.

12

NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS

ENERGEN CORPORATION AND ALABAMA GAS CORPORATION

1. BASIS OF PRESENTATION

The unaudited condensed financial statements and notes should be read in conjunction with the financial statements and notes thereto for the years ended December 31, 2011, 2010 and 2009, included in the 2011 Annual Report of Energen Corporation (the Company) and Alabama Gas Corporation (Alagasco) on Form 10-K. Alagasco has a September 30 fiscal year for rate-setting purposes (rate year) and reports on a calendar year for the Securities and Exchange Commission and all other financial accounting reporting purposes. The accompanying unaudited condensed financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America for interim financial information and with the instructions to Form 10-Q and Rule 10-01 of Regulation S-X. Accordingly, they do not include all of the disclosures required for complete financial statements. The Company's natural gas distribution business is seasonal in character and influenced by weather conditions. Results of operations for interim periods are not necessarily indicative of the results that may be expected for the year. All adjustments to the unaudited condensed financial statements that are, in the opinion of management, necessary for a fair statement of the results for the interim periods have been recorded. Such adjustments consist of normal recurring items. Certain reclassifications were made to conform prior year's financial statements to the current-quarter presentation.

2. REGULATORY MATTERS

Alagasco is subject to regulation by the Alabama Public Service Commission (APSC) which established the Rate Stabilization and Equalization (RSE) rate-setting process in 1983. RSE’s current extension is for a seven-year period through December 31, 2014. RSE will continue after December 31, 2014, unless, after notice to the Company and a hearing, the APSC votes to modify or discontinue the RSE methodology.

Alagasco's allowed range of return on average common equity is 13.15 percent to 13.65 percent throughout the term of the RSE order. Under RSE, the APSC conducts quarterly reviews to determine whether Alagasco's return on average common equity at the end of the rate year will be within the allowed range of return. Reductions in rates can be made quarterly to bring the projected return within the allowed range; increases, however, are allowed only once each rate year, effective December 1, and cannot exceed 4 percent of prior-year revenues. During the three months and nine months ended September 30, 2012, Alagasco had a net $1.3 million pre-tax and a net $6.3 million pre-tax, respectively, reduction in revenues to bring the return on average common equity to midpoint within the allowed range of return. During the three months and nine months ended September 30, 2011, Alagasco had a net $1.2 million pre-tax and a net $6.7 million pre-tax, respectively, reduction in revenues to bring the return on average common equity to midpoint within the allowed range of return. Under the provisions of RSE, a $13.0 million annual increase and a $1.3 million annual decrease in revenues became effective December 1, 2011 and 2010, respectively.

RSE limits the utility’s equity upon which a return is permitted to 55 percent of total capitalization, subject to certain adjustments. Under the inflation-based Cost Control Measurement (CCM) established by the APSC, if the percentage change in operations and maintenance (O&M) expense on an aggregate basis falls within a range of 0.75 points above or below the percentage change in the Consumer Price Index For All Urban Consumers (Index Range), no adjustment is required. If the change in O&M expense on an aggregate basis exceeds the Index Range, three-quarters of the difference is returned to customers. To the extent the change is less than the Index Range, the utility benefits by one-half of the difference through future rate adjustments. The O&M expense base for measurement purposes will be set at the prior year’s actual O&M expense amount unless the Company exceeds the top of the Index Range in two successive years, in which case the base for the following year will be set at the top of the Index Range. Certain items that fluctuate based on situations demonstrated to be beyond Alagasco’s control may be excluded from the CCM calculation. Alagasco’s O&M expense fell within the Index Range for the rate years ended September 30, 2012 and 2011.

Alagasco’s rate schedules for natural gas distribution charges contain a Gas Supply Adjustment (GSA) rider, established in 1993, which permits the pass-through to customers of changes in the cost of gas supply. Alagasco's tariff provides a temperature adjustment mechanism, also included in the GSA, that is designed to moderate the impact of departures from normal temperatures on Alagasco’s earnings. The temperature adjustment applies primarily to residential, small commercial and small industrial customers. Other non-temperature weather related conditions that may affect customer usage are not included in the temperature adjustment.

13

The APSC approved an Enhanced Stability Reserve (ESR) in 1998, which was subsequently modified and expanded in 2010. As currently approved, the ESR provides deferred treatment and recovery for the following: (1) extraordinary O&M expenses related to environmental response costs; (2) extraordinary O&M expenses related to self insurance costs that exceed $1 million per occurrence; (3) extraordinary O&M expenses, other than environmental response costs and self insurance costs, resulting from a single force majeure event or multiple force majeure events greater than $275,000 and $412,500, respectively, during a rate year; and (4) negative individual large commercial and industrial customer budget revenue variances that exceed $350,000 during a rate year.

Charges to the ESR are subject to certain limitations which may disallow deferred treatment and which proscribe the timing of recovery. Funding to the ESR is provided as a reduction to the refundable negative salvage balance over its nine year term beginning December 1, 2010. Subsequent to the nine year period and subject to APSC authorization, Alagasco anticipates recovering underfunded ESR balances over a five year amortization period with an annual limitation of $660,000. Amounts in excess of this limitation are deferred for recovery in future years.

3. DERIVATIVE COMMODITY INSTRUMENTS

Energen Resources Corporation, Energen's oil and gas subsidiary, recognizes all derivatives on the balance sheet and measures all derivatives at fair value. If a derivative is designated as a cash flow hedge, the effectiveness of the hedge, or the degree that the gain (loss) for the hedging instrument offsets the loss (gain) on the hedged item, is measured at each reporting period. The effective portion of the gain or loss on the derivative instrument is recognized in other comprehensive income (OCI) as a component of shareholders’ equity and subsequently reclassified as operating revenues when the forecasted transaction affects earnings. The ineffective portion of a derivative's change in fair value is required to be recognized in operating revenues immediately. All derivative transactions are included in operating activities on the consolidated condensed statements of cash flows.

Energen Resources periodically enters into derivative commodity instruments to hedge its exposure to price fluctuations on oil, natural gas and natural gas liquids production. In prior years, Alagasco entered into cash flow derivative commodity instruments to hedge its exposure to price fluctuations on its gas supply. Hedge transactions are pursuant to standing authorizations by the Board of Directors, which do not authorize speculative positions. Such instruments may include over-the-counter (OTC) swaps and basis hedges typically with investment and commercial banks and energy-trading firms. The Company is at risk for economic loss based upon the creditworthiness of its counterparties. Energen Resources was in a net gain position with eleven of its active counterparties at September 30, 2012. The five largest counterparty net gain positions at September 30, 2012, Macquarie Bank Limited, J Aron & Company, BP Corporation North America Inc., Shell Energy North America (US), L.P. and Citibank, N.A. constituted approximately $16.8 million, $9.7 million, $9.6 million, $8.5 million and $7.7 million, respectively, of Energen Resources’ net gain on fair value of derivatives. Energen Resources was in a net loss position with three of its active counterparties at September 30, 2012. The largest counterparty net loss position at September 30, 2012, Morgan Stanley Capital Group, Inc constituted approximately $24.3 million of Energen Resources’ net loss on fair value of derivatives.

The current policy of the Company is to not enter into agreements that require the posting of collateral. The Company has a few older agreements, none of which have active positions as of September 30, 2012, which include collateral posting requirements based on the amount of exposure and counterparty credit ratings. The majority of the Company’s counterparty agreements include provisions for net settlement of transactions payable on the same date and in the same currency. Most of the agreements include various contractual set-off rights, which may be exercised by the non-defaulting party in the event of an early termination due to a default.

The Company periodically enters into derivative transactions that do not qualify for cash flow hedge accounting but are considered by management to represent valid economic hedges and are accounted for as mark-to-market transactions. These economic hedges may include, but are not limited to, hedges on estimated future production not yet flowing, basis hedges without a corresponding New York Mercantile Exchange (NYMEX) hedge, and hedges on non-operated or other properties for which all of the necessary information to qualify for cash flow hedge accounting is either not readily available or subject to change. Derivatives that do not qualify for hedge treatment or are not designated as cash flow hedges are recorded at fair value with gains or losses recognized in operating revenues in the period of change.

14

The following tables detail the fair values of commodity contracts by business segment on the balance sheets:

(in thousands)	September 30, 2012
	Oil and Gas Operations				Natural Gas Distribution			Total
Derivative assets or (liabilities) designated as hedging instruments
Accounts receivable	$	76,354			$	—		$	76,354
Long-term asset derivative instruments	51,181				—			51,181
Total derivative assets	127,535				—			127,535
Accounts receivable	(33,476		)	*	—			(33,476		)
Long-term asset derivative instruments	(17,575		)	*	—			(17,575		)
Accounts payable	(12,471		)		—			(12,471		)
Long-term liability derivative instruments	(7,739		)		—			(7,739		)
Total derivative liabilities	(71,261		)		—			(71,261		)
Total derivatives designated	56,274				—			56,274
Derivative assets or (liabilities) not designated as hedging instruments
Accounts receivable	(6,603		)	*	—			(6,603		)
Long-term asset derivative instruments	9,531				—			9,531
Total derivative assets	2,928				—			2,928
Accounts payable	(4,476		)		(14,990		)	(19,466		)
Long-term liability derivative instruments	(1,316		)		—			(1,316		)
Total derivative liabilities	(5,792		)		(14,990		)	(20,782		)
Total derivatives not designated	(2,864		)		(14,990		)	(17,854		)
Total derivatives	$	53,410			$	(14,990	)	$	38,420

(in thousands)	December 31, 2011
	Oil and Gas Operations				Natural Gas Distribution			Total
Derivative assets or (liabilities) designated as hedging instruments
Accounts receivable	$	73,636			$	—		$	73,636
Long-term asset derivative instruments	75,982				—			75,982
Total derivative assets	149,618				—			149,618
Accounts receivable	(48,174		)	*	—			(48,174		)
Long-term asset derivative instruments	(36,341		)	*	—			(36,341		)
Accounts payable	(37,070		)		—			(37,070		)
Long-term liability derivative instruments	(20,386		)		—			(20,386		)
Total derivative liabilities	(141,971		)		—			(141,971		)
Total derivatives designated	7,647				—			7,647
Derivative assets or (liabilities) not designated as hedging instruments
Accounts receivable	(3,670		)	*	—			(3,670		)
Long-term asset derivative instruments	(8,585		)	*	—			(8,585		)
Total derivative assets	(12,255		)		—			(12,255		)
Accounts payable	(13,416		)		(56,804		)	(70,220		)
Long-term liability derivative instruments	(10,922		)		(3,070		)	(13,992		)
Total derivative liabilities	(24,338		)		(59,874		)	(84,212		)
Total derivatives not designated	(36,593		)		(59,874		)	(96,467		)
Total derivatives	$	(28,946	)		$	(59,874	)	$	(88,820	)

15

* Amounts classified in accordance with accounting guidance which permits offsetting fair value amounts recognized for multiple derivative instruments executed with the same counterparty under a master netting arrangement.

The Company had a net $22.0 million and a net $5.7 million deferred tax liability included in current and noncurrent deferred income taxes on the consolidated condensed balance sheets related to derivative items included in OCI as of September 30, 2012, and December 31, 2011, respectively.

Alagasco recognizes all derivatives at fair value as either assets or liabilities on the balance sheet. Any gains or losses are passed through to customers using the mechanisms of the GSA in compliance with Alagasco’s APSC-approved tariff and are recognized as a regulatory asset or regulatory liability.

The following table details the effect of derivative commodity instruments in cash flow hedging relationships on the financial statements:

(in thousands)	Location on Income Statement	Three months ended September 30, 2012			Three months ended September 30, 2011
Gain (loss) recognized in OCI on derivative (effective portion), net of tax of ($30.6) million and $105.7 million	—	$	(49,962	)	$	172,430
Gain reclassified from accumulated OCI into income (effective portion)	Operating revenues	$	15,998		$	11,207
Gain (loss) recognized in income on derivative (ineffective portion and amount excluded from effectiveness testing)	Operating revenues	$	(3,042	)	$	5,631

(in thousands)	Location on Income Statement	Nine months ended September 30, 2012			Nine months ended September 30, 2011
Gain recognized in OCI on derivative (effective portion), net of tax of $30.6 million and $76.6 million	—	$	49,961		$	125,005
Gain reclassified from accumulated OCI into income (effective portion)	Operating revenues	$	39,012		$	13,028
Gain (loss) recognized in income on derivative (ineffective portion and amount excluded from effectiveness testing)	Operating revenues	$	(1,372	)	$	3,240

The following table details the effect of derivative commodity instruments not designated as hedging instruments on the income statements:

(in thousands)	Location on Income Statement	Three months ended September 30, 2012			Three months ended September 30, 2011
Gain (loss) recognized in income on derivative	Operating revenues	$	(45,618	)	$	53,227

(in thousands)	Location on Income Statement	Nine months ended September 30, 2012		Nine months ended September 30, 2011
Gain recognized in income on derivative	Operating revenues	$	33,825	$	53,225

As of September 30, 2012, $20.2 million, net of tax, of deferred net gains on derivative instruments recorded in accumulated other comprehensive income are expected to be reclassified and reported in earnings as operating revenues during the next twelve-month period. The actual amount that will be reclassified to earnings over the next year could vary materially from this amount due to changes in market conditions. As of September 30, 2012, the Company had 2.0 billion, 5.6 billion and 9.7 billion cubic feet (Bcf) of natural gas hedges which expire during 2012, 2013 and 2014, respectively, that did not meet the definition of a cash flow hedge but are considered by the Company to be economic hedges. The Company had 1.2 million, 8.7 million and 5.4 million barrels (MMBbl) of oil and oil basis hedges which expire during 2012, 2013 and 2014, respectively, that did not meet the definition of a

16

cash flow hedge but are considered by the Company to be economic hedges. The Company had 3.8 million and 1.6 million gallons (MMgal) of natural gas liquid hedges which expire during 2012 and 2013, respectively, that did not meet the definition of a cash flow hedge but are considered by the Company to be economic hedges. During 2011, the Company had a discontinuance of hedge accounting when Energen Resources determined it was probable certain forecasted volumes would not occur, which resulted in $46,000 after-tax gain being recognized into operating revenues during the nine months ended September 30, 2012.

Energen Resources entered into the following transactions for the remainder of 2012 and subsequent years:

Production Period	Total Hedged Volumes		Average Contract Price	Description
Natural Gas
2012	3.6	Bcf	$4.49 Mcf	NYMEX Swaps
	8.9	Bcf	$4.14 Mcf	Basin Specific Swaps - San Juan
	2.0	Bcf	$2.89 Mcf	Basin Specific Swaps - Permian
2013	12.7	Bcf	$4.82 Mcf	NYMEX Swaps
	32.8	Bcf	$4.56 Mcf	Basin Specific Swaps - San Juan
	4.6	Bcf	$3.45 Mcf	Basin Specific Swaps - Permian
2014	10.6	Bcf	$4.55 Mcf	NYMEX Swaps
	25.7	Bcf	$4.72 Mcf	Basin Specific Swaps - San Juan
	9.7	Bcf	$3.81 Mcf	Basin Specific Swaps - Permian
Gas Basis Differential
2012	0.1	Bcf	$(0.23) Mcf	San Juan Basis Swaps
Oil
2012	1,850	MBbl	$88.51 Bbl	NYMEX Swaps
2013	8,858	MBbl	$90.95 Bbl	NYMEX Swaps
2014	9,796	MBbl	$92.64 Bbl	NYMEX Swaps
Oil Basis Differential
2012	752	MBbl	$(2.95) Bbl	WTS/WTI Basis Swaps*
2013	3,592	MBbl	$(3.03) Bbl	WTS/WTI Basis Swaps*
	1,740	MBbl	$(1.13) Bbl	WTI/WTI Basis Swaps**
Natural Gas Liquids
2012	15.3	MMGal	$0.99 Gal	Liquids Swaps
2013	44.5	MMGal	$1.02 Gal	Liquids Swaps
*WTS - West Texas Sour/Midland, WTI - West Texas Intermediate/Cushing
**WTI - West Texas Intermediate/Midland, WTI - West Texas Intermediate/Cushing

Alagasco entered into the following natural gas transactions for the remainder of 2012 and subsequent years:

Production Period	Total Hedged Volumes		Description
2012	4.6	Bcf	NYMEX Swaps
2013	1.5	Bcf	NYMEX Swaps

As of September 30, 2012, the maximum term over which Energen Resources and Alagasco have hedged exposures to the variability of cash flows is through December 31, 2014, and March 31, 2013, respectively. Alagasco has not entered into any new cash flow derivative transactions on its gas supply since the summer of 2010. 

Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). All assets and liabilities are required to be classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Assessing the significance of a particular input may require

17

judgment considering factors specific to the asset or liability, and may affect the valuation of the asset or liability and its placement within the fair value hierarchy. The fair value hierarchy that prioritizes the inputs used to measure fair value is as follows:

Level 1 - Unadjusted quoted prices in active markets for identical assets or liabilities;

Level 2 - Pricing inputs other than quoted prices in active markets included within Level 1, which are either directly or indirectly observable through correlation with market data as of the reporting date;

Level 3 - Pricing that requires inputs that are both significant and unobservable to the calculation of the fair value measure. The fair value measure represents estimates of the assumption that market value participants would use in pricing the asset or liability. Unobservable inputs are developed based on the best available information and subject to cost-benefit constraints.

Derivative commodity instruments are over-the-counter (OTC) derivatives valued using market transactions and other market evidence whenever possible, including market-based inputs to models and broker or dealer quotations. These OTC derivative contracts trade in less liquid markets with limited pricing information as compared to markets with actively traded, unadjusted quoted prices; accordingly, the determination of fair value is inherently more difficult. OTC derivatives for which the Company is able to substantiate fair value through directly observable market prices are classified within Level 2 of the fair value hierarchy. These Level 2 fair values consist of swaps priced in reference to NYMEX natural gas and oil futures. OTC derivatives valued using unobservable market prices have been classified within Level 3 of the fair value hierarchy. These Level 3 fair values include basin specific, basis and natural gas liquids swaps. The Company considers frequency of pricing and variability in pricing between sources in determining whether a market is considered active. While the Company does not have access to the specific assumptions used in its counterparties' valuation models, the Company maintains communications with its counterparties and discusses pricing practices. Further, the Company corroborates the fair value of its transactions by comparison of market-based price sources.

The following sets forth derivative assets and liabilities that were measured at fair value on a recurring basis:

	September 30, 2012
(in thousands)	Level 2*			Level 3*			Total
Current assets	$	(1,048	)	$	37,323		$	36,275
Noncurrent assets	18,133			25,004			43,137
Current liabilities	(30,588		)	(1,349		)	(31,937		)
Noncurrent liabilities	(5,358		)	(3,697		)	(9,055		)
Net derivative asset (liability)	$	(18,861	)	$	57,281		$	38,420

	December 31, 2011
(in thousands)	Level 2*			Level 3*			Total
Current assets	$	(14,843	)	$	36,635		$	21,792
Noncurrent assets	(8,382		)	39,438			31,056
Current liabilities	(98,468		)	(8,822		)	(107,290		)
Noncurrent liabilities	(32,928		)	(1,450		)	(34,378		)
Net derivative asset (liability)	$	(154,621	)	$	65,801		$	(88,820	)

* Amounts classified in accordance with accounting guidance which permits offsetting fair value amounts recognized for multiple derivative instruments executed with the same counterparty under a master netting arrangement.

As of September 30, 2012, Alagasco had $15.0 million of derivative instruments which are classified as Level 2 fair values and are included in the above table as current liabilities. As of December 31, 2011, Alagasco had $56.8 million and $3.1 million of derivative instruments which are classified as Level 2 fair values and are included in the above table as current and noncurrent liabilities, respectively. Alagasco had no derivative instruments classified as Level 3 fair values as of September 30, 2012, and December 31, 2011.

The Company has prepared a sensitivity analysis to evaluate the hypothetical effect that changes in the prices used to estimate fair value would have on the fair value of its derivative instruments. The Company estimates that a 10 percent increase or decrease in commodity prices would result in an approximate $35 million change in the fair value of open Level 3 derivative contracts. The resulting impact upon the results of operations would be an approximate $5.9 million associated with open Level 3 mark-to-market

18

derivative contracts. Cash flow requirements to meet the obligation would not be significantly impacted as gains and losses on the derivative contracts would be similarly offset by sales at the spot market price.

The tables below set forth a summary of changes in the fair value of the Company’s Level 3 derivative commodity instruments as follows:

	Three months ended			Three months ended
(in thousands)	September 30, 2012			September 30, 2011
Balance at beginning of period	$	103,456		$	13,446
Realized gains	18,737			9,370
Unrealized gains (losses) relating to instruments held at the reporting date*	(46,983		)	23,953
Settlements during period	(17,929		)	(10,565		)
Balance at end of period	$	57,281		$	36,204

	Nine months ended			Nine months ended
(in thousands)	September 30, 2012			September 30, 2011
Balance at beginning of period	$	65,801		$	42,755
Realized gains	51,858			37,031
Unrealized losses relating to instruments held at the reporting date*	(9,328		)	(5,356		)
Settlements during period	(51,050		)	(38,226		)
Balance at end of period	$	57,281		$	36,204

*Includes $7.9 million and $4.5 million in mark-to-market losses for the three months and nine months ended September 30, 2012. Includes $0.1 million in mark-to-market gains for both the three months and nine months ended September 30, 2011.

The tables below set forth quantitative information about the Company’s Level 3 fair value measurements of derivative commodity instruments as follows:

(in thousands)	Fair Value as of September 30, 2012			Valuation Technique*	Unobservable Input*	Range
Natural Gas Basis - San Juan
2012	$	8,807		Discounted Cash Flow	Forward Basis	($0.10 - $0.12) Mcf
2013	$	27,968		Discounted Cash Flow	Forward Basis	($0.14 - $0.15) Mcf
2014	$	17,273		Discounted Cash Flow	Forward Basis	($0.14 - $0.16) Mcf
Natural Gas Basis - Permian
2012	$	(634	)	Discounted Cash Flow	Forward Basis	($0.08) Mcf
2013	$	(1,221	)	Discounted Cash Flow	Forward Basis	($0.13) Mcf
2014	$	(2,132	)	Discounted Cash Flow	Forward Basis	($0.13 - $0.15) Mcf
Oil Basis - WTS/WTI
2012	$	14		Discounted Cash Flow	Forward Basis	($2.74 - $2.81) Bbl
2013	$	(5,085	)	Discounted Cash Flow	Forward Basis	($1.59) Bbl
Oil Basis - WTI/WTI
2013	$	(379	)	Discounted Cash Flow	Forward Basis	($0.75 - $1.15) Bbl
Natural Gas Liquids
2012	$	3,594		Discounted Cash Flow	Forward Price	$0.75 - $0.89 Gal
2013	$	9,076		Discounted Cash Flow	Forward Price	$0.77 - $0.85 Gal

*Discounted cash flow represents an income approach in calculating fair value including the referenced unobservable input and a discount reflecting credit quality of the counterparty.

19

4. RECONCILIATION OF EARNINGS PER SHARE (EPS)

	Three months ended					Three months ended
(in thousands, except per share amounts)	September 30, 2012					September 30, 2011
	Net			Per Share		Net			Per Share
	Income		Shares	Amount		Income		Shares	Amount
Basic EPS	$	2,046	72,130	$	0.03	$	87,599	72,068	$	1.22
Effect of dilutive securities
Stock options			183					298
Non-vested restricted stock			3					9
Diluted EPS	$	2,046	72,316	$	0.03	$	87,599	72,375	$	1.21

	Nine months ended					Nine months ended
(in thousands, except per share amounts)	September 30, 2012					September 30, 2011
	Net			Per Share		Net			Per Share
	Income		Shares	Amount		Income		Shares	Amount
Basic EPS	$	190,739	72,121	$	2.64	$	245,192	72,045	$	3.40
Effect of dilutive securities
Stock options			177					355
Non-vested restricted stock			3					9
Diluted EPS	$	190,739	72,301	$	2.64	$	245,192	72,409	$	3.39

For the three months and nine months ended September 30, 2012, the Company had 849,583 options that were excluded from the computation of diluted EPS, as their effect was non-dilutive. For the three months and nine months ended September 30, 2011, the Company had 293,978 options that were excluded from the computation of diluted EPS. For the three months and nine months ended September 30, 2012 and 2011, the Company had no options or shares of non-vested restricted stock that were excluded from the computation of diluted EPS.

20

5. SEGMENT INFORMATION

The Company principally is engaged in two business segments: the development, acquisition, exploration and production of oil and gas in the continental United States (oil and gas operations) and the purchase, distribution and sale of natural gas in central and north Alabama (natural gas distribution).

	Three months ended						Nine months ended
	September 30,						September 30,
(in thousands)	2012			2011			2012			2011
Operating revenues
Oil and gas operations	$	233,515		$	318,952		$	856,940		$	779,834
Natural gas distribution	61,809			59,616			327,183			415,497
Total	$	295,324		$	378,568		$	1,184,123		$	1,195,331
Operating income (loss)
Oil and gas operations	$	32,407		$	161,331		$	274,818		$	351,808
Natural gas distribution	(12,743		)	(10,681		)	70,265			65,541
Eliminations and corporate expenses	(206		)	(238		)	(857		)	(721		)
Total	$	19,458		$	150,412		$	344,226		$	416,628
Other income (expense)
Oil and gas operations	$	(12,633	)	$	(9,363	)	$	(35,195	)	$	(20,632	)
Natural gas distribution	(3,274		)	(4,162		)	(10,062		)	(10,115		)
Eliminations and other	148			94			234			182
Total	$	(15,759	)	$	(13,431	)	$	(45,023	)	$	(30,565	)
Income before income taxes	$	3,699		$	136,981		$	299,203		$	386,063

(in thousands)	September 30, 2012		December 31, 2011
Identifiable assets
Oil and gas operations	$	4,734,269	$	4,046,242
Natural gas distribution	1,120,161		1,163,959
Eliminations and other	65,399		27,215
Total	$	5,919,829	$	5,237,416

6. STOCK COMPENSATION

Stock Incentive Plan

The Stock Incentive Plan provides for the grant of incentive stock options, non-qualified stock options, restricted stock, performance shares or a combination thereof to officers and key employees. Options granted under the Stock Incentive Plan provide for the purchase of Company common stock at not less than the fair market value on the date the option is granted. The sale or transfer of the shares is limited during certain periods. All outstanding options vest within three years from date of grant and expire 10 years from the grant date. The Company granted 371,040 non-qualified option shares during the first quarter of 2012 with a grant-date fair value of $18.79.

Petrotech Incentive Plan

The Energen Resources’ Petrotech Incentive Plan provides for the grant of stock equivalent units. These awards are liability awards which settle in cash and are re-measured each reporting period until settlement. During the nine months ended September 30, 2012, Energen Resources awarded 102,349, 3,768 and 40,822 Petrotech units with a three-year, two-year and 18 month vesting period, respectively. These awards have a fair value of $51.17, $51.72 and $51.99 per unit, respectively, as of September 30, 2012.

Stock Repurchase Program

During the three months and nine months ended September 30, 2012, the Company had noncash purchases of approximately $111,000 and $229,000, respectively, of Company common stock in conjunction with tax withholdings on its non-qualified deferred compensation plan and other stock compensation. The Company utilized internally generated cash flows in payment of the related tax withholdings.

21

7. EMPLOYEE BENEFIT PLANS

The components of net pension expense for the Company’s two defined benefit non-contributory pension plans and certain nonqualified supplemental pension plans were:

	Three months ended September 30,						Nine months ended September 30,
(in thousands)	2012			2011			2012			2011
Components of net periodic benefit cost:
Service cost	$	2,632		$	2,293		$	7,895		$	6,879
Interest cost	2,700			2,740			8,101			8,220
Expected long-term return on assets	(3,563		)	(3,868		)	(10,689		)	(11,603		)
Actuarial loss	2,099			1,609			6,297			4,826
Prior service cost amortization	129			124			388			372
Net periodic expense	$	3,997		$	2,898		$	11,992		$	8,694

During the third quarter of 2012, the Moving Ahead for Progress in the 21st Century Act (MAP-21) was signed into law. This law included pension funding stabilization measures designed to stabilize the discount rate used to determine funding requirements. The impact of MAP-21 on Energen's pension plans was to reduce the required contributions during 2012 from approximately $12.8 million to $2.1 million to the qualified pension plans. These contribution requirements were satisfied during the third quarter of 2012 by applying the plans' funding balances, as established under Internal Revenue Code Section 430(f). It is not anticipated that the funded status of the qualified pension plans will fall below statutory thresholds requiring accelerated funding or constraints on benefit levels or plan administration. No additional discretionary contributions are currently expected to be made to the pension plans by the Company during 2012. For the three months and nine months ending September 30, 2012, the Company made benefit payments aggregating $36,000 and $2.3 million, respectively, to retirees from the nonqualified supplemental retirement plans and expects to make additional benefit payments of approximately $36,000 through the remainder of 2012.

The components of net periodic postretirement benefit expense for the Company’s postretirement benefit plans were:

	Three months ended September 30,						Nine months ended September 30,
(in thousands)	2012			2011			2012			2011
Components of net periodic benefit cost:
Service cost	$	463		$	442		$	1,390		$	1,327
Interest cost	1,062			1,111			3,186			3,332
Expected long-term return on assets	(1,109		)	(1,104		)	(3,328		)	(3,314		)
Actuarial loss	9			—			27			—
Transition amortization	479			479			1,438			1,438
Net periodic expense	$	904		$	928		$	2,713		$	2,783

For the three months and nine months ended September 30, 2012, the Company made contributions aggregating $0.9 million and $2.7 million, respectively, to the postretirement benefit plans. The Company expects to make additional discretionary contributions of approximately $0.9 million to the postretirement benefit plans through the remainder of 2012.

8. COMMITMENTS AND CONTINGENCIES    

Commitments and Agreements: Under various agreements for third party gathering, treatment, transportation or other services, Energen Resources is committed to deliver minimum production volumes or to pay certain costs in the event the minimum quantities are not delivered. These delivery commitments are approximately 33.4 million barrels of oil equivalent (MMBOE) through November 2021.

22

Energen Resources entered into three agreements which commenced at various dates from November 15, 2011 to January 15, 2012 and expire at various dates through January 2015 to secure drilling rigs necessary to execute a portion of its drilling plans. In the unlikely event that Energen Resources discontinues use of these drilling rigs, Energen Resources' total resulting exposure could be as much as $24 million depending on the contractor's ability to remarket the drilling rig.

Certain of Alagasco's long-term contracts associated with the delivery and storage of natural gas include fixed charges of approximately $74 million through September 2024. During the nine months ending September 30, 2012 and 2011, Alagasco recognized approximately $36.8 million of long-term commitments through expense and its regulatory accounts in the accompanying financial statements. Alagasco also is committed to purchase minimum quantities of gas at market-related prices or to pay certain costs in the event the minimum quantities are not taken. These purchase commitments are approximately 177 Bcf through August 2020.

Alagasco purchases gas as an agent for certain of its large commercial and industrial customers. Alagasco has, in certain instances, provided commodity-related guarantees to the counterparties in order to facilitate these agency purchases. Liabilities existing for gas delivered to customers subject to these guarantees are included in the balance sheets. In the event the customer for whom the guarantee was entered fails to take delivery of the gas, Alagasco can sell such gas for the customer, with the customer liable for any resulting loss. Although the substantial majority of purchases under these guarantees are for the customers' current monthly consumption and are at current market prices, in some instances, the purchases are for an extended term at a fixed price. At September 30, 2012, the fixed price purchases under these guarantees had a maximum term outstanding through March 2013 and an aggregate purchase price of $0.8 million with a market value of $0.8 million.

Income Taxes: The Company and Alagasco have on-going tax examinations under various U.S. and state tax jurisdictions. Accordingly, it is reasonably possible that significant changes to the reserve for uncertain tax benefits may occur as a result of the completion of various audits and the expiration of statute of limitations. Although the timing and outcome of these tax examinations is highly uncertain, the Company does not expect the change in the unrecognized tax benefit within the next 12 months would have a material impact to the financial statements.

Legal Matters: Energen and its affiliates are, from time to time, parties to various pending or threatened legal proceedings. Certain of these lawsuits include claims for punitive damages in addition to other specified relief. Based upon information presently available and in light of available legal and other defenses, contingent liabilities arising from threatened and pending litigation are not considered material in relation to the respective financial positions of Energen and its affiliates. It should be noted, however, that Energen and its affiliates conduct business in jurisdictions in which the magnitude and frequency of punitive and other damage awards may bear little or no relation to culpability or actual damages, thus making it difficult to predict litigation results.

Various pending or threatened legal proceedings are in progress currently, and the Company has accrued a provision for estimated liability. This provision was increased by $1.4 million during the nine months ended September 30, 2012.

Environmental Matters: Various environmental laws and regulations apply to the operations of Energen Resources and Alagasco. Historically, the cost of environmental compliance has not materially affected the Company's financial position, results of operations or cash flows. New regulations, enforcement policies, claims for damages or other events could result in significant unanticipated costs.

Alagasco is in the chain of title of nine former manufactured gas plant sites, four of which it still owns, and five former manufactured gas distribution sites, one of which it still owns and is the subject of a recent inquiry discussed below. Also discussed below is the recent completion of a removal action at the Huntsville, Alabama manufactured gas plant site. An investigation of the sites does not indicate the present need for other remediation activities and management expects that, should remediation of any such sites be required in the future, Alagasco's share, if any, of such costs will not materially affect the financial position of Alagasco.

In May 2012, Alagasco received from the United States Environmental Protection Agency (EPA) a Request for information Pursuant to Section 104 of CERCLA relating to the EPA's investigation of a site which it refers to as the 35^th Avenue Superfund Site in and around Birmingham, Jefferson County, Alabama. The inquiry requests information about a parcel owned by Alagasco and located in the vicinity of the 35^th Avenue site. The parcel is the former site of a manufactured gas distribution facility. Alagasco has responded to the inquiry.

In June 2009, Alagasco received a General Notice Letter from the EPA identifying Alagasco as a responsible party for a former manufactured gas plant (MGP) site located in Huntsville, Alabama, and inviting Alagasco to enter an Administrative Settlement Agreement and Order on Consent to perform a removal action at that site. The Huntsville MGP, along with the Huntsville gas distribution system, was sold by Alagasco to the City of Huntsville in 1949. While Alagasco no longer owns the Huntsville site, the Company and the current site owner entered into a Consent Order, and developed and completed during 2011 an action plan for the site. Alagasco has incurred costs associated with the site of approximately $5.0 million. As of September 30, 2012, the expected

23

remaining costs are not expected to be material to the Company. Alagasco has recorded a corresponding amount to its Enhanced Stability Reserve regulatory asset account of which a debit balance of $4.8 million was cleared as of September 30, 2011 and allocated, subject to APSC review guidelines, against the refundable negative salvage costs being refunded to customers.

New Mexico Audits: During the third quarter of 2010, Energen Resources received preliminary findings from the Taxation and Revenue Department (the Department) of the State of New Mexico relating to its audit, conducted on behalf of the Office of Natural Resources Revenue (ONRR), of federal oil and gas leases in New Mexico. The audit covered periods from January 2004 through December 2008 and included a review of the computation and payment of royalties due on minerals removed from specified U.S. federal leases. The ONRR has proposed certain changes in the method of determining allowable deductions of transportation, fuel and processing costs from royalties due under the terms of the related leases.

As a result of the audit, Energen Resources has been ordered by the ONRR to pay additional royalties on the specified U.S. federal leases in the amount of $142,000 and restructure its accounting for all federal leases in two counties in New Mexico from March 1, 2004, forward. The Company preliminarily estimates that application of the Order to all of the Company's New Mexico federal leases would result in ONRR claims for up to approximately $23 million of additional royalties plus interest and penalties for the period from March 1, 2004, forward. The preliminary findings and subsequent Order (issued April 25, 2011) are contrary to deductions allowed under previous audits, retroactive in application and inconsistent with the Company’s understanding of industry practice. The Company is vigorously contesting the Order and has requested additional information from the ONRR and the Department to assist the Company in evaluating the ONRR Order and the Department's findings. Management is unable, at this time, to determine a range of reasonably possible losses as a result of this Order, and no amount has been accrued as of September 30, 2012.

Capital Lease Obligations: During the first quarter of 2012, the Company entered into certain capital leases related to certain equipment. The following is a schedule of future minimum lease payments under capital leases together with the present value of the net minimum lease payments as of September 30, 2012:

(in thousands)
2012	$	436
2013	1,743
2014	1,743
2015	145
Total minimum lease payments	4,067
Less amount representing interest	93
Total present value of minimum lease payments	$	3,974

9. FINANCIAL INSTRUMENTS

The stated value of cash and cash equivalents, short-term investments, trade receivables (net of allowance), and short-term debt approximates fair value due to the short maturity of the instruments. The fair value of Energen's long-term debt, including the current portion, approximates $1,256.2 million and has a carrying value of $1,154.1 million at September 30, 2012. The fair value of Alagasco's fixed-rate long-term debt, including the current portion, approximates $284.9 million and has a carrying value of $250.1 million at September 30, 2012. The fair values were based on market prices of similar debt issues having the same remaining maturities, redemption terms and credit rating. Short-term debt is classified as Level 1 fair value and long-term debt is classified as Level 2 fair value.

In December 2011, the Company entered into interest rate swap agreements for $200 million of the Senior Term Loans. The swap agreements exchange a variable interest rate for a fixed interest rate of 2.4175 percent on $200 million of the principal amount outstanding. The fair value of the Company's interest rate swap was a $3.7 million liability at September 30, 2012 and is classified as Level 1 fair value.

Finance Receivables: Alagasco finances third-party contractor sales of merchandise including gas furnaces and appliances. At September 30, 2012 and December 31, 2011, Alagasco’s finance receivable totaled $10.7 million and $10.5 million, respectively. These finance receivables currently have an average balance of approximately $3,000 and with terms of up to 60 months. Financing is available only to qualified customers who meet credit worthiness thresholds for customer payment history and external agency credit reports. Alagasco relies upon ongoing payments as the primary indicator of credit quality during the term of each contract. The allowance for credit losses is recognized using an estimate of write-off percentages based on historical experience applied to an aging of the finance receivable balance. Delinquent accounts are evaluated on a case-by-case basis and, absent evidence of debt repayment after 90 days, are due in full and assigned to a third-party collection agency. The remaining finance receivable is written

24

off approximately 12 months after being assigned to the third-party collection agency. Alagasco had finance receivables past due 90 days or more of $467,000 as of September 30, 2012.

The following table sets forth a summary of changes in the allowance for credit losses as follows:

(in thousands)
Allowance for credit losses as of December 31, 2011	$	421
Provision	21
Allowance for credit losses as of September 30, 2012	$	442

10. REGULATORY ASSETS AND LIABILITIES

The following table details regulatory assets and liabilities on the balance sheets:

(in thousands)	September 30, 2012				December 31, 2011
	Current		Noncurrent		Current		Noncurrent
Regulatory assets:
Pension and postretirement assets	$	170	$	79,984	$	170	$	77,587
Accretion and depreciation for asset retirement obligation	—		14,885		—		13,981
Risk management activities	14,990		—		56,804		3,070
Asset removal costs, net	—		—		—		994
Gas supply adjustment	40,998		—		—		—
Other	30		—		169		1
Total regulatory assets	$	56,188	$	94,869	$	57,143	$	95,633
Regulatory liabilities:
RSE adjustment	$	3,187	$	—	$	2,931	$	—
Unbilled service margin	5,799		—		22,419		—
Gas supply adjustment	—		—		12,626		—
Refundable negative salvage	18,353		55,389		20,269		65,646
Asset retirement obligation	—		21,525		—		20,785
Other	33		778		34		803
Total regulatory liabilities	$	27,372	$	77,692	$	58,279	$	87,234

11. ASSET RETIREMENT OBLIGATIONS

The Company recognizes a liability for the fair value of asset retirement obligations (ARO) in the periods incurred. Subsequent to initial measurement, liabilities are accreted to their present value and capitalized costs are depreciated over the estimated useful life of the related assets. Upon settlement of the liability, the Company may recognize a gain or loss for differences between estimated and actual settlement costs. The ARO fair value liability is recognized on a discounted basis incorporating an estimate of performance risk specific to the Company.

During the nine months ended September 30, 2012, Energen Resources recognized amounts representing expected future costs associated with site reclamation, facilities dismantlement, and plug and abandonment of wells as follows:

(in thousands)
Balance of ARO as of December 31, 2011	$	107,340
Liabilities incurred	2,946
Liabilities settled	(676		)
Accretion expense	5,581
Balance of ARO as of September 30, 2012	$	115,191

25

The Company recognizes conditional obligations if such obligations can be reasonably estimated and a legal requirement to perform an asset retirement activity exists. Alagasco recorded a conditional asset retirement obligation, on a discounted basis of $21.5 million and $20.8 million, to purge and cap its gas pipelines upon abandonment as a regulatory liability as of September 30, 2012 and December 31, 2011, respectively. The costs associated with asset retirement obligations are currently either being recovered in rates or are probable of recovery in future rates.

Alagasco accrues removal costs on certain gas distribution assets over the useful lives of its property, plant and equipment through depreciation expense in accordance with rates approved by the APSC. Regulatory assets for accumulated asset removal costs of $1 million as of December 31, 2011 are included as regulatory assets in noncurrent assets on the balance sheets. As of September 30, 2012 and December 31, 2011, the Company recognized $18.4 million and $20.3 million, respectively, of refundable negative salvage as regulatory liabilities in current liabilities on the balance sheet in response to the June 28, 2010, APSC order. As of September 30, 2012 and December 31, 2011, the Company recognized $55.4 million and $65.6 million, respectively, of refundable negative salvage as regulatory liabilities in deferred credit and other liabilities on the balance sheet in response to the June 28, 2010, APSC order.

12. ACQUISITION AND DISPOSITION OF OIL AND GAS PROPERTIES

During the first quarter of 2012, Energen Resources recognized a noncash impairment writedown on certain properties in East Texas of $21.5 million pre-tax to adjust the carrying amount of these properties to their fair value based on expected future discounted cash flows. Significant assumptions in valuing the proved reserves included the reserve quantities, anticipated operating costs, anticipated production taxes, future expected natural gas prices and basis differentials, anticipated production declines, and a discount rate of 10 percent commensurate with the risk of the underlying cash flow estimates. The impairment was caused by the impact of lower future natural gas prices. During the first quarter of 2012, future natural gas price curves shifted significantly lower, especially in the next 5 years. This nonrecurring impairment writedown is classified as Level 3 fair value.

On February 21, 2012, Energen Resources entered into a definitive agreement with BHP Billiton (BHP) to buy a 50 percent undivided interest in three existing wells in Reeves County, Texas, from Energen Resources for approximately $18 million. Following the purchase of the wells, BHP completed two of the wells and earned a 50 percent undivided interest in 4,829 net acres. The agreement also included the option for BHP to purchase from Energen Resources a 50 percent undivided interest in 51,720 net acres in the Permian Basin. On May 1, 2012, BHP elected not to exercise the option.

On February 14, 2012, Energen completed the purchase of certain properties in the Permian Basin for a cash purchase price of $68 million. This purchase had an effective date of December 1, 2011. Energen acquired total proved reserves of approximately 8.1 MMBOE. Of the proved reserves acquired, an estimated 81 percent are undeveloped. Approximately 64 percent of the proved reserves are oil, 22 percent are natural gas liquids and natural gas comprises the remaining 14 percent. Energen Resources used its credit facilities and internally generated cash flows to finance the acquisition. Pro forma financial information for this acquisition is not presented because it would not be materially different from the information presented in the consolidated statements of income.

The following table summarizes the consideration paid and the amounts of the assets acquired and liabilities assumed recognized as of February 14, 2012 (including the effects of closing adjustments).

(in thousands)
Consideration given
Cash (net)	$	67,615
Recognized amounts of identifiable assets acquired and liabilities assumed
Proved properties	$	65,581
Unproved leasehold properties	911
Accounts receivable	1,358
Accounts payable	(25		)
Asset retirement obligation	(210		)
Total identifiable net assets	$	67,615

Included in the Company’s consolidated results of operations for the nine months ended September 30, 2012, were $8.8 million of operating revenues and $3.2 million in operating income resulting from the operation of the properties acquired above.

26

On December 27, 2011, Energen completed the purchase of certain properties in the Permian Basin for a cash purchase price of $60 million (subject to closing adjustments). This purchase had an effective date of July 1, 2011. Energen acquired total proved reserves of approximately 3.4 MMBOE. Of the proved reserves acquired, an estimated 77 percent are undeveloped. Approximately 61 percent of the proved reserves are oil, 24 percent are natural gas liquids and natural gas comprises the remaining 15 percent. Energen Resources used its credit facilities and internally generated cash flows to finance the acquisition. Pro forma financial information for this acquisition is not presented because it would not be materially different from the information presented in the consolidated statements of income.

The following table summarizes the consideration paid and the amounts of the assets acquired and liabilities assumed recognized as of December 27, 2011. The purchase price allocation is preliminary and subject to adjustment as the final closing statement is not complete.

(in thousands)
Consideration given
Cash (net)	$	59,997
Recognized amounts of identifiable assets acquired and liabilities assumed
Proved properties	$	36,048
Unproved leasehold properties	23,686
Accounts receivable	680
Accounts payable	(244		)
Asset retirement obligation	(173		)
Total identifiable net assets	$	59,997

The impact to operating revenues and operating income from this acquisition was not material for the year ended December 31, 2011.

On November 16, 2011, Energen completed the purchase of certain liquids-rich properties in the Permian Basin for a cash purchase price of $162 million. This purchase had an effective date of August 1, 2011. Energen acquired total proved reserves of approximately 13.6 million MMBOE. Of the proved reserves acquired, an estimated 76 percent are undeveloped. Approximately 59 percent of the proved reserves are oil, 25 percent are natural gas liquids and natural gas comprises the remaining 16 percent. Energen Resources used its credit facilities and internally generated cash flows to finance the acquisition. Pro forma financial information for this acquisition is not presented because it would not be materially different from the information presented in the consolidated statements of income.

The following table summarizes the consideration paid and the amounts of the assets acquired and liabilities assumed recognized as of November 16, 2011, (including the effects of closing adjustments).

(in thousands)
Consideration given
Cash (net)	$	161,967
Recognized amounts of identifiable assets acquired and liabilities assumed
Proved properties	$	151,544
Unproved leasehold properties	7,883
Accounts receivable	3,070
Accounts payable	(388		)
Asset retirement obligation	(142		)
Total identifiable net assets	$	161,967

The impact to operating revenues and operating income from this acquisition was not material for the year ended December 31, 2011.

27

In July 2011, Energen completed the purchase of liquids-rich properties in the Permian Basin for a cash purchase price of approximately $20 million. In April 2011, Energen completed the purchase of unproved leasehold properties for a cash purchase price of approximately $37 million covering an estimated 11,000 net acres in the Permian Basin.

13. RECENTLY ISSUED ACCOUNTING STANDARDS

In December 2011, the FASB issued Accounting Standard Update (ASU) No. 2011-11, Disclosures about Offsetting Assets and Liabilities. The amendments in this update require an entity to disclose information about offsetting and related arrangements to enable users of its financial statements to understand the effect of those arrangements on its financial position. The amendment is effective for annual reporting periods beginning on or after January 1, 2013, and interim periods within those annual periods. The Company is currently evaluating the impact of the ASU but does not expect this update to have a material impact on its results of operations.

In June 2011, the FASB issued ASU No. 2011-05, Presentation of Comprehensive Income. This update requires entities to present the components of net income and other comprehensive income either in a single continuous statement of comprehensive income or in two separate but consecutive statements. The amendments in this update do not change the items that must be reported in other comprehensive income or when an item of other comprehensive income must be reclassified to net income. In December 2011, the FASB issued ASU No. 2011-12, Deferral of the Effective Date for Amendments to the Presentation of Reclassifications of Items Out of Accumulated Other Comprehensive Income in Accounting Standards Update No. 2011-05, which indefinitely deferred the requirements to include reclassification adjustments for items that are reclassified from other comprehensive income to net income on the face of the financial statements. The amendments in these updates are effective for fiscal years, and interim periods within those years, beginning after December 15, 2011. Adoption of these updates has not had a material impact on the consolidated condensed financial statements or results of operations.

In May 2011, the FASB issued ASU No. 2011-04, Amendments to Achieve Common Fair Value Measurement and Disclosure Requirement in U.S. GAAP and International Financial Reporting Standards (IFRSs). The amendments in this update result in common fair value measurement and disclosure requirements in U.S. GAAP and IFRSs. The amendments are effective during interim and annual periods beginning after December 15, 2011. This standard did not have a material impact on the consolidated condensed financial statements of the Company. The additional fair value disclosures are included in Note 3, Derivative Commodity Instruments.

28

ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

RESULTS OF OPERATIONS

Energen's net income totaled $2.0 million ($0.03 per diluted share) for the three months ended September 30, 2012 compared with net income of $87.6 million ($1.21 per diluted share) for the same period in the prior year. Energen Resources Corporation, Energen's oil and gas subsidiary, had net income for the three months ended September 30, 2012, of $12.4 million as compared with $96.8 million in the same quarter in the previous year. This decrease in net income was primarily the result of a net after-tax $63 million non-cash mark-to-market loss on derivatives (resulting from an after-tax $29.7 million non-cash mark-to-market loss on derivatives for the third quarter of 2012 and an after-tax $33.1 million non-cash mark-to-market gain on derivatives for the third quarter of 2011), lower commodity prices (approximately $38 million after-tax), higher depreciation, depletion and amortization (DD&A) expense (approximately $20 million after-tax), increased lease operating expense excluding production taxes (approximately $6 million after-tax) and increased interest expense (approximately $3 million after-tax). Positively affecting net income was the impact of significantly higher production volumes (approximately $47 million after-tax). Energen's natural gas utility, Alagasco, reported a net loss of $10.0 million in the third quarter of 2012 compared to a net loss of $9.1 million in the same period last year.

For the 2012 year-to-date, Energen's net income totaled $190.7 million ($2.64 per diluted share) compared to net income of $245.2 million ($3.39 per diluted share) for the same period in the prior year. Energen Resources generated net income for the nine months ended September 30, 2012, of $153.6 million as compared with $209.6 million in the previous period. Lower natural gas and natural gas liquids commodity prices (approximately $71 million after-tax), higher DD&A expense (approximately $65 million after-tax), a noncash impairment on certain natural gas properties in East Texas of approximately $13.4 million after-tax, increased lease operating expense excluding production taxes (approximately $17 million after-tax), a net after-tax $11 million non-cash mark-to-market loss on derivatives (resulting from an after-tax $22 million non-cash mark-to-market gain on derivatives during 2012 and an after-tax $33.1 million non-cash market-to-market gain on derivatives during 2011) and increased interest expense (approximately $11 million after-tax) were partially offset by increased production volumes (approximately $133 million) and higher oil commodity prices (approximately $4 million after-tax). Alagasco’s net income of $37.2 million in the current year-to-date compared to net income of $35.3 million in the same period in the previous year. This increase primarily reflects the utility’s ability to earn on a higher level of equity in support of Alagasco's investment in its distribution system and support facilities devoted to public service.

Oil and Gas Operations

Revenues from oil and gas operations declined 26.8 percent to $233.5 million for the three months ended September 30, 2012 largely as a result of the non-cash mark-to-market losses on derivatives and decreased realized commodity prices partially offset by higher production volumes. Revenues from oil and gas operations rose 9.9 percent to $856.9 million for the nine months ended September 30, 2012 primarily as a result of higher production volumes and increased realized oil commodity prices partially offset by the non-cash mark-to-market losses on derivatives and decreased realized natural gas and natural gas liquids commodity prices. During the current quarter, revenue per unit of production for natural gas decreased 30 percent to $3.80 per thousand cubic feet (Mcf), while oil revenue per unit of production decreased 2.2 percent to $82.74 per barrel. Natural gas liquids revenue per unit of production fell 22 percent to an average price of $0.78 per gallon. In the year-to-date, revenue per unit of production for natural gas decreased 31.5 percent to $3.76 per Mcf, oil revenue per unit of production increased 5.4 percent to $84.48 per barrel and natural gas liquids revenue per unit of production fell 15.8 percent to an average price of $0.80 per gallon. Revenues per unit of production for the current quarter and year-to-date reflect realized prices and derivative gains and losses including effects of designated cash flow hedges.

Production for the current quarter and year-to-date increased largely due to higher volumes related to increased field development in certain Permian Basin liquids-rich properties and increased volumes related to the 2011 acquisition of certain Permian Basin properties partially offset by normal production declines. Natural gas production in the third quarter rose 6.1 percent to 18.9 billion cubic feet (Bcf), oil volumes increased 33.4 percent to 2,279 thousand barrels (MBbl) and natural gas liquids production rose 3.7 percent to 25.2 million gallons (MMgal). For the year-to-date, natural gas production increased 8.2 percent to 57.3 Bcf, while oil volumes rose 40.5 percent to 6,427 MBbl. Natural gas liquids production increased 18.6 percent to 79 MMgal. Natural gas comprised approximately 53 percent of Energen Resources' production for the current quarter and year-to-date.

Energen Resources may, in the ordinary course of business, be involved in the sale of developed or undeveloped properties. The Company includes gains and losses on the disposition of these assets in operating revenues. Energen Resources recorded a pre-tax gain of $0.1 million in the third quarter of 2012 and a pre-tax gain of $0.2 million year-to-date from the sale of various properties. Energen Resources recorded a pre-tax gain of $5.8 million in both the third quarter of 2011 and year-to-date primarily from the sale of certain properties in the Permian Basin.

29

Operations and maintenance (O&M) expense increased $12.6 million for the quarter and $32 million for the year-to-date. Lease operating expense (excluding production taxes) generally reflects year over year increases in the number of active wells resulting from Energen Resources' ongoing development, exploratory and acquisition activities. Lease operating expense (excluding production taxes) increased $9.2 million for the quarter largely due to increased water disposal costs (approximately $2.6 million), the acquisitions of Permian Basin liquids-rich properties (approximately $1.8 million), additional ad valorem taxes (approximately $1.1 million), increased chemical and treatment costs (approximately $0.9 million) and increased nonoperated expense (approximately $0.7 million). In the year-to-date, lease operating expense (excluding production taxes) increased $26.9 million primarily due to additional water disposal costs (approximately $7.4 million), Permian Basin acquisitions (approximately $3.5 million), increased workover and repair expense (approximately $3.1 million), increased ad valorem taxes (approximately $2.9 million), higher marketing and transportation costs (approximately $2.6 million), higher labor costs (approximately $1.9 million), increased chemical and treatment costs (approximately $1.8 million), increased nonoperated expense (approximately $1.8 million) and higher equipment rental (approximately $1.1 million) partially offset by lower other O&M expense (approximately $1.6 million). On a per unit basis, the average lease operating expense (excluding production taxes) for the current quarter was $10.58 per barrel of oil equivalent (BOE) as compared to $10.39 per BOE in the same period a year ago. For the nine months ended September 30, 2012, the average lease operating expense (excluding production taxes) was $10.03 per BOE as compared to $10.16 per BOE in the previous period. Administrative expense increased $3.6 million for the three months ended September 30, 2012 largely due to increased costs from the Company’s benefit and performance-based compensation plans (approximately $4 million) and higher labor costs (approximately $1.8 million) partially offset by decreased legal expenses (approximately $1.9 million). For the nine months ended September 30, 2012, administrative expense rose $4.3 million primarily due to increased costs from the Company’s benefit and performance-based compensation plans (approximately $2.4 million) and higher labor costs (approximately $2.3 million) partially offset by lower legal expenses (approximately $0.6 million). Exploration expense fell $0.1 million in the third quarter of 2012 and rose $0.8 million year-to-date.

Energen Resources' DD&A expense for the quarter rose $30.9 million. For the year-to-date, DD&A expense increased $120.9 million which includes an impairment writedown on certain properties in East Texas of $21.5 million pre-tax to adjust the carrying amount of certain properties to their fair value based on expected future discounted cash flows. The average depletion rate for the current quarter was $15.38 per BOE as compared to $11.78 per BOE in the same period a year ago. For the nine months ended September 30, 2012, the average depletion rate, excluding the asset impairment, was $14.92 per BOE as compared to $11.15 per BOE in the previous period. The increase in the current quarter and year-to-date per unit DD&A rate, which contributed approximately $18.7 million and $53.8 million, respectively, to the increase in DD&A expense, was largely due to higher rates resulting from the acquisition of liquids-rich properties and an increase in development costs. Higher production volumes contributed approximately $12.1 million and $45.3 million to the increase in DD&A expense for the quarter and year-to-date, respectively.

Energen Resources' expense for taxes other than income taxes was $0.3 million lower in the three months ended September 30, 2012 largely due to production-related taxes. Production-related taxes for the quarter decreased by approximately $2.4 million primarily due to lower net commodity market prices partially offset by higher natural gas, oil and natural gas liquid production volumes of approximately $2.1 million. Energen Resources' expense for taxes other than income taxes was $0.6 million higher in the nine months ended September 30, 2012 largely due to production-related taxes. In the year-to-date, higher commodity production volumes contributed approximately $7.8 million to the increase in production-related taxes partially offset by a decrease of approximately $7.2 million primarily due to lower net commodity market prices. Commodity market prices exclude the effects of derivative instruments for purposes of determining severance taxes.

Natural Gas Distribution

Natural gas distribution revenues increased $2.2 million for the quarter largely due to an increase in customer usage and slightly higher gas costs. During the third quarter of 2012, Alagasco had a net $1.3 million pre-tax reduction in revenues to bring the return on average common equity to midpoint within the allowed range of return. During the third quarter of 2011, Alagasco had a net $1.2 million pre-tax reduction in revenues to bring the return on average common equity to midpoint within the allowed range of return. For the quarter, weather was comparable with the same quarter in the prior year. Residential sales volumes fell slightly while commercial and industrial customer sales volumes increased 5.5 percent. Transportation volumes increased 12.5 percent in period comparisons. Revenues for the year-to-date fell $88.3 million primarily due to a decline in customer usage and lower gas costs partially offset by adjustments from the utility’s rate setting mechanisms. During the year-to-date 2012, Alagasco had a net $6.3 million pre-tax reduction in revenues to bring the return on average common equity to midpoint within the allowed range of return. In the 2011 year-to-date, Alagasco had a net reduction in revenues of $6.7 million pre-tax to bring the return on average common equity to midpoint within the allowed range of return. Weather, for the current nine months, that was 35.3 percent warmer compared with the same period in the prior year contributed to a 30.6 percent decrease in residential sales volumes and a 21.8 percent fall in commercial and industrial customer sales volumes. Transportation volumes increased 3.3 percent in period comparisons. A decrease in gas purchase volumes partially offset by slightly higher gas costs resulted in a 3.8 percent decrease in cost of gas for the quarter. For the year-to-date, a significant decrease in gas purchase volumes along with decreased gas costs resulted in a 49.3 percent decrease in cost of gas. Utility gas costs include commodity cost, risk management gains and losses and the provisions of the Gas Supply

30

Adjustment (GSA) rider. The GSA rider in Alagasco's rate schedule provides for a pass-through of gas price fluctuations to customers without markup. Alagasco's tariff provides a temperature adjustment mechanism, also included in the GSA, that is designed to moderate the impact of departures from normal temperatures on Alagasco’s earnings. The temperature adjustment applies primarily to residential, small commercial and small industrial customers.

O&M expense rose 12.8 percent in the current quarter primarily due to higher labor-related costs (approximately $0.9 million), increased business development and marketing expense (approximately $0.9 million), additional distribution operation expenses (approximately $0.6 million), higher legal expense (approximately $0.4 million) and increased technology costs (approximately $0.3 million). In the nine months ended September 30, 2012, O&M expense increased 1 percent primarily due to higher business development and marketing expense (approximately $1.6 million), increased distribution operations (approximately $0.8 million), additional technology costs (approximately $0.5 million), higher legal expense (approximately $0.3 million), increased economic development expenditures (approximately $0.3 million) and increased insurance costs (approximately $0.2 million) partially offset by lower bad debt expense impacted by warmer weather in the current year-to-date and enhanced credit and collection processes implemented in 2011 (approximately $2.8 million) and decreased labor-related costs (approximately $0.5 million).

A 5.9 percent increase in depreciation expense in the current quarter and a 6.6 percent increase year-to-date was primarily due to the extension and replacement of the utility's distribution system and replacement of its support systems. Taxes other than income taxes primarily reflected various state and local business taxes as well as payroll-related taxes. State and local business taxes generally are based on gross receipts and fluctuate accordingly.

Non-Operating Items

Interest expense for the Company rose $5.2 million in the third quarter of 2012 and $17.6 million year-to-date largely due to the August 2011 issuance of $400 million of Senior Notes by Energen with an interest rate of 4.625 percent, the December 2011 issuance of $50 million of Senior Notes by Alagasco with an interest rate of 3.86 percent and the December 2011 issuance of $300 million of Senior Term Loans. Also contributing to the increase in interest expense for the quarter were higher short-term borrowings. The $300 million issuance includes $100 million with a floating rate of LIBOR plus 1.375 percent, currently 1.59 percent at September 30, 2012 and $200 million swapped to a fixed rate at 2.4175 percent. Income tax expense for the Company decreased $47.7 million and $32.4 million in the current quarter and year-to-date, respectively, largely due to lower pre-tax income.

FINANCIAL POSITION AND LIQUIDITY

Cash flows from operations for the year-to-date were $603.1 million as compared to $593.9 million in the prior period. Net income decreased during period comparisons primarily due to lower realized natural gas and natural gas liquids commodity prices partially offset by increased production volumes and higher realized oil commodity prices at Energen Resources. Deferred income taxes decreased in the current year due to the tax effect of reduced bonus depreciation in 2012. The Company’s working capital needs were also influenced by accrued taxes, commodity prices and the timing of payments and recoveries, including gas supply pass-through adjustments. During 2011, the income tax receivable decreased approximately $39.3 million primarily from an income tax refund associated with the 2010 impact of bonus depreciation and the write-off of Alabama shale leasehold. Working capital needs at Alagasco were additionally affected by lower gas costs and changes to storage gas inventory compared to the prior period.

The Company had a net outflow of cash from investing activities of $1.0 billion for the nine months ended September 30, 2012 primarily due to additions of property, plant and equipment of $1,002 million. Energen Resources incurred on a cash basis $953 million in capital expenditures primarily related to the acquisition and development of oil and gas properties. In February 2012, Energen Resources completed the purchase of certain properties located in the Permian Basin for a cash price of approximately $68 million. Utility capital expenditures on a cash basis totaled $49.7 million year-to-date and primarily represented expansion and replacement of its distribution system and replacement of its support facilities.

The Company provided net cash of $435.2 million from financing activities in the year-to-date primarily due to an increase in short-term borrowings partially offset by the payment of dividends to common shareholders.

Oil and Gas Operations

The Company plans to continue investing significant capital in Energen Resources’ oil and gas production operations. For 2012, the Company expects its oil and gas capital spending to total approximately $1.3 billion, including $103 million for certain property acquisitions in the Permian Basin and $1.2 billion for existing properties, including exploration to date of $305 million. On an annual basis, the development and exploration expenditures cannot be reasonably segregated as drilling and development throughout the course of the year may change the classification of locations currently identified as exploratory. In February 2012, Energen completed the purchase of certain properties in the Permian Basin for a cash purchase price of $68 million (including the effects of closing

31

adjustments). This purchase had an effective date of December 1, 2011. Energen acquired total proved reserves of approximately 8.1 MMBOE. Of the proved reserves acquired, an estimated 81 percent are undeveloped. Approximately 64 percent of the proved reserves are oil, 22 percent are natural gas liquids and natural gas comprises the remaining 14 percent. Energen Resources used its credit facilities and internally generated cash flows to finance the acquisition. Capital investment at Energen Resources in 2013 is expected to approximate $900 million. These estimates are subject to revision as Energen Resources completes its formal budgeting process for 2013.

The Company also may allocate additional capital for other oil and gas activities such as property acquisitions and additional development of existing properties. Energen Resources may evaluate acquisition opportunities which arise in the marketplace and from time to time will pursue acquisitions that meet Energen’s acquisition criteria. Energen Resources’ ability to invest in property acquisitions is subject to market conditions and industry trends. Property acquisitions, except as disclosed above, are not included in the aforementioned estimate of oil and gas investments and could result in capital expenditures different from those outlined above. To finance capital spending at Energen Resources, the Company expects to use internally generated cash flow supplemented by its credit facilities. The Company also may issue long-term debt and equity periodically to replace short-term obligations, enhance liquidity and provide for permanent financing. The Company currently has no plans for the issuance of equity.

Impairment

During the first quarter of 2012, Energen Resources recognized a noncash impairment writedown on certain properties in East Texas of $21.5 million pre-tax to adjust the carrying amount of these properties to their fair value based on expected future discounted cash flows. Significant assumptions in valuing the proved reserves included the reserve quantities, anticipated operating costs, anticipated production taxes, future expected natural gas prices and basis differentials, anticipated production declines, and a discount rate of 10 percent commensurate with the risk of the underlying cash flow estimates. The impairment was caused by the impact of lower future natural gas prices. During the first quarter of 2012, future natural gas price curves shifted significantly lower, especially in the next 5 years. This nonrecurring impairment writedown is classified as Level 3 fair value.

Natural Gas Distribution

Alagasco is subject to regulation by the Alabama Public Service Commission (APSC) and is allowed to earn a range of return on average common equity of 13.15 percent to 13.65 percent. RSE limits the utility’s equity upon which a return is permitted to 55 percent of total capitalization, subject to certain adjustments. Given existing economic conditions, Alagasco expects only modest growth in equity supporting Alagasco's investment in its distribution system and support facilities devoted to public service as annual dividends are typically paid by the utility.

On June 28, 2010, the APSC approved a reduction in depreciation rates, effective June 1, 2010, for Alagasco with the revised prospective composite depreciation rate approximating 3.1 percent. Related to the lower depreciation rates, Alagasco refunded to eligible customers approximately $25.6 million of refundable negative salvage costs through a one-time bill credit in July 2010. Refunds of negative salvage costs to customers through lower tariff rates were $12.5 million, $22.2 million and $2.7 million for the periods January through September 2012, January through December 2011 and in December 2010, respectively. Alagasco anticipates refunding approximately $18.4 million of refundable negative salvage costs through lower tariff rates over the next twelve months. An additional estimated $55.1 million of refundable negative salvage costs will be refunded to eligible customers on a declining basis through lower tariff rates over a seven year period beginning January 1, 2013. The total amount refundable to customers is subject to adjustments over the entire nine year period for charges made to the Enhanced Stability Reserve (ESR) and other commission-approved charges. On November 1, 2010, the APSC specifically approved adjustments to the total amount refundable to include items originally approved in the APSC's 1998 order establishing the ESR, extraordinary O&M expenses related to environmental response costs, and extraordinary O&M expenses related to self insurance costs that exceed $1 million per occurrence. As of the rate year ended September 30, 2011, an adjustment for environmental response costs of $4.8 million from the ESR was made to reduce the total refundable amount. The refunds as of September 2012 and the remaining amount refundable over the entire nine year period are due to a re-estimation of future removal costs provided for through the prior depreciation rates. The re-estimation was primarily the result of Alagasco’s actual removal cost experience, combined with technology improvements and Alagasco’s system efficiency improvements, during the five years prior to the approval of the reduction in depreciation rates.

Alagasco is a mature utility operating in a slow-growth service area. Over the last five years, Alagasco's customer count has declined at a rate of approximately 1 percent. While enhanced credit and collection processes implemented in 2011 to reduce bad debt expense combined with the impact of severe weather on April 27, 2011, including a number of deadly tornados causing significant damage to several communities in Alabama served by Alagasco, have resulted in a loss of customers, the number of active accounts as of September 30, 2012 had a small net increase as compared to September 30, 2011. To increase its customer base, the utility is capitalizing on opportunities to expand its distribution lines to areas with potential for economic growth and appliance conversions. Alagasco monitors the bad debt reserve and makes adjustments as required based on its evaluation of receivables which are impacted by natural gas prices and the underlying current and future economic conditions facing the utility's customer base. During the nine

32

months ended September 30, 2012, Alagasco reduced the bad debt reserve by approximately $6.3 million primarily due to certain aged receivables transitioned to the utility's long-term collections, in addition to the impact of its collection related initiatives.

Another aspect of growth is usage per customer. Throughout the country, customer use of natural gas has declined over the years in large part due to energy-efficiencies in home construction and appliances and conservation. Alagasco’s marketing and business development emphasis in this area is directed toward retention and increasing end-use applications by existing customers.

Alagasco maintains an investment in storage gas that is expected to average approximately $37 million in 2012 but will vary depending upon the price of natural gas. During 2012 and 2013, Alagasco plans to invest an estimated $69 million and $75 million, respectively, in capital expenditures for the normal needs of its distribution and support systems and for technology-related projects designed to improve customer service. The utility anticipates funding these capital requirements through internally generated capital and the utilization of its credit facilities. Alagasco also may issue long-term debt periodically to replace short-term obligations, enhance liquidity and provide for permanent financing.

Derivative Commodity Instruments

Energen Resources periodically enters into derivative commodity instruments to hedge its price exposure to its estimated oil, natural gas and natural gas liquids production. Such instruments may include over-the-counter (OTC) swaps, collars and basis hedges typically with investment and commercial banks and energy-trading firms. At September 30, 2012, the counterparty agreements under which the Company had active positions did not include collateral posting requirements. Energen Resources was in a net gain position with eleven of its active counterparties and in a net loss with the remaining three at September 30, 2012. The Company is at risk for economic loss based upon the creditworthiness of its counterparties. Hedge transactions are pursuant to standing authorizations by the Board of Directors, which do not authorize speculative positions.

In prior years, Alagasco entered into cash flow derivative commodity instruments to hedge its exposure to price fluctuations on its gas supply pursuant to standing authorizations by the Board of Directors. Alagasco has not entered into any new cash flow derivative transactions on its gas supply since the summer of 2010. Alagasco recognizes all derivatives at fair value as either assets or liabilities on the balance sheet. Any gains or losses are passed through to customers using the mechanisms of the GSA in compliance with Alagasco’s APSC-approved tariff and are recognized as a regulatory asset or regulatory liability.

33

Energen Resources entered into the following transactions for the remainder of 2012 and subsequent years:

Production Period	Total Hedged Volumes		Average Contract Price	Description
Natural Gas
2012	3.6	Bcf	$4.49 Mcf	NYMEX Swaps
	8.9	Bcf	$4.14 Mcf	Basin Specific Swaps - San Juan
	2.0	Bcf	$2.89 Mcf	Basin Specific Swaps - Permian
2013	12.7	Bcf	$4.82 Mcf	NYMEX Swaps
	32.8	Bcf	$4.56 Mcf	Basin Specific Swaps - San Juan
	4.6	Bcf	$3.45 Mcf	Basin Specific Swaps - Permian
2014	10.6	Bcf	$4.55 Mcf	NYMEX Swaps
	25.7	Bcf	$4.72 Mcf	Basin Specific Swaps - San Juan
	9.7	Bcf	$3.81 Mcf	Basin Specific Swaps - Permian
Gas Basis Differential
2012	0.1	Bcf	$(0.23) Mcf	San Juan Basis Swaps
Oil
2012	1,850	MBbl	$88.51 Bbl	NYMEX Swaps
2013	8,858	MBbl	$90.95 Bbl	NYMEX Swaps
2014	9,796	MBbl	$92.64 Bbl	NYMEX Swaps
Oil Basis Differential
2012	752	MBbl	$(2.95) Bbl	WTS/WTI Basis Swaps**
2013	3,592	MBbl	$(3.03) Bbl	WTS/WTI Basis Swaps**
	1,740	MBbl	$(1.13) Bbl	WTI/WTI Basis Swaps***
	1,020	MBbl*	$(0.80) Bbl	WTI/WTI Basis Swaps***
Natural Gas Liquids
2012	15.3	MMGal	$0.99 Gal	Liquids Swaps
2013	44.5	MMGal	$1.02 Gal	Liquids Swaps
* Contract entered into subsequent to September 30, 2012
**WTS - West Texas Sour/Midland, WTI - West Texas Intermediate/Cushing
***WTI - West Texas Intermediate/Midland, WTI - West Texas Intermediate/Cushing

Alagasco entered into the following natural gas transactions for the remainder of 2012 and subsequent years:

Production Period	Total Hedged Volumes		Description
2012	4.6	Bcf	NYMEX Swaps
2013	1.5	Bcf	NYMEX Swaps

Realized prices are anticipated to be lower than New York Mercantile Exchange (NYMEX) prices primarily due to basis differences and other factors.

See Note 3, Derivative Commodity Instruments, in the Notes to Unaudited Condensed Financial Statements for information regarding the Company’s policies on fair value measurement.

34

The following sets forth derivative assets and liabilities that were measured at fair value on a recurring basis:

	September 30, 2012
(in thousands)	Level 2*			Level 3*			Total
Current assets	$	(1,048	)	$	37,323		$	36,275
Noncurrent assets	18,133			25,004			43,137
Current liabilities	(30,588		)	(1,349		)	(31,937		)
Noncurrent liabilities	(5,358		)	(3,697		)	(9,055		)
Net derivative asset (liability)	$	(18,861	)	$	57,281		$	38,420

	December 31, 2011
(in thousands)	Level 2*			Level 3*			Total
Current assets	$	(14,843	)	$	36,635		$	21,792
Noncurrent assets	(8,382		)	39,438			31,056
Current liabilities	(98,468		)	(8,822		)	(107,290		)
Noncurrent liabilities	(32,928		)	(1,450		)	(34,378		)
Net derivative asset (liability)	$	(154,621	)	$	65,801		$	(88,820	)

* Amounts classified in accordance with accounting guidance which permits offsetting fair value amounts recognized for multiple derivative instruments executed with the same counterparty under a master netting arrangement.

As of September 30, 2012, Alagasco had $15.0 million of derivative instruments which are classified as Level 2 fair values and are included in the above table as current liabilities. As of December 31, 2011, Alagasco has $56.8 million and $3.1 million of derivative instruments which are classified as Level 2 fair values and are included in the table as current and noncurrent liabilities, respectively. Alagasco had no derivative instruments classified as Level 3 fair values as of September 30, 2012 and December 31, 2011.

Level 3 assets and liabilities as of September 30, 2012, represent approximately 1 percent of total assets and an immaterial amount of liabilities, respectively. Changes in fair value primarily result from price changes in the underlying commodity. The Company has prepared a sensitivity analysis to evaluate the hypothetical effect that changes in the prices used to estimate fair value would have on the fair value of its derivative instruments. The Company estimates that a 10 percent increase or decrease in commodity prices would result in an approximate $35 million change in the fair value of open Level 3 derivative contracts. The resulting impact upon the results of operations would be an approximate $5.9 million associated with open Level 3 mark-to-market derivative contracts. Cash flow requirements to meet the obligation would not be significantly impacted as gains and losses on the derivative contracts would be similarly offset by sales at the spot market price.

In July 2010, the Dodd-Frank Wall Street Reform and Consumer Protection Act (Dodd-Frank Act) was signed into law. Title VII of the Dodd-Frank Act establishes federal oversight and regulation of the over-the-counter derivatives markets and participants in such markets and requires the Commodities Futures Trading Commission (CFTC) and the Securities and Exchange Commission (SEC) to promulgate implementing rules and regulations. The Dodd-Frank Act imposes certain margin, clearing and trade execution requirements. Under rules and regulations recently adopted by the CFTC and the SEC, the Company and Alagasco expect their derivatives transactions to qualify for an end-user exception which will exempt them from the Dodd-Frank Act margin and exchange clearing requirements. The Company and Alagasco will be subject to new and expanded documentation, record keeping and reporting requirements.

Stock Repurchases

Energen periodically considers stock repurchases as a capital investment. Energen may buy shares on the open market or in negotiated purchases. The timing and amounts of any repurchases are subject to changes in market conditions. The Company did not repurchase shares of common stock for this program during the nine months ended September 30, 2012. The Company expects any future stock repurchases to be funded through internally generated cash flow or through the utilization of its credit facilities. During the three months and nine months ended September 30, 2012, the Company had noncash purchases of approximately $111,000 and $229,000, respectively, of Company common stock in conjunction with tax withholdings on its non-qualified deferred compensation plan and other stock compensation plans. The Company utilized internally generated cash flows in payment of the related tax withholdings.

35

Credit Facilities and Working Capital

On October 30, 2012, Energen and Alagasco entered into $1,250 million and a $100 million, respectively, five-year syndicated unsecured credit facilities (syndicated credit facilities) with domestic and foreign lenders. These syndicated credit facilities replace Energen's $850 million and Alagasco's $150 million three-year syndicated credit facilities. Energen obligations under the $1,250 million syndicated credit facility are unconditionally guaranteed by Energen Resources. There are certain restrictive covenants including a financial covenant with a maximum consolidated debt to capitalization ratio of not more than 65 percent for both the Company and Alagasco.

Energen and Alagasco rely upon internally generated cash flows supplemented by the syndicated credit facilities and the short-term credit facilities to fund working capital needs. The Company may also issue long-term debt and equity periodically to replace obligations under the credit facilities, enhance liquidity and provide for permanent financing.

Working capital requirements for Energen and Alagasco are influenced by short-term borrowings to finance recent acquisitions, the fair value of the Company's derivative financial instruments associated with future production, the recovery and pass-through of regulatory items and the seasonality of Alagasco's business. Energen's accounts receivable and accounts payable at September 30, 2012 include $36.3 million and $31.9 million, respectively, associated with its derivative financial instruments. Working capital at Alagasco reflects an expected pass-through to rate payers of $18.4 million in refundable negative salvage costs representing a reduction in future revenues through lower tariff rates.

Dividends

Energen expects to pay annual cash dividends of $0.56 per share on the Company’s common stock in 2012. The amount and timing of all dividend payments is subject to the discretion of the Board of Directors and is based upon business conditions, results of operations, financial conditions and other factors.

Contractual Cash Obligations

In the course of ordinary business activities, Energen enters into a variety of contractual cash obligations and other commitments. Except as discussed below, there have been no material changes to the contractual cash obligations of the Company since December 31, 2011.

During the first quarter of 2012, the Company entered into certain capital leases related to certain equipment. The following is a schedule of future minimum lease payments under capital leases together with the present value of the net minimum lease payments as of September 30, 2012:

(in thousands)
2012	$	436
2013	1,743
2014	1,743
2015	145
Total minimum lease payments	4,067
Less amount representing interest	93
Total present value of minimum lease payments	$	3,974

Commitments and Agreements: Under various agreements for third party gathering, treatment, transportation or other services, Energen Resources is committed to deliver minimum production volumes or to pay certain costs in the event the minimum quantities are not delivered. These delivery commitments are approximately 33.4 million barrels of oil equivalent (MMBOE) through November 2021.

Other Commitments

During the third quarter of 2010, Energen Resources received preliminary findings from the Taxation and Revenue Department (the Department) of the State of New Mexico relating to its audit, conducted on behalf of the Office of Natural Resources Revenue (ONRR), of federal oil and gas leases in New Mexico. The audit covered periods from January 2004 through December 2008 and included a review of the computation and payment of royalties due on minerals removed from specified U.S. federal leases. The ONRR has proposed certain changes in the method of determining allowable deductions of transportation, fuel and processing costs from royalties due under the terms of the related leases.

As a result of the audit, Energen Resources has been ordered by the ONRR to pay additional royalties on the specified U.S. federal leases in the amount of $142,000 and restructure its accounting for all federal leases in two counties in New Mexico from March 1,

36

2004 forward. The Company preliminarily estimates that application of the Order to all of the Company's New Mexico federal leases would result in ONRR claims for up to approximately $23 million of additional royalties plus interest and penalties for the period from March 1, 2004 forward. The preliminary findings and subsequent Order (issued April 25, 2011) are contrary to deductions allowed under previous audits, retroactive in application and inconsistent with the Company’s understanding of industry practice. The Company is vigorously contesting the Order and has requested additional information from the ONRR and the Department to assist the Company in evaluating the ONRR Order and the Department's findings. Management is unable, at this time, to determine a range of reasonably possible losses as a result of this Order, and no amount has been accrued as of September 30, 2012.

Recent Accounting Standards Updates

See Note 13, Recently Issued Accounting Standards, in the Notes to Unaudited Condensed Financial Statements for information regarding recently issued accounting standards.

FORWARD LOOKING STATEMENTS AND RISK FACTORS

The disclosure and analysis in this report contains forward-looking statements that express management’s expectations of future plans, objectives and performance of the Company and its subsidiaries. Such statements constitute forward-looking statements within the meaning of Section 27A of the Securities Act, as amended, and Section 21E of the Exchange Act, as amended, and are noted in the Company’s disclosure as permitted by the Private Securities Litigation Reform Act of 1995. Forward-looking statements often address the Company’s future business and financial performance and financial condition, and often contain words such as “expect”, “anticipate”, “intend”, “plan”, “believe”, “seek”, “see”, “project”, “will”, “estimate”, “may”, and other words of similar meaning.

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. Some of these include, but are not limited to, economic and competitive conditions, production levels, reserve levels, energy markets, supply and demand for and the price of energy commodities including oil, gas and natural gas liquids, fluctuations in the weather, drilling risks, costs associated with compliance with environmental obligations, inflation rates, legislative and regulatory changes, financial market conditions, the Company’s ability to access the capital markets, future business decisions, utility customer growth and retention and usage per customer, litigation results and other factors and uncertainties discussed elsewhere in this report and in the Company’s other public filings and press releases, all of which are difficult to predict. While it is not possible to predict or identify all the factors that could cause the Company’s actual results to differ materially from expected or historical results, the Company has identified certain risk factors which may affect the Company’s future business and financial performance.

Commodity prices for crude oil and natural gas are volatile, and a substantial reduction in commodity prices could adversely affect the Company's results and the carrying value of its oil and natural gas properties: The Company and Alagasco are significantly influenced by commodity prices. Historical markets for natural gas, oil and natural gas liquids have been volatile. Energen Resources’ revenues, operating results, profitability and cash flows depend primarily upon the prices realized for its oil, gas and natural gas liquid production. Additionally, downward commodity price trends may impact expected cash flows from future production and potentially reduce the carrying value of Company-owned oil and natural gas properties. Alagasco’s competitive position and customer demand is significantly influenced by prices for natural gas which are passed-through to customers.

Market conditions or a downgrade in the Company's credit rating could negatively impact its cost of and ability to access capital for future development and working capital needs: The Company and its subsidiaries rely on access to credit markets. The availability and cost of credit market access is significantly influenced by market events and rating agency evaluations for both lenders and the Company. Market volatility and credit market disruption may severely limit credit availability and issuer credit ratings can change rapidly. Events negatively affecting credit ratings and credit market liquidity could increase borrowing costs or limit availability of funds to the Company.

Energen Resources' hedging activities may prevent Energen Resources from benefiting fully from price increases and expose Energen Resources to other risks, including counterparty credit risk: Although Energen Resources makes use of futures, swaps, options, collars and fixed-price contracts to mitigate price risk, fluctuations in future oil, gas and natural gas liquids prices could materially affect the Company's financial position, results of operations and cash flows; furthermore, such risk mitigation activities may cause the Company's financial position and results of operations to be materially different from results that would have been obtained had such risk mitigation activities not occurred. The effectiveness of such risk mitigation assumes that counterparties maintain satisfactory credit quality. The effectiveness of such risk mitigation also assumes that actual sales volumes will generally meet or exceed the volumes subject to the futures, swaps, options, collars and fixed-price contracts. A substantial failure to meet sales volume targets, whether caused by miscalculations, weather events, natural disaster, accident, mechanical failure, criminal act or otherwise, could leave Energen Resources financially exposed to its counterparties and result in material adverse financial

37

consequences to Energen Resources and the Company. The adverse effect could be increased if the adverse event was widespread enough to move market prices against Energen Resources' position. In addition, various existing and pending financial reform rules and regulations could have an adverse effect on the ability of Energen Resources to use derivative instruments which could have a material adverse effect on our financial position, results of operations and cash flows.

Alagasco's hedging activities may adversely affect Alagasco's financial condition and results of operations should gas supply needs fail to meet projected volumes, and such hedging activities also expose Alagasco to counterparty credit risk:Similarly, although Alagasco has made use of cash flow derivative commodity instruments to mitigate gas supply cost risk, fluctuations in future gas supply costs could materially affect its financial position and rates to customers. The effectiveness of Alagasco's risk mitigation assumes that its counterparties in such activities maintain satisfactory credit quality. The effectiveness of such risk mitigation also assumes that Alagasco's actual gas supply needs will generally meet or exceed the volumes subject to the cash flow derivative commodity instruments. A substantial failure to experience projected gas supply needs, whether caused by miscalculations, weather events, natural disaster, accident, mechanical failure, criminal act or otherwise, could leave Alagasco financially exposed to its counterparties and result in material adverse financial consequences to Alagasco and the Company. The adverse effect could be increased if the adverse event was widespread enough to move market prices against Alagasco's position. In addition, various existing and pending financial reform rules and regulations could have an adverse effect on the ability of Alagasco to use derivative instruments which could have a material adverse effect on our financial position, results of operations and cash flows.

The Company is exposed to counterparty credit risk as a result of its concentrated customer base: Revenues and related accounts receivable from oil and gas operations primarily are generated from the sale of produced oil, natural gas and natural gas liquids to a small number of energy marketing companies. Such sales are typically made on an unsecured credit basis with payment due the month following delivery. This concentration of sales to a limited number of customers in the energy marketing industry has the potential to affect the Company's overall exposure to credit risk, either positively or negatively, based on changes in economic, industry or other conditions specific to a single customer or to the energy marketing industry generally. Energen Resources considers the credit quality of its customers and, in certain instances, may require credit assurances such as a deposit, letter of credit or parent guarantee.

The Company's operations depend upon the use of third party facilities and an interruption of its ability to utilize these facilities may adversely affect its financial condition and results of operations: Energen Resources delivers to and Alagasco is served by third party facilities. These facilities include third party oil and gas gathering, transportation, processing and storage facilities. Energen Resources relies upon such facilities for access to markets for its production. Alagasco relies upon such facilities for access to natural gas supplies. Such facilities are typically limited in number and geographically concentrated. An extended interruption of access to or service from these facilities, whether caused by weather events, natural disaster, accident, mechanical failure, criminal act or otherwise could result in material adverse financial consequences to Energen Resources, Alagasco and the Company.

The Company's oil and natural gas reserves are estimates, and actual future production may vary significantly and may also be negatively impacted by its inability to invest in production on planned timelines:There are numerous uncertainties inherent in estimating quantities of proved oil and gas reserves and in projecting future rates of production and timing of development expenditures. The total amount or timing of actual future production may vary significantly from reserve and production estimates. In the event Energen Resources is unable to fully invest its planned development, acquisition and exploratory expenditures, future operating revenues, production, and proved reserves could be negatively affected. The drilling of development and exploratory wells can involve significant risks, including those related to timing, success rates and cost overruns, and these risks can be affected by lease and rig availability, complex geology and other factors. Anticipated drilling plans and capital expenditures may also change due to weather, manpower and equipment availability, changing emphasis by management and a variety of other factors which could result in actual drilling and capital expenditures being substantially different than currently planned.

The Company's operations involve operational risk and its insurance policies do not cover all such risks: Inherent in the gas distribution activities of Alagasco and the oil and gas production activities of Energen Resources are a variety of hazards and operation risks, such as leaks, explosions and mechanical problems that could cause substantial financial losses. In addition, these risks could result in loss of human life, significant damage to property, environmental pollution, impairment of operations and substantial losses to the Company. In accordance with customary industry practices, the Company maintains insurance against some, but not all, of these risks and losses. Further, the Company’s insurance retention levels are such that significant events could adversely affect Energen Resources’, Alagasco's and the Company's financial position, results of operations and cash flows. The location of pipeline and storage facilities near populated areas, including residential areas, commercial business centers and industrial sites, could increase the level of damages resulting from these risks. The occurrence of any of these events could adversely affect Alagasco's, Energen Resources’ and the Company's financial position, results of operations and cash flows.

38

Alagasco operates in a limited service territory and is therefore subject to concentrated regional risks which may negatively affect Alagasco's financial condition and results of operations: Alagasco’s utility customers are geographically concentrated in central and north Alabama. Significant economic, weather, natural disaster, criminal act or other events that adversely affect this region could adversely affect Alagasco and the Company.

The Company is subject to numerous federal, state and local laws and regulations that may require significant expenditures or impose significant restrictions on its operations: Energen and Alagasco are subject to extensive federal, state and local regulation which significantly influences operations. Although the Company believes that operations generally comply with applicable laws and regulations, failure to comply could result in the suspension or termination of operations and subject the Company to administrative, civil and criminal penalties.Federal, state and local legislative bodies and agencies frequently exercise their respective authority to adopt new laws and regulations and to amend, modify and interpret existing laws and regulations.  Such changes can subject the Company to significant tax or cost increases and can impose significant restrictions and limitations on the Company's operations.

39

SELECTED BUSINESS SEGMENT DATA
ENERGEN CORPORATION
(Unaudited)
	Three months ended						Nine months ended
	September 30,						September 30,
(in thousands, except sales price data)	2012			2011			2012			2011
Oil and Gas Operations
Operating revenues
Natural gas	$	67,542		$	96,604		$	211,371		$	290,240
Oil	148,004			197,636			579,278			419,830
Natural gas liquids	17,566			24,476			64,970			63,491
Other	403			236			1,321			6,273
Total	$	233,515		$	318,952		$	856,940		$	779,834
Production volumes
Natural gas (MMcf)	18,882			17,796			57,252			52,908
Oil (MBbl)	2,279			1,709			6,427			4,574
Natural gas liquids (MMgal)	25.2			24.3			79.0			66.6
Total production volumes (MMcfe)	36,156			31,518			107,100			89,868
Total production volumes (MBOE)	6,026			5,253			17,850			14,978
Revenue per unit of production including effects of designated cash flow hedges
Natural gas (Mcf)	$	3.80		$	5.43		$	3.76		$	5.49
Oil (barrel)	$	82.74		$	84.56		$	84.48		$	80.17
Natural gas liquids (gallon)	$	0.78		$	1.00		$	0.80		$	0.95
Revenue per unit of production excluding effects of all derivative instruments
Natural gas (Mcf)	$	2.72		$	4.11		$	2.53		$	4.10
Oil (barrel)	$	86.53		$	86.17		$	89.91		$	90.40
Natural gas liquids (gallon)	$	0.68		$	1.17		$	0.78		$	1.11
Other data
Lease operating expense (LOE)
LOE and other	$	63,731		$	54,563		$	179,122		$	152,220
Production taxes	14,069			14,367			41,436			40,842
Total	$	77,800		$	68,930		$	220,558		$	193,062
Depreciation, depletion and amortization	$	93,766		$	62,822		$	269,312		$	169,953
Asset impairment	$	—		$	—		$	21,545		$	—
Capital expenditures	$	323,037		$	266,745		$	957,913		$	666,601
Exploration expenditures	$	10,646		$	10,775		$	13,387		$	12,596
Operating income	$	32,407		$	161,331		$	274,818		$	351,808
Natural Gas Distribution
Operating revenues
Residential	$	30,658		$	30,541		$	201,537		$	269,584
Commercial and industrial	17,695			16,984			84,889			107,283
Transportation	13,505			12,114			42,765			40,568
Other	(49		)	(23		)	(2,008		)	(1,938		)
Total	$	61,809		$	59,616		$	327,183		$	415,497

40

Gas delivery volumes (MMcf)
Residential	1,378			1,385			11,601		16,725
Commercial and industrial	1,246			1,181			6,137		7,843
Transportation	11,252			10,004			34,835		33,713
Total	13,876			12,570			52,573		58,281
Other data
Depreciation and amortization	$	10,572		$	9,980		$	31,551	$	29,606
Capital expenditures	$	18,813		$	21,333		$	51,786	$	57,170
Operating income (loss)	$	(12,743	)	$	(10,681	)	$	70,265	$	65,541

41

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Energen Resources' major market risk exposure is in the pricing applicable to its oil and gas production. Historically, prices received for oil and gas production have been volatile because of seasonal weather patterns, world and national supply-and-demand factors and general economic conditions. Crude oil prices also are affected by quality differentials, by worldwide political developments and by actions of the Organization of Petroleum Exporting Countries. Basis differentials, like the underlying commodity prices, can be volatile because of regional supply-and-demand factors, including seasonal factors and the availability and price of transportation to consuming areas.

Energen Resources periodically enters into derivative commodity instruments to hedge its exposure to price fluctuations to its estimated oil, natural gas and natural gas liquids production. In addition, Alagasco periodically enters into cash flow derivative commodity instruments to hedge its gas supply exposure. Such instruments may include over-the-counter swaps, collars and basis hedges with major energy derivative product specialists. The counterparties to the commodity instruments are investment banks and energy-trading firms and are believed to be creditworthy by the Company. The Company is at risk for economic loss based upon the creditworthiness of its counterparties. All hedge transactions are subject to the Company's risk management policy, approved by the Board of Directors, which does not permit speculative positions. The Company formally documents all relationships between hedging instruments and hedged items, as well as its risk management objective and strategy for undertaking the hedge. As of September 30, 2012, the maximum term over which Energen Resources and Alagasco have hedged exposures to the variability of cash flows is through December 31, 2014 and March 31, 2013, respectively

A failure to meet sales volume targets at Energen Resources or gas supply targets at Alagasco due to miscalculations, weather events, natural disasters, accidents, mechanical failure, criminal act or otherwise could leave the Company or Alagasco exposed to its counterparties in commodity hedging contracts and result in material adverse financial losses.

See Note 3, Derivative Commodity Instruments, in the Notes to Unaudited Condensed Financial Statements for details related to the Company's hedging activities.

The Company’s interest rate exposure as of September 30, 2012, primarily relates to its syndicated credit facilities with variable interest rates. The weighted average interest rate for amounts outstanding at September 30, 2012 was 1.91 percent. The Company's interest rate exposure as of September 30, 2012, was minimal since approximately 91 percent of long-term debt obligations were at fixed rates.

42

ITEM 4. CONTROLS AND PROCEDURES

Energen Corporation

(a) Our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) of the Securities Exchange Act of 1934) are designed to provide reasonable assurance of achieving their objectives and, as of the end of the period covered by this report, our chief executive officer and chief financial officer concluded that our disclosure controls and procedures are effective at that reasonable assurance level.

(b) Our chief executive officer and chief financial officer of Energen Corporation have concluded that during the most recent fiscal quarter covered by this report there were no changes in our internal control over financial reporting that materially affected or are reasonably likely to materially affect our internal control over financial reporting.

Alabama Gas Corporation

(a) Our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) of the Securities Exchange Act of 1934) are designed to provide reasonable assurance of achieving their objectives and, as of the end of the period covered by this report, our chief executive officer and chief financial officer concluded that our disclosure controls and procedures are effective at that reasonable assurance level.

(b) Our chief executive officer and chief financial officer of Alabama Gas Corporation have concluded that during the most recent fiscal quarter covered by this report there were no changes in our internal control over financial reporting that materially affected or are reasonably likely to materially affect our internal control over financial reporting.

43

PART II: OTHER INFORMATION

ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

Period	Total Number of Shares Purchased		Average Price Paid per Share		Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs	Maximum Number of Shares that May Yet Be Purchased Under the Plans or Programs**
July 1, 2012 through July 31, 2012	—		—		—	8,992,700
August 1, 2012 through August 31, 2012	1,857	*	$	51.33	—	8,992,700
September 1, 2012 through September 30, 2012	297	*	51.45		—	8,992,700
Total	2,154		$	51.35	—	8,992,700

* Acquired in connection with tax withholdings and payment of exercise price on stock compensation plans.

** By resolution adopted May 24, 1994, and supplemented by resolutions adopted April 26, 2000 and June 24, 2006, the Board of Directors authorized the Company to repurchase up to 12,564,400 shares of the Company's common stock. The resolutions do not have an expiration date.

ITEM 6. EXHIBITS

31(a)	-	Section 302 Energen Corporation Certification required by Rule 13a-14(a) or Rule 15d-14(a)
31(b)	-	Section 302 Energen Corporation Certification required by Rule 13a-14(a) or Rule 15d-14(a)
31(c)	-	Section 302 Alabama Gas Corporation Certification required by Rule 13a-14(a) or Rule 15d-14(a)
31(d)	-	Section 302 Alabama Gas Corporation Certification required by Rule 13a-14(a) or Rule 15d-14(a)
32(a)	-	Section 906 Energen Corporation Certification pursuant to 18 U.S.C. Section 1350
32(b)	-	Section 906 Alabama Gas Corporation Certification pursuant to 18 U.S.C. Section 1350
101	-	The financial statements and notes thereto from Energen Corporation's Quarterly Report on Form 10-Q/A for the
		quarter ended September 30, 2012 are formatted in XBRL

44

SIGNATURES

Pursuant to the requirements of the Securities and 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
November 13, 2012	By	/s/ J. T. McManus, II
		J. T. McManus, II
		Chairman, Chief Executive Officer and President of Energen Corporation; Chairman and Chief Executive Officer of Alabama Gas Corporation
November 13, 2012	By	/s/ Charles W. Porter, Jr.
		Charles W. Porter, Jr.
		Vice President, Chief Financial Officer and Treasurer of Energen Corporation and Alabama Gas Corporation
November 13, 2012	By	/s/ Russell E. Lynch, Jr.
		Russell E. Lynch, Jr.
		Vice President and Controller of Energen Corporation
November 13, 2012	By	/s/ William D. Marshall
		William D. Marshall
		Vice President and Controller of Alabama Gas Corporation

45

EX-31.A

Exhibit 31(a)

CERTIFICATION

I, J.T. McManus, II, certify that:

1. I have reviewed this quarterly report on Form 10-Q of Energen Corporation;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15(d)-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent function):

a) All significant deficiencies and material weaknesses in the design or operation of internal controls over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

November 13, 2012	By	/s/ J. T. McManus, II
		J. T. McManus, II Chairman, Chief Executive Officer and President of Energen Corporation

EX-31.B

Exhibit 31(b)

CERTIFICATION

I, Charles W. Porter, Jr., certify that:

1. I have reviewed this quarterly report on Form 10-Q of Energen Corporation;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15(d)-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent function):

a) All significant deficiencies and material weaknesses in the design or operation of internal controls over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

November 13, 2012	By	/s/ Charles W. Porter, Jr.
		Charles W. Porter, Jr. Vice President, Chief Financial Officer and Treasurer of Energen Corporation

EX-31.C

Exhibit 31(c)

CERTIFICATION

I, J.T. McManus, II, certify that:

1. I have reviewed this quarterly report on Form 10-Q of Alabama Gas Corporation;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15(d)-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent function):

a) All significant deficiencies and material weaknesses in the design or operation of internal controls over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

November 13, 2012	By	/s/ J. T. McManus, II
		J. T. McManus, II Chairman and Chief Executive Officer of Alabama Gas Corporation

EX-31.D

Exhibit 31(d)

CERTIFICATION

I, Charles W. Porter, Jr., certify that:

1. I have reviewed this quarterly report on Form 10-Q of Alabama Gas Corporation;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15(d)-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent function):

a) All significant deficiencies and material weaknesses in the design or operation of internal controls over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

November 13, 2012	By	/s/ Charles W. Porter, Jr.
		Charles W. Porter, Jr. Vice President, Chief Financial Officer and Treasurer of Alabama Gas Corporation

EX-32.A

Exhibit 32(a)

CERTIFICATION PURSUANT TO

18 U.S.C. 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Quarterly Report of Energen Corporation (the “Registrant”) on Form 10-Q for the period ended September 30, 2012, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), each of the undersigned hereby certifies with respect to the registrant, pursuant to 18 U.S.C. 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that, to his knowledge, the Report fully complies with the requirements of Section 13(a) of the Securities Exchange Act of 1934 and the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

Dated as of November 13, 2012

By	/s/ J. T. McManus, II
	J. T. McManus, II Chairman, Chief Executive Officer and President of Energen Corporation
By	/s/ Charles W. Porter, Jr.
	Charles W. Porter, Jr. Vice President, Chief Financial Officer and Treasurer of Energen Corporation

A signed original of this written statement required by Section 906, or other document authenticating, acknowledging or otherwise adopting the signature that appears in typed form within the electronic version of this written statement required by Section 906, has been provided to Energen Corporation and will be retained by Energen Corporation and furnished to the Securities and Exchange Commission or its staff upon request.

EX-32.B

Exhibit 32(b)

CERTIFICATION PURSUANT TO

18 U.S.C. 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Quarterly Report of Alabama Gas Corporation (the “Registrant”) on Form 10-Q for the period ended September 30, 2012, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), each of the undersigned hereby certifies with respect to the registrant, pursuant to 18 U.S.C. 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that, to his knowledge, the Report fully complies with the requirements of Section 13(a) of the Securities Exchange Act of 1934 and the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

Dated as of November 13, 2012

By	/s/ J. T. McManus, II
	J. T. McManus, II Chairman and Chief Executive Officer of Alabama Gas Corporation
By	/s/ Charles W. Porter, Jr.
	Charles W. Porter, Jr. Vice President, Chief Financial Officer and Treasurer of Alabama Gas Corporation

A signed original of this written statement required by Section 906, or other document authenticating, acknowledging or otherwise adopting the signature that appears in typed form within the electronic version of this written statement required by Section 906, has been provided to Alabama Gas Corporation and will be retained by Alabama Gas Corporation and furnished to the Securities and Exchange Commission or its staff upon request.

XML

Reconciliation of Earnings Per Share (Details) - Earnings Per Share Reconciliation (USD $) In Thousands, except Per Share data, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2012	Sep. 30, 2011	Sep. 30, 2012	Sep. 30, 2011
Earnings Per Share Reconciliation
Net Income, Basic EPS	$ 2,046	$ 87,599	$ 190,739	$ 245,192
Basic Shares Oustanding (in shares)	72,130	72,068	72,121	72,045
Earnings Per Share, Basic (dollars per share)	$ 0.03	$ 1.22	$ 2.64	$ 3.40
Effect of dilutive securities
Net Income, Diluted EPS	$ 2,046	$ 87,599	$ 190,739	$ 245,192
Diluted Shares Outstanding (in shares)	72,316	72,375	72,301	72,409
Earnings Per Share, Diluted (dollars per share)	$ 0.03	$ 1.21	$ 2.64	$ 3.39
Stock options
Effect of dilutive securities
Incremental Common Shares Attributable to Share-based Payment Arrangements	183	298	177	355
Non-vested restricted stock
Effect of dilutive securities
Incremental Common Shares Attributable to Share-based Payment Arrangements	3	9	3	9

XML

Financial Instruments (Details) (USD $)	9 Months Ended
	Sep. 30, 2012	Sep. 30, 2012 Long-term Debt, Including Current Portion, Fair Value, Fair Value Disclosure	Sep. 30, 2012 Long-term Debt, Including Current Portion, Carrying Value, Fair Value Disclosure	Sep. 30, 2012 Alabama Gas Corporation	Dec. 31, 2011 Alabama Gas Corporation	Sep. 30, 2012 Alabama Gas Corporation Long-term Debt, Including Current Portion, Fair Value, Fair Value Disclosure	Sep. 30, 2012 Alabama Gas Corporation Long-term Debt, Including Current Portion, Carrying Value, Fair Value Disclosure	Dec. 31, 2011 Senior Loans [Member] Swap [Member]	Dec. 31, 2011 Senior Loans [Member] Swap [Member] Senior Term Loans, Due March 31, 2014 to November 29, 2016 [Member]	Sep. 30, 2012 Senior Loans [Member] Fair Value, Inputs, Level 1 [Member] Swap [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term Debt, Fair Value		$ 1,256,200,000	$ 1,154,100,000			$ 284,900,000	$ 250,100,000
Debt Instrument, Face Amount									200,000,000
Debt Instrument, Interest Rate, Stated Percentage								2.4175%
Derivative Asset, Fair Value, Gross Liability										3,700,000
Financing Receivable				10,700,000	10,500,000
Financing Receivable, Recorded Investment, Average Balance 0 to 60 Days Past Due				3,000
Average Finance Receivable Term				up to 60 months
Financing Receivable, Recorded Investment, Equal to Greater than 90 Days Past Due				467,000
Financing Receivable, Allowance for Credit Losses [Roll Forward]
Allowance for credit losses, beginning balance	421,000
Provision	21,000
Allowance for credit losses, ending balance	$ 442,000

XML

Commitments and Contingencies (Details) - New Mexico Audits (Unfavorable Regulatory Action, USD $)	9 Months Ended
	Sep. 30, 2012
Unfavorable Regulatory Action
Loss Contingencies [Line Items]
Loss Contingency, Range of Possible Loss, Minimum	$ 142,000
Loss Contingency, Range of Possible Loss, Maximum	$ 23,000,000
Loss Contingency, Inestimable Loss	The preliminary findings and subsequent Order (issued April 25, 2011) are contrary to deductions allowed under previous audits, retroactive in application and inconsistent with the Company’s understanding of industry practice. The Company is vigorously contesting the Order and has requested additional information from the ONRR and the Department to assist the Company in evaluating the ONRR Order and the Department's findings. Management is unable, at this time, to determine a range of reasonably possible losses as a result of this Order, and no amount has been accrued as of June 30, 2012.

XML

Derivative Commodity Instruments - Commodity Contracts by Business Segment (Details) (USD $)	Sep. 30, 2012 counterparty		Dec. 31, 2011
Derivative [Line Items]
Number of Active Counterparties with Whom Company Holds Net Gain Positions	11
Number of Large Counterparties with Whom Company Holds Net Gain Positions	5
Number of Counterparties with Whom Company Holds Net Gain Positions	3
Derivative, Fair Value, Net	$ 38,420,000		$ (88,820,000)
Deferred tax assets (liabilities), net	(22,000,000)		5,700,000
Oil and Gas Operations [Member]
Derivative [Line Items]
Derivative, Fair Value, Net	53,410,000		(28,946,000)
Natural Gas Distribution [Member]
Derivative [Line Items]
Derivative, Fair Value, Net	(14,990,000)		(59,874,000)
Designated as Hedging Instrument [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Gross Asset	127,535,000		149,618,000
Derivative Liability, Fair Value, Net	(71,261,000)		(141,971,000)
Derivative, Fair Value, Net	56,274,000		7,647,000
Designated as Hedging Instrument [Member] | Oil and Gas Operations [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Gross Asset	127,535,000		149,618,000
Derivative Liability, Fair Value, Net	(71,261,000)		(141,971,000)
Derivative, Fair Value, Net	56,274,000		7,647,000
Designated as Hedging Instrument [Member] | Natural Gas Distribution [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Gross Asset	0		0
Derivative Liability, Fair Value, Net	0		0
Derivative, Fair Value, Net	0		0
Not Designated as Hedging Instrument [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Gross Asset	2,928,000		(12,255,000)
Derivative Liability, Fair Value, Gross Liability	(20,782,000)		(84,212,000)
Derivative, Fair Value, Net	(17,854,000)		(96,467,000)
Not Designated as Hedging Instrument [Member] | Oil and Gas Operations [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Gross Asset	2,928,000		(12,255,000)
Derivative Liability, Fair Value, Gross Liability	(5,792,000)		(24,338,000)
Derivative, Fair Value, Net	(2,864,000)		(36,593,000)
Not Designated as Hedging Instrument [Member] | Natural Gas Distribution [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Gross Asset	0		0
Derivative Liability, Fair Value, Gross Liability	(14,990,000)		(59,874,000)
Derivative, Fair Value, Net	(14,990,000)		(59,874,000)
Accounts Receivable [Member] | Designated as Hedging Instrument [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Gross Asset	76,354,000		73,636,000
Derivative Liability, Fair Value, Gross Asset	(33,476,000)		(48,174,000)
Accounts Receivable [Member] | Designated as Hedging Instrument [Member] | Oil and Gas Operations [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Gross Asset	76,354,000		73,636,000
Derivative Liability, Fair Value, Gross Asset	(33,476,000)	[1]	(48,174,000)	[1]
Accounts Receivable [Member] | Designated as Hedging Instrument [Member] | Natural Gas Distribution [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Gross Asset	0		0
Derivative Liability, Fair Value, Gross Asset	0		0
Accounts Receivable [Member] | Not Designated as Hedging Instrument [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Gross Asset	(6,603,000)		(3,670,000)
Accounts Receivable [Member] | Not Designated as Hedging Instrument [Member] | Oil and Gas Operations [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Gross Asset	(6,603,000)	[1]	(3,670,000)	[1]
Accounts Receivable [Member] | Not Designated as Hedging Instrument [Member] | Natural Gas Distribution [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Gross Asset	0		0
Other Assets [Member] | Designated as Hedging Instrument [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Gross Asset	51,181,000		75,982,000
Derivative Liability, Fair Value, Gross Asset	(17,575,000)		(36,341,000)
Other Assets [Member] | Designated as Hedging Instrument [Member] | Oil and Gas Operations [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Gross Asset	51,181,000		75,982,000
Derivative Liability, Fair Value, Gross Asset	(17,575,000)	[1]	(36,341,000)	[1]
Other Assets [Member] | Designated as Hedging Instrument [Member] | Natural Gas Distribution [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Gross Asset	0		0
Derivative Liability, Fair Value, Gross Asset	0		0
Other Assets [Member] | Not Designated as Hedging Instrument [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Gross Asset	9,531,000		(8,585,000)
Other Assets [Member] | Not Designated as Hedging Instrument [Member] | Oil and Gas Operations [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Gross Asset	9,531,000		(8,585,000)	[1]
Other Assets [Member] | Not Designated as Hedging Instrument [Member] | Natural Gas Distribution [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Gross Asset	0		0
Accounts Payable [Member] | Designated as Hedging Instrument [Member]
Derivative [Line Items]
Derivative Liability, Fair Value, Gross Liability	(12,471,000)		(37,070,000)
Accounts Payable [Member] | Designated as Hedging Instrument [Member] | Oil and Gas Operations [Member]
Derivative [Line Items]
Derivative Liability, Fair Value, Gross Liability	(12,471,000)		(37,070,000)
Accounts Payable [Member] | Designated as Hedging Instrument [Member] | Natural Gas Distribution [Member]
Derivative [Line Items]
Derivative Liability, Fair Value, Gross Liability	0		0
Accounts Payable [Member] | Not Designated as Hedging Instrument [Member]
Derivative [Line Items]
Derivative Liability, Fair Value, Gross Liability	(19,466,000)		(70,220,000)
Accounts Payable [Member] | Not Designated as Hedging Instrument [Member] | Oil and Gas Operations [Member]
Derivative [Line Items]
Derivative Liability, Fair Value, Gross Liability	(4,476,000)		(13,416,000)
Accounts Payable [Member] | Not Designated as Hedging Instrument [Member] | Natural Gas Distribution [Member]
Derivative [Line Items]
Derivative Liability, Fair Value, Gross Liability	(14,990,000)		(56,804,000)
Other Liabilities [Member] | Designated as Hedging Instrument [Member]
Derivative [Line Items]
Derivative Liability, Fair Value, Gross Liability	(7,739,000)		(20,386,000)
Other Liabilities [Member] | Designated as Hedging Instrument [Member] | Oil and Gas Operations [Member]
Derivative [Line Items]
Derivative Liability, Fair Value, Gross Liability	(7,739,000)		(20,386,000)
Other Liabilities [Member] | Designated as Hedging Instrument [Member] | Natural Gas Distribution [Member]
Derivative [Line Items]
Derivative Liability, Fair Value, Gross Liability	0		0
Other Liabilities [Member] | Not Designated as Hedging Instrument [Member]
Derivative [Line Items]
Derivative Liability, Fair Value, Gross Liability	(1,316,000)		(13,992,000)
Other Liabilities [Member] | Not Designated as Hedging Instrument [Member] | Oil and Gas Operations [Member]
Derivative [Line Items]
Derivative Liability, Fair Value, Gross Liability	(1,316,000)		(10,922,000)
Other Liabilities [Member] | Not Designated as Hedging Instrument [Member] | Natural Gas Distribution [Member]
Derivative [Line Items]
Derivative Liability, Fair Value, Gross Liability	0		(3,070,000)
Cash Flow Hedging [Member] | Macquarie Bank Limited [Member]
Derivative [Line Items]
Derivative Assets	16,800,000
Cash Flow Hedging [Member] | J Aron and Company [Member]
Derivative [Line Items]
Derivative Assets	9,700,000
Cash Flow Hedging [Member] | Citibank, N.A. [Member]
Derivative [Line Items]
Derivative Assets	7,700,000
Cash Flow Hedging [Member] | Shell Energy North America US, L.P. [Member]
Derivative [Line Items]
Derivative Assets	8,500,000
Cash Flow Hedging [Member] | BP Corporation North America Inc. [Member]
Derivative [Line Items]
Derivative Assets	9,600,000
Cash Flow Hedging [Member] | Morgan Stanley Capital Group, Inc. [Member]
Derivative [Line Items]
Derivative Liabilities	$ 24,300,000

[1] Amounts classified in accordance with accounting guidance which permits offsetting fair value amounts recognized for multiple derivative instruments executed with the same counterparty under a master netting arrangement.

XML

Segment Information (Tables)

9 Months Ended

Sep. 30, 2012

Segment Reporting [Abstract]

Schedule of Segment Reporting Information, by Segment

	Three months ended						Nine months ended
	September 30,						September 30,
(in thousands)	2012			2011			2012			2011
Operating revenues
Oil and gas operations	$	233,515		$	318,952		$	856,940		$	779,834
Natural gas distribution	61,809			59,616			327,183			415,497
Total	$	295,324		$	378,568		$	1,184,123		$	1,195,331
Operating income (loss)
Oil and gas operations	$	32,407		$	161,331		$	274,818		$	351,808
Natural gas distribution	(12,743		)	(10,681		)	70,265			65,541
Eliminations and corporate expenses	(206		)	(238		)	(857		)	(721		)
Total	$	19,458		$	150,412		$	344,226		$	416,628
Other income (expense)
Oil and gas operations	$	(12,633	)	$	(9,363	)	$	(35,195	)	$	(20,632	)
Natural gas distribution	(3,274		)	(4,162		)	(10,062		)	(10,115		)
Eliminations and other	148			94			234			182
Total	$	(15,759	)	$	(13,431	)	$	(45,023	)	$	(30,565	)
Income before income taxes	$	3,699		$	136,981		$	299,203		$	386,063

(in thousands)	September 30, 2012		December 31, 2011
Identifiable assets
Oil and gas operations	$	4,734,269	$	4,046,242
Natural gas distribution	1,120,161		1,163,959
Eliminations and other	65,399		27,215
Total	$	5,919,829	$	5,237,416

XML

Asset Retirement Obligations (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2012	Sep. 30, 2011	Sep. 30, 2012	Sep. 30, 2011	Dec. 31, 2011
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Balance of ARO, beginning			$ 107,340
Liabilities incurred			2,946
Liabilities settled			(676)
Accretion expense	1,907	1,728	5,581	5,066
Balance of ARO, end	115,191		115,191
Regulatory Assets, Noncurrent	94,869		94,869		95,633
Regulatory Liability, Current	27,372		27,372		58,279
Regulatory Liability, Noncurrent	77,692		77,692		87,234
Alabama Gas Corporation
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Balance of ARO, beginning					20,800
Balance of ARO, end	21,500		21,500		20,800
Regulatory Assets, Noncurrent	94,869		94,869		95,633
Regulatory Liability, Current	27,372		27,372		58,279
Regulatory Liability, Noncurrent	77,692		77,692		87,234
Asset removal costs | Alabama Gas Corporation
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Regulatory Assets, Noncurrent					1,000
Refundable negative salvage
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Regulatory Liability, Current	18,400		18,400		20,300
Regulatory Liability, Noncurrent	55,400		55,400		65,600
Refundable negative salvage | Alabama Gas Corporation
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Regulatory Liability, Current	18,353		18,353		20,269
Regulatory Liability, Noncurrent	$ 55,389		$ 55,389		$ 65,646

XML

Stock Compensation (Details) (USD $) In Thousands, except Share data, unless otherwise specified	3 Months Ended			9 Months Ended	3 Months Ended	9 Months Ended	3 Months Ended	9 Months Ended	3 Months Ended	9 Months Ended
	Sep. 30, 2012 Stock Incentive Plan	Mar. 31, 2012 Stock Incentive Plan	Sep. 30, 2012 Deferred Compensation Plan	Sep. 30, 2012 Deferred Compensation Plan	Sep. 30, 2012 Petrotech Incentive Plan [Member] Restricted Stock Units (RSUs) [Member] Vesting Period, Three Years [Member]	Sep. 30, 2012 Petrotech Incentive Plan [Member] Restricted Stock Units (RSUs) [Member] Vesting Period, Three Years [Member]	Sep. 30, 2012 Petrotech Incentive Plan [Member] Restricted Stock Units (RSUs) [Member] Vesting Period, Two Years [Member]	Sep. 30, 2012 Petrotech Incentive Plan [Member] Restricted Stock Units (RSUs) [Member] Vesting Period, Two Years [Member]	Sep. 30, 2012 Petrotech Incentive Plan [Member] Restricted Stock Units (RSUs) [Member] Vesting Period, 18 Months [Member]	Sep. 30, 2012 Petrotech Incentive Plan [Member] Restricted Stock Units (RSUs) [Member] Vesting Period, 18 Months [Member]
Share-based Compensation Arrangement by Share-based Payment Award
Award Vesting Period	3 years					3 years		2 years		18 months
Award Expiration Period	10 years
Grants in Period, Options, Fair Value		$ 18.79
Grants in Period, Options		371,040
Grants in Period, Other than Options						102,349		3,768		40,822
Grants in Period, Other than Options, Fair Value					$ 51.17		$ 51.72		$ 51.99
Noncash Payments for Repurchase of Common Stock			$ 111	$ 229

XML

Derivative Commodity Instruments - Derivative Instruments Change in Fair Value (Details) (Derivative Commodity Instruments, USD $)	3 Months Ended		9 Months Ended
	Sep. 30, 2012	Sep. 30, 2011	Sep. 30, 2012	Sep. 30, 2011
Derivative Commodity Instruments
Fair Value, Assets and Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Balance at beginning of period	$ 103,456,000	$ 13,446,000	$ 65,801,000	$ 42,755,000
Realized losses	18,737,000	9,370,000	51,858,000	37,031,000
Unrealized gains (losses) relating to instruments held at the reporting date	(46,983,000)	23,953,000	(9,328,000)	(5,356,000)
Settlements during period	(17,929,000)	(10,565,000)	(51,050,000)	(38,226,000)
Balance at end of period	57,281,000	36,204,000	57,281,000	36,204,000
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset and Liability, Mark-toMarket Gain (Loss) Included in Earnings, Unrealized	7,900,000		4,500,000
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset and Liability, Mark-toMarket Gain Included in Earnings, Unrealized		$ 100,000		$ 100,000

XML

Commitments and Contingencies (Details) - Lease Obligations (USD $) In Thousands, unless otherwise specified	3 Months Ended
	Sep. 30, 2012
Capital Leases, Future Minimum Payments Due [Abstract]
2012	$ 436
2013	1,743
2014	1,743
2015	145
Total minimum lease payments	4,067
Less amount representing interest	93
Total present value of minimum lease payments	$ 3,974

XML

Regulatory Matters

9 Months Ended

Sep. 30, 2012

Regulated Operations [Abstract]

Regulatory Matters

REGULATORY MATTERS

Alagasco is subject to regulation by the Alabama Public Service Commission (APSC) which established the Rate Stabilization and Equalization (RSE) rate-setting process in 1983. RSE’s current extension is for a seven-year period through December 31, 2014. RSE will continue after December 31, 2014, unless, after notice to the Company and a hearing, the APSC votes to modify or discontinue the RSE methodology.

Alagasco's allowed range of return on average common equity is 13.15 percent to 13.65 percent throughout the term of the RSE order. Under RSE, the APSC conducts quarterly reviews to determine whether Alagasco's return on average common equity at the end of the rate year will be within the allowed range of return. Reductions in rates can be made quarterly to bring the projected return within the allowed range; increases, however, are allowed only once each rate year, effective December 1, and cannot exceed 4 percent of prior-year revenues. During the three months and nine months ended September 30, 2012, Alagasco had a net $1.3 million pre-tax and a net $6.3 million pre-tax, respectively, reduction in revenues to bring the return on average common equity to midpoint within the allowed range of return. During the three months and nine months ended September 30, 2011, Alagasco had a net $1.2 million pre-tax and a net $6.7 million pre-tax, respectively, reduction in revenues to bring the return on average common equity to midpoint within the allowed range of return. Under the provisions of RSE, a $13.0 million annual increase and a $1.3 million annual decrease in revenues became effective December 1, 2011 and 2010, respectively.

RSE limits the utility’s equity upon which a return is permitted to 55 percent of total capitalization, subject to certain adjustments. Under the inflation-based Cost Control Measurement (CCM) established by the APSC, if the percentage change in operations and maintenance (O&M) expense on an aggregate basis falls within a range of 0.75 points above or below the percentage change in the Consumer Price Index For All Urban Consumers (Index Range), no adjustment is required. If the change in O&M expense on an aggregate basis exceeds the Index Range, three-quarters of the difference is returned to customers. To the extent the change is less than the Index Range, the utility benefits by one-half of the difference through future rate adjustments. The O&M expense base for measurement purposes will be set at the prior year’s actual O&M expense amount unless the Company exceeds the top of the Index Range in two successive years, in which case the base for the following year will be set at the top of the Index Range. Certain items that fluctuate based on situations demonstrated to be beyond Alagasco’s control may be excluded from the CCM calculation. Alagasco’s O&M expense fell within the Index Range for the rate years ended September 30, 2012 and 2011.

Alagasco’s rate schedules for natural gas distribution charges contain a Gas Supply Adjustment (GSA) rider, established in 1993, which permits the pass-through to customers of changes in the cost of gas supply. Alagasco's tariff provides a temperature adjustment mechanism, also included in the GSA, that is designed to moderate the impact of departures from normal temperatures on Alagasco’s earnings. The temperature adjustment applies primarily to residential, small commercial and small industrial customers. Other non-temperature weather related conditions that may affect customer usage are not included in the temperature adjustment.

The APSC approved an Enhanced Stability Reserve (ESR) in 1998, which was subsequently modified and expanded in 2010. As currently approved, the ESR provides deferred treatment and recovery for the following: (1) extraordinary O&M expenses related to environmental response costs; (2) extraordinary O&M expenses related to self insurance costs that exceed $1 million per occurrence; (3) extraordinary O&M expenses, other than environmental response costs and self insurance costs, resulting from a single force majeure event or multiple force majeure events greater than $275,000 and $412,500, respectively, during a rate year; and (4) negative individual large commercial and industrial customer budget revenue variances that exceed $350,000 during a rate year.

Charges to the ESR are subject to certain limitations which may disallow deferred treatment and which proscribe the timing of recovery. Funding to the ESR is provided as a reduction to the refundable negative salvage balance over its nine year term beginning December 1, 2010. Subsequent to the nine year period and subject to APSC authorization, Alagasco anticipates recovering underfunded ESR balances over a five year amortization period with an annual limitation of $660,000. Amounts in excess of this limitation are deferred for recovery in future years.

XML

Employee Benefit Plans (Details) (USD $)	3 Months Ended		9 Months Ended
	Sep. 30, 2012	Sep. 30, 2011	Sep. 30, 2012	Sep. 30, 2011
Pension Plans
Components of net periodic benefit cost:
Service cost	$ 2,632,000	$ 2,293,000	$ 7,895,000	$ 6,879,000
Interest cost	2,700,000	2,740,000	8,101,000	8,220,000
Expected long-term return on assets	(3,563,000)	(3,868,000)	(10,689,000)	(11,603,000)
Actuarial loss	2,099,000	1,609,000	6,297,000	4,826,000
Prior service cost amortization	129,000	124,000	388,000	372,000
Net periodic expense	3,997,000	2,898,000	11,992,000	8,694,000
Estimated Future Employer Contributions in Current Fiscal Year	12,800,000		12,800,000
Benefit Payments Made in Current Fiscal Year	36,000		2,300,000
Estimated Future Benefit Payments in Current Fiscal Year			36,000
Postretirement Benefit Plans
Components of net periodic benefit cost:
Service cost	463,000	442,000	1,390,000	1,327,000
Interest cost	1,062,000	1,111,000	3,186,000	3,332,000
Expected long-term return on assets	(1,109,000)	(1,104,000)	(3,328,000)	(3,314,000)
Actuarial loss	9,000	0	27,000	0
Transition amortization	479,000	479,000	1,438,000	1,438,000
Net periodic expense	904,000	928,000	2,713,000	2,783,000
Estimated Future Employer Contributions in Current Fiscal Year	900,000		900,000
Contributions by Employer in Current Fiscal Year	900,000		2,700,000
Maximum [Member] | Pension Plans
Components of net periodic benefit cost:
Estimated Future Employer Contributions in Current Fiscal Year	$ 2,100,000		$ 2,100,000

XML

Regulatory Assets and Liabilities (Tables) (Alabama Gas Corporation [Member])

9 Months Ended

Sep. 30, 2012

Alabama Gas Corporation [Member]

Regulatory Assets and Liabilities [Line Items]

Schedule of Regulatory Assets and Liabilities [Table Text Block]

The following table details regulatory assets and liabilities on the balance sheets:

(in thousands)	September 30, 2012				December 31, 2011
	Current		Noncurrent		Current		Noncurrent
Regulatory assets:
Pension and postretirement assets	$	170	$	79,984	$	170	$	77,587
Accretion and depreciation for asset retirement obligation	—		14,885		—		13,981
Risk management activities	14,990		—		56,804		3,070
Asset removal costs, net	—		—		—		994
Gas supply adjustment	40,998		—		—		—
Other	30		—		169		1
Total regulatory assets	$	56,188	$	94,869	$	57,143	$	95,633
Regulatory liabilities:
RSE adjustment	$	3,187	$	—	$	2,931	$	—
Unbilled service margin	5,799		—		22,419		—
Gas supply adjustment	—		—		12,626		—
Refundable negative salvage	18,353		55,389		20,269		65,646
Asset retirement obligation	—		21,525		—		20,785
Other	33		778		34		803
Total regulatory liabilities	$	27,372	$	77,692	$	58,279	$	87,234

XML

Financial Instruments (Tables)

9 Months Ended

Sep. 30, 2012

Fair Value Disclosures [Abstract]

Allowance for Credit Losses on Financing Receivables [Table Text Block]

The following table sets forth a summary of changes in the allowance for credit losses as follows:

(in thousands)
Allowance for credit losses as of December 31, 2011	$	421
Provision	21
Allowance for credit losses as of September 30, 2012	$	442

XML

Commitments and Contingencies (Details) - Commitments and Agreements (USD $) In Millions, unless otherwise specified	9 Months Ended
	Sep. 30, 2012 agreements
Long-term Purchase Commitment [Line Items]
Drilling Plans, Agreement to Secure Drilling Rigs, Number of Agreements	3
Agreement Termination
Long-term Purchase Commitment [Line Items]
Loss Contingency, Range of Possible Loss, Maximum	24
Pending or threatened legal proceedings
Long-term Purchase Commitment [Line Items]
Loss Contingency Accrual, Carrying Value, Period Increase (Decrease)	1.4
Alabama Gas Corporation
Long-term Purchase Commitment [Line Items]
Chain of Title, Manufactured Gas Plant Sites	9
Chain of Title, Manufactured Gas Distribution Sites	5
Crude Oil [Member]
Long-term Purchase Commitment [Line Items]
Oil and Gas Delivery Commitments and Contracts, Remaining Contractual Volume	33.4
Natural Gas | Alabama Gas Corporation
Long-term Purchase Commitment [Line Items]
Long-term Purchase Commitment, Time Period	August 2020
Long-term Purchase Commitment, Minimum Quantity Required	177
Recorded Unconditional Purchase Obligation, Time Period	March 2013
Recorded Unconditional Purchase Obligation	0.8
Recorded Unconditional Purchase Obligation, Market Value	0.8
Natural Gas, Delivery and Storage | Alabama Gas Corporation
Long-term Purchase Commitment [Line Items]
Long-term Purchase Commitment, Amount	74
Long-term Purchase Commitment, Time Period	September 2024
Long Term Commitments Expense Recognized in Statements of Operations	36.8
Wholly Owned Properties [Member] | Alabama Gas Corporation
Long-term Purchase Commitment [Line Items]
Chain of Title, Manufactured Gas Plant Sites	4
Chain of Title, Manufactured Gas Distribution Sites	1

XML

Asset Retirement Obligations (Tables)

9 Months Ended

Sep. 30, 2012

Asset Retirement Obligation Disclosure [Abstract]

Schedule of Change in Asset Retirement Obligation

During the nine months ended September 30, 2012, Energen Resources recognized amounts representing expected future costs associated with site reclamation, facilities dismantlement, and plug and abandonment of wells as follows:

(in thousands)
Balance of ARO as of December 31, 2011	$	107,340
Liabilities incurred	2,946
Liabilities settled	(676		)
Accretion expense	5,581
Balance of ARO as of September 30, 2012	$	115,191

XML

Acquisition and Dispositions of Oil and Gas Properties (Tables)

9 Months Ended

Sep. 30, 2012

Oil and Gas Exploration and Production Industries Disclosures [Abstract]

Schedule of Recognized Identified Assets Acquired and Liabilities Assumed

The following table summarizes the consideration paid and the amounts of the assets acquired and liabilities assumed recognized as of November 16, 2011, (including the effects of closing adjustments).

(in thousands)
Consideration given
Cash (net)	$	161,967
Recognized amounts of identifiable assets acquired and liabilities assumed
Proved properties	$	151,544
Unproved leasehold properties	7,883
Accounts receivable	3,070
Accounts payable	(388		)
Asset retirement obligation	(142		)
Total identifiable net assets	$	161,967

The following table summarizes the consideration paid and the amounts of the assets acquired and liabilities assumed recognized as of December 27, 2011. The purchase price allocation is preliminary and subject to adjustment as the final closing statement is not complete.

(in thousands)
Consideration given
Cash (net)	$	59,997
Recognized amounts of identifiable assets acquired and liabilities assumed
Proved properties	$	36,048
Unproved leasehold properties	23,686
Accounts receivable	680
Accounts payable	(244		)
Asset retirement obligation	(173		)
Total identifiable net assets	$	59,997

The following table summarizes the consideration paid and the amounts of the assets acquired and liabilities assumed recognized as of February 14, 2012 (including the effects of closing adjustments).

(in thousands)
Consideration given
Cash (net)	$	67,615
Recognized amounts of identifiable assets acquired and liabilities assumed
Proved properties	$	65,581
Unproved leasehold properties	911
Accounts receivable	1,358
Accounts payable	(25		)
Asset retirement obligation	(210		)
Total identifiable net assets	$	67,615

XML

Basis of Presentation

9 Months Ended

Sep. 30, 2012

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Basis of Presentation

BASIS OF PRESENTATION

The unaudited condensed financial statements and notes should be read in conjunction with the financial statements and notes thereto for the years ended December 31, 2011, 2010 and 2009, included in the 2011 Annual Report of Energen Corporation (the Company) and Alabama Gas Corporation (Alagasco) on Form 10-K. Alagasco has a September 30 fiscal year for rate-setting purposes (rate year) and reports on a calendar year for the Securities and Exchange Commission and all other financial accounting reporting purposes. The accompanying unaudited condensed financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America for interim financial information and with the instructions to Form 10-Q and Rule 10-01 of Regulation S-X. Accordingly, they do not include all of the disclosures required for complete financial statements. The Company's natural gas distribution business is seasonal in character and influenced by weather conditions. Results of operations for interim periods are not necessarily indicative of the results that may be expected for the year. All adjustments to the unaudited condensed financial statements that are, in the opinion of management, necessary for a fair statement of the results for the interim periods have been recorded. Such adjustments consist of normal recurring items. Certain reclassifications were made to conform prior year's financial statements to the current-quarter presentation.

XML

Regulatory Matters (Details) (Alabama Gas Corporation, USD $)	1 Months Ended		3 Months Ended		9 Months Ended		12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Sep. 30, 2012	Sep. 30, 2011	Sep. 30, 2012	Sep. 30, 2011	Jun. 30, 2011
Regulatory Matters [Line Items]
Enahanced Stability Reserve Extension Period					7 years
Revenue Impact of Rate Adjustments	$ 13,000,000	$ (1,300,000)	$ (1,300,000)	$ (1,200,000)	$ (6,300,000)	$ (6,700,000)
Adjustment Requirement Threshold for Return on Equity as Percentage of Operations and Maintenance Expenses to Consumer Price Index			0.75
Amortization Expense, Enhanced Stability Reserve, Annual Amount					660,000
Enahanced Stability Reserve Amortization Period							5 years
Enhanced Stability Reserve Refund Period							9 years
Return on Equity, Adjustment Requirements, Description					RSE limits the utility’s equity upon which a return is permitted to 55 percent of total capitalization, subject to certain adjustments. Under the inflation-based Cost Control Measurement (CCM) established by the APSC, if the percentage change in operations and maintenance (O&M) expense on an aggregate basis falls within a range of 0.75 points above or below the percentage change in the Consumer Price Index For All Urban Consumers (Index Range), no adjustment is required. If the change in O&M expense on an aggregate basis exceeds the Index Range, three-quarters of the difference is returned to customers. To the extent the change is less than the Index Range, the utility benefits by one-half of the difference through future rate adjustments. The O&M expense base for measurement purposes will be set at the prior year’s actual O&M expense amount unless the Company exceeds the top of the Index Range in two successive years, in which case the base for the following year will be set at the top of the Index Range.
Minimum
Regulatory Matters [Line Items]
Allowed Return on Average Common Equity			13.15%
Maximum
Regulatory Matters [Line Items]
Allowed Return on Average Common Equity			13.65%
Rate Increases as Percentage of Prior Year Revenues			4.00%
Limitation on Return on Equity as Percentage of Total Capitalization			55.00%
APSC Approved Expension of ESR, November 1, 2010
Regulatory Matters [Line Items]
Negative Revenue Variance, Large Commercial and Industrial Customer Budget, Minimum Amount, Charged to Enhanced Stability Reserve					350,000
APSC Approved Expension of ESR, November 1, 2010 | Force Majeure Event Costs
Regulatory Matters [Line Items]
Extraordinary Operating and Maintenance Expenses, Minimum Amount, Charged to Enhanced Stability Reserve					275,000
APSC Approved Expension of ESR, November 1, 2010 | Force Majeure Events Costs
Regulatory Matters [Line Items]
Extraordinary Operating and Maintenance Expenses, Minimum Amount, Charged to Enhanced Stability Reserve					412,500
APSC Approved Expension of ESR, November 1, 2010 | Environmental Response and Self Insurance Costs
Regulatory Matters [Line Items]
Extraordinary Operating and Maintenance Expenses, Minimum Amount, Charged to Enhanced Stability Reserve			$ 1,000,000

XML

Reconciliation of Earnings Per Share (Details) - Antidilutive Securities (Stock options)	3 Months Ended		9 Months Ended
	Sep. 30, 2012	Sep. 30, 2011	Sep. 30, 2012	Sep. 30, 2011
Stock options
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Antidilutive Securities Excluded from Computation of Earnings Per Share (in options or shares)	849,583	293,978	849,583	293,978

XML

Consolidated Condensed Statements of Income (USD $) In Thousands, except Per Share data, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2012	Sep. 30, 2011	Sep. 30, 2012	Sep. 30, 2011
Operating Revenues
Oil and gas operations	$ 233,515	$ 318,952	$ 856,940	$ 779,834
Natural gas distribution	61,809	59,616	327,183	415,497
Total operating revenues	295,324	378,568	1,184,123	1,195,331
Operating Expenses
Cost of gas	20,924	21,748	94,179	185,916
Operations and maintenance	128,587	111,749	351,861	318,763
Depreciation, depletion and amortization	104,338	72,802	300,863	199,559
Income taxes
Deferred			80,724	120,656
Asset impairment	0	0	21,545	0
Taxes, other than income taxes	20,110	20,129	65,868	69,399
Accretion expense	1,907	1,728	5,581	5,066
Total operating expenses	275,866	228,156	839,897	778,703
Operating Income	19,458	150,412	344,226	416,628
Other Income (Expense)
Interest expense	(17,198)	(11,976)	(48,458)	(30,843)
Other income	1,523	619	3,740	1,727
Other expense	(84)	(2,074)	(305)	(1,449)
Total other expense	(15,759)	(13,431)	(45,023)	(30,565)
Interest Charges
Income Before Income Taxes	3,699	136,981	299,203	386,063
Income tax expense	1,653	49,382	108,464	140,871
Net Income	2,046	87,599	190,739	245,192
Diluted Earnings Per Average Common Share	$ 0.03	$ 1.21	$ 2.64	$ 3.39
Basic Earnings Per Average Common Share	$ 0.03	$ 1.22	$ 2.64	$ 3.40
Dividends Per Common Share	$ 0.140	$ 0.135	$ 0.420	$ 0.405
Diluted Average Common Shares Outstanding	72,316	72,375	72,301	72,409
Basic Average Common Shares Outstanding	72,130	72,068	72,121	72,045
Alabama Gas Corporation
Operating Revenues
Natural gas distribution	61,809	59,616	327,183	415,497
Operating Expenses
Cost of gas	20,924	21,748	94,179	185,916
Operations and maintenance	37,235	33,001	107,470	106,535
Depreciation, depletion and amortization	10,572	9,980	31,551	29,606
Income taxes
Current	(9,242)	(9,414)	13,567	3,456
Deferred	3,264	3,664	9,431	16,626
Taxes, other than income taxes	5,821	5,568	23,718	27,899
Total operating expenses	68,574	64,547	279,916	370,038
Operating Income	(6,765)	(4,931)	47,267	45,459
Other Income (Expense)
Interest expense	(4,164)	(3,835)	(12,185)	(10,988)
Allowance for funds used during construction	187	260	452	652
Other income	787	326	1,925	941
Other expense	(84)	(913)	(254)	(720)
Total other expense	890	(327)	2,123	873
Interest Charges
Interest on long-term debt	3,423	3,025	10,270	9,106
Other interest expense	741	810	1,915	1,882
Net Income	$ (10,039)	$ (9,093)	$ 37,205	$ 35,344

XML

Commitments and Contingencies (Details) - Environmental Matters (Alabama Gas Corporation, USD $) In Millions, unless otherwise specified	9 Months Ended
	Sep. 30, 2012
Site Contingency [Line Items]
Environmental Remediation Estimated Cost	$ 5.0
Enhanced Stability Reserve [Member]
Site Contingency [Line Items]
Regulatory Assets	$ 4.8

XML

Consolidated Condensed Balance Sheets (Parenthetical) (USD $) In Thousands, except Share data, unless otherwise specified	Sep. 30, 2012	Dec. 31, 2011
Current Assets
Allowance for doubtful accounts	$ 6,649	$ 12,946
Shareholders' Equity
Preferred stock, par value	$ 0.01	$ 0.01
Preferred stock, shares authorized	5,000,000	5,000,000
Common stock, par value	$ 0.01	$ 0.01
Common stock, shares authorized	150,000,000	150,000,000
Common stock, shares issued	75,062,599	75,007,412
Treasury stock, shares	3,031,622	3,036,549
Alabama Gas Corporation
Current Assets
Allowance for doubtful accounts	$ 5,800	$ 12,100
Shareholders' Equity
Preferred stock, par value	$ 0.01	$ 0.01
Preferred stock, shares authorized	120,000	120,000
Common stock, par value	$ 0.01	$ 0.01
Common stock, shares authorized	3,000,000	3,000,000
Common stock, shares issued	1,972,052	1,972,052

XML

Derivative Commodity Instruments - Hedging Transactions (Details) (Cash Flow Hedging [Member])	Sep. 30, 2012 Bcf
Natural Gas [Member] | 2012 | NYMEX Swaps [Member]
Derivative [Line Items]
Total Hedged Volumes	3.6
Average Contract Price, per Mcf	4.49
Natural Gas [Member] | 2012 | Basin Specific Swaps - San Juan [Member]
Derivative [Line Items]
Total Hedged Volumes	8.9
Average Contract Price, per Mcf	4.14
Natural Gas [Member] | 2012 | Basin Specific Swaps - Permain [Member]
Derivative [Line Items]
Total Hedged Volumes	2.0
Average Contract Price, per Mcf	2.89
Natural Gas [Member] | 2012 | San Juan Basis Swaps [Member]
Derivative [Line Items]
Total Hedged Volumes	0.1
Average Contract Price, per Mcf	(0.23)
Natural Gas [Member] | 2013 | NYMEX Swaps [Member]
Derivative [Line Items]
Total Hedged Volumes	12.7
Average Contract Price, per Mcf	4.82
Natural Gas [Member] | 2013 | Basin Specific Swaps - San Juan [Member]
Derivative [Line Items]
Total Hedged Volumes	32.8
Average Contract Price, per Mcf	4.56
Natural Gas [Member] | 2013 | Basin Specific Swaps - Permain [Member]
Derivative [Line Items]
Total Hedged Volumes	4.6
Average Contract Price, per Mcf	3.45
Natural Gas [Member] | 2014 | NYMEX Swaps [Member]
Derivative [Line Items]
Total Hedged Volumes	10.6
Average Contract Price, per Mcf	4.55
Natural Gas [Member] | 2014 | Basin Specific Swaps - San Juan [Member]
Derivative [Line Items]
Total Hedged Volumes	25.7
Average Contract Price, per Mcf	4.72
Natural Gas [Member] | 2014 | Basin Specific Swaps - Permain [Member]
Derivative [Line Items]
Total Hedged Volumes	9.7
Average Contract Price, per Mcf	3.81
Crude Oil [Member] | 2012 | NYMEX Swaps [Member]
Derivative [Line Items]
Total Hedged Volumes	1,850
Average Contract Price, per Bbl	88.51
Crude Oil [Member] | 2012 | WTS/WTI Basis Swap [Member]
Derivative [Line Items]
Total Hedged Volumes	752
Average Contract Price, per Bbl	(2.95)
Crude Oil [Member] | 2013 | NYMEX Swaps [Member]
Derivative [Line Items]
Total Hedged Volumes	8,858
Average Contract Price, per Bbl	90.95
Crude Oil [Member] | 2013 | WTS/WTI Basis Swap [Member]
Derivative [Line Items]
Total Hedged Volumes	3,592
Average Contract Price, per Bbl	(3.03)
Crude Oil [Member] | 2013 | WTI/WTI Basis Swaps [Member]
Derivative [Line Items]
Total Hedged Volumes	1,740
Average Contract Price, per Bbl	(1.13)
Crude Oil [Member] | 2014 | NYMEX Swaps [Member]
Derivative [Line Items]
Total Hedged Volumes	9,796
Average Contract Price, per Bbl	92.64
Natural Gas Liquids [Member] | 2012 | Liquids Swaps [Member]
Derivative [Line Items]
Total Hedged Volumes	15.3
Average Contract Price, Per Gal	0.99
Natural Gas Liquids [Member] | 2013 | Liquids Swaps [Member]
Derivative [Line Items]
Total Hedged Volumes	44.5
Average Contract Price, Per Gal	1.02
Alabama Gas Corporation [Member] | Natural Gas [Member] | 2012 | NYMEX Swaps [Member]
Derivative [Line Items]
Total Hedged Volumes	4.6
Alabama Gas Corporation [Member] | Natural Gas [Member] | 2013 | NYMEX Swaps [Member]
Derivative [Line Items]
Total Hedged Volumes	1.5

XML

Recently Issued Accounting Standards Recently Issued Accounting Standards (Policies)

9 Months Ended

Sep. 30, 2012

New Accounting Pronouncements and Changes in Accounting Principles [Abstract]

New Accounting Pronouncements, Policy [Policy Text Block]

In December 2011, the FASB issued Accounting Standard Update (ASU) No. 2011-11, Disclosures about Offsetting Assets and Liabilities. The amendments in this update require an entity to disclose information about offsetting and related arrangements to enable users of its financial statements to understand the effect of those arrangements on its financial position. The amendment is effective for annual reporting periods beginning on or after January 1, 2013, and interim periods within those annual periods. The Company is currently evaluating the impact of the ASU but does not expect this update to have a material impact on its results of operations.

In June 2011, the FASB issued ASU No. 2011-05, Presentation of Comprehensive Income. This update requires entities to present the components of net income and other comprehensive income either in a single continuous statement of comprehensive income or in two separate but consecutive statements. The amendments in this update do not change the items that must be reported in other comprehensive income or when an item of other comprehensive income must be reclassified to net income. In December 2011, the FASB issued ASU No. 2011-12, Deferral of the Effective Date for Amendments to the Presentation of Reclassifications of Items Out of Accumulated Other Comprehensive Income in Accounting Standards Update No. 2011-05, which indefinitely deferred the requirements to include reclassification adjustments for items that are reclassified from other comprehensive income to net income on the face of the financial statements. The amendments in these updates are effective for fiscal years, and interim periods within those years, beginning after December 15, 2011. Adoption of these updates has not had a material impact on the consolidated condensed financial statements or results of operations.

In May 2011, the FASB issued ASU No. 2011-04, Amendments to Achieve Common Fair Value Measurement and Disclosure Requirement in U.S. GAAP and International Financial Reporting Standards (IFRSs). The amendments in this update result in common fair value measurement and disclosure requirements in U.S. GAAP and IFRSs. The amendments are effective during interim and annual periods beginning after December 15, 2011. This standard did not have a material impact on the consolidated condensed financial statements of the Company. The additional fair value disclosures are included in Note 3, Derivative Commodity Instruments.

XML

Derivative Commodity Instruments - Derivatives Measured at Fair Value on a Recurring Basis (Details) (USD $)									3 Months Ended
	Sep. 30, 2012	Dec. 31, 2011	Sep. 30, 2012 Fair Value, Measurements, Recurring [Member]	Dec. 31, 2011 Fair Value, Measurements, Recurring [Member]	Sep. 30, 2012 Level 2 Fair Value, Measurements, Recurring [Member]		Dec. 31, 2011 Level 2 Fair Value, Measurements, Recurring [Member]		Sep. 30, 2012 Level 3	Sep. 30, 2012 Level 3 Fair Value, Measurements, Recurring [Member]		Dec. 31, 2011 Level 3 Fair Value, Measurements, Recurring [Member]		Sep. 30, 2012 Alabama Gas Corporation [Member]	Dec. 31, 2011 Alabama Gas Corporation [Member]	Sep. 30, 2012 Alabama Gas Corporation [Member] Level 2 Fair Value, Measurements, Recurring [Member]	Dec. 31, 2011 Alabama Gas Corporation [Member] Level 2 Fair Value, Measurements, Recurring [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Current assets			$ 36,275,000	$ 21,792,000	$ (1,048,000)	[1]	$ (14,843,000)			$ 37,323,000	[1]	$ 36,635,000
Noncurrent assets	43,137,000	31,056,000	43,137,000	31,056,000	18,133,000	[1]	(8,382,000)			25,004,000	[1]	39,438,000
Current liabilities			(31,937,000)	(107,290,000)	(30,588,000)	[1]	(98,468,000)			(1,349,000)	[1]	(8,822,000)				(15,000,000)	(56,800,000)
Noncurrent liabilities	(11,110,000)	(34,663,000)	(9,055,000)	(34,378,000)	(5,358,000)	[1]	(32,928,000)			(3,697,000)	[1]	(1,450,000)		0	(3,070,000)		(3,100,000)
Net derivative asset (liability)			38,420,000	(88,820,000)	(18,861,000)	[1]	(154,621,000)	[1]		57,281,000	[1]	65,801,000	[1]
Impact on fair value of a 10 percent increase or decrease in commodity prices									35,000,000
Impact on results of operations of a 10 percent increase or decrease in commodity prices									$ 5,900,000

[1] Amounts classified in accordance with accounting guidance which permits offsetting fair value amounts recognized for multiple derivative instruments executed with the same counterparty under a master netting arrangement.

XML

Reconciliation of Earnings Per Share (Tables)

9 Months Ended

Sep. 30, 2012

Earnings Per Share [Abstract]

Schedule of Earnings Per Share Reconciliation

	Three months ended					Three months ended
(in thousands, except per share amounts)	September 30, 2012					September 30, 2011
	Net			Per Share		Net			Per Share
	Income		Shares	Amount		Income		Shares	Amount
Basic EPS	$	2,046	72,130	$	0.03	$	87,599	72,068	$	1.22
Effect of dilutive securities
Stock options			183					298
Non-vested restricted stock			3					9
Diluted EPS	$	2,046	72,316	$	0.03	$	87,599	72,375	$	1.21

	Nine months ended					Nine months ended
(in thousands, except per share amounts)	September 30, 2012					September 30, 2011
	Net			Per Share		Net			Per Share
	Income		Shares	Amount		Income		Shares	Amount
Basic EPS	$	190,739	72,121	$	2.64	$	245,192	72,045	$	3.40
Effect of dilutive securities
Stock options			177					355
Non-vested restricted stock			3					9
Diluted EPS	$	190,739	72,301	$	2.64	$	245,192	72,409	$	3.39

XML

Consolidated Condensed Statements of Cash Flows (USD $) In Thousands, unless otherwise specified	9 Months Ended
	Sep. 30, 2012	Sep. 30, 2011
Operating Activities
Net Income	$ 190,739	$ 245,192
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization	300,863	199,559
Asset impairment	21,545	0
Accretion expense	5,581	5,066
Deferred income taxes	80,724	120,656
Bad debt expense	370	3,197
Exploratory expense	11,420	10,773
Change in derivative fair value	(23,933)	(59,581)
Gain on sale of assets	(420)	(5,991)
Other, net	17,047	5,913
Net change in:
Accounts receivable	46,798	48,585
Inventories	62	(15,493)
Accounts payable	(12,791)	(26,877)
Amounts due customers including gas supply pass-through	(52,466)	7,342
Income tax receivable	1,817	39,347
Pension and other postretirement benefit contributions	(5,056)	(5,025)
Other current assets and liabilities	20,819	21,286
Net cash provided by operating activities	603,119	593,949
Investing Activities
Additions to property, plant and equipment	(898,202)	(634,427)
Acquisitions, net of cash acquired	(104,200)	(106,578)
Proceeds from sale of assets	2,420	7,401
Other, net	(746)	(946)
Net cash used in investing activities	(1,000,728)	(734,550)
Financing Activities
Payment of dividends on common stock	(30,292)	(29,188)
Issuance of common stock	1,164	6,221
Issuance of long-term debt	0	399,952
Payment of long-term debt	(1,143)	(5,407)
Net change in short-term debt	465,000	(230,000)
Tax benefit on stock compensation	514	922
Other	(38)	(3,162)
Net cash provided by (used in) financing activities	435,205	139,338
Net change in cash and cash equivalents	37,596	(1,263)
Cash and cash equivalents at beginning of period	9,541	22,659
Cash and Cash Equivalents at End of Period	47,137	21,396
Alabama Gas Corporation
Operating Activities
Net Income	37,205	35,344
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization	31,551	29,606
Deferred income taxes	9,431	16,626
Bad debt expense	364	3,184
Other, net	4,681	227
Net change in:
Accounts receivable	29,539	41,085
Inventories	5,975	(6,173)
Accounts payable	(17,222)	(22,155)
Amounts due customers including gas supply pass-through	(52,466)	7,342
Income tax receivable	6,002	6,807
Pension and other postretirement benefit contributions	(2,044)	(2,108)
Other current assets and liabilities	(9,795)	(8,474)
Net cash provided by operating activities	43,221	101,311
Investing Activities
Additions to property, plant and equipment	(49,746)	(57,424)
Other, net	2,490	177
Net cash used in investing activities	(47,256)	(57,247)
Financing Activities
Payment of dividends on common stock	(28,182)	(29,183)
Payment of long-term debt	(143)	(5,407)
Net increases in advances from affiliates	24,867	370
Net change in short-term debt	10,000	(20,000)
Other	(38)	0
Net cash provided by (used in) financing activities	6,504	(54,220)
Net change in cash and cash equivalents	2,469	(10,156)
Cash and cash equivalents at beginning of period	7,817	16,910
Cash and Cash Equivalents at End of Period	$ 10,286	$ 6,754

XML

Consolidated Condensed Statements of Comprehensive Income (USD $) In Thousands, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2012	Sep. 30, 2011	Sep. 30, 2012	Sep. 30, 2011
Net Income	$ 2,046	$ 87,599	$ 190,739	$ 245,192
Other Comprehensive Income (Loss):
Current period change in fair value of commodity derivative instruments, net of tax of ($30,622), $105,683, $30,621 and $76,616	(49,962)	172,430	49,961	125,005
Pension and postretirement plans:
Amortization of net obligation at transition, net of taxes of $25, $24, $75 and $72	47	44	140	133
Amortization of prior service cost, net of taxes of $30, $26, $89 and $78	55	48	166	145
Amortization of net loss, net of taxes of $413, $318, $1,238 and $953	766	591	2,300	1,770
Current period change in fair value of pension and postretirement plans, net of taxes of ($4,073) ($5,988), ($4,073) and ($5,988)	(7,564)	(11,121)	(7,564)	(11,121)
Total pension and postretirement plans	(6,696)	(10,438)	(4,958)	(9,073)
Current period change in fair value of interest rate swap, net of tax ($375) and ($1,205)	(697)	0	(2,240)	0
Comprehensive Income (Loss)	(63,080)	239,151	210,948	351,039
Commodity Contract [Member]
Other Comprehensive Income (Loss):
Reclassification adjustment for derivative instruments, net of tax	(8,034)	(10,440)	(23,337)	(10,085)
Interest Rate Swap [Member]
Other Comprehensive Income (Loss):
Reclassification adjustment for derivative instruments, net of tax	$ 263	$ 0	$ 783	$ 0

XML

Regulatory Assets and Liabilities

9 Months Ended

Sep. 30, 2012

Regulatory Assets and Liabilities Disclosure [Abstract]

Regulatory Assets and Liabilities

REGULATORY ASSETS AND LIABILITIES

The following table details regulatory assets and liabilities on the balance sheets:

(in thousands)	September 30, 2012				December 31, 2011
	Current		Noncurrent		Current		Noncurrent
Regulatory assets:
Pension and postretirement assets	$	170	$	79,984	$	170	$	77,587
Accretion and depreciation for asset retirement obligation	—		14,885		—		13,981
Risk management activities	14,990		—		56,804		3,070
Asset removal costs, net	—		—		—		994
Gas supply adjustment	40,998		—		—		—
Other	30		—		169		1
Total regulatory assets	$	56,188	$	94,869	$	57,143	$	95,633
Regulatory liabilities:
RSE adjustment	$	3,187	$	—	$	2,931	$	—
Unbilled service margin	5,799		—		22,419		—
Gas supply adjustment	—		—		12,626		—
Refundable negative salvage	18,353		55,389		20,269		65,646
Asset retirement obligation	—		21,525		—		20,785
Other	33		778		34		803
Total regulatory liabilities	$	27,372	$	77,692	$	58,279	$	87,234

XML

Document and Entity Information	9 Months Ended
	Sep. 30, 2012	Oct. 30, 2012
Entity Information
Document Type	10-Q
Amendment Flag	true
Amendment Description	This Amendment No. 1 to our Quarterly Report on Form 10-Q for the quarter ended September 30, 2012, previously filed with the Securities and Exchange Commission (the Commission) on November 7, 2012, is being filed for the sole purpose of correcting the ending totals on the Consolidated Condensed Statements of Comprehensive Income. In connection with generation of the XBRL document for filing with the Commission, typographical errors resulted in incorrect Comprehensive Income or Loss totals for the three months ended September 30, 2012 and 2011 and for the nine months ended September 30, 2012. These totals have been corrected in this filing. Except as described above, no other changes have been made to the original filing and this Form 10-Q/A does not amend any other items or disclosures in the original filing.
Document Period End Date	Sep. 30, 2012
Document Fiscal Year Focus	2012
Document Fiscal Period Focus	Q3
Entity Registrant Name	ENERGEN CORP
Entity Central Index Key	0000277595
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Entity Common Stock, Shares Outstanding		72,146,547
Alabama Gas Corporation
Entity Information
Document Type	10-Q
Amendment Flag	true
Amendment Description	This Amendment No. 1 to our Quarterly Report on Form 10-Q for the quarter ended September 30, 2012, previously filed with the Securities and Exchange Commission (the Commission) on November 7, 2012, is being filed for the sole purpose of correcting the ending totals on the Consolidated Condensed Statements of Comprehensive Income. In connection with generation of the XBRL document for filing with the Commission, typographical errors resulted in incorrect Comprehensive Income or Loss totals for the three months ended September 30, 2012 and 2011 and for the nine months ended September 30, 2012. These totals have been corrected in this filing. Except as described above, no other changes have been made to the original filing and this Form 10-Q/A does not amend any other items or disclosures in the original filing.
Document Period End Date	Sep. 30, 2012
Document Fiscal Year Focus	2012
Document Fiscal Period Focus	Q3
Entity Registrant Name	ALABAMA GAS CORP
Entity Central Index Key	0000003146
Current Fiscal Year End Date	--12-31
Entity Filer Category	Non-accelerated Filer
Entity Common Stock, Shares Outstanding		1,972,052

XML

Asset Retirement Obligations

9 Months Ended

Sep. 30, 2012

Asset Retirement Obligation Disclosure [Abstract]

Asset Retirement Obligations

ASSET RETIREMENT OBLIGATIONS

The Company recognizes a liability for the fair value of asset retirement obligations (ARO) in the periods incurred. Subsequent to initial measurement, liabilities are accreted to their present value and capitalized costs are depreciated over the estimated useful life of the related assets. Upon settlement of the liability, the Company may recognize a gain or loss for differences between estimated and actual settlement costs. The ARO fair value liability is recognized on a discounted basis incorporating an estimate of performance risk specific to the Company.

During the nine months ended September 30, 2012, Energen Resources recognized amounts representing expected future costs associated with site reclamation, facilities dismantlement, and plug and abandonment of wells as follows:

(in thousands)
Balance of ARO as of December 31, 2011	$	107,340
Liabilities incurred	2,946
Liabilities settled	(676		)
Accretion expense	5,581
Balance of ARO as of September 30, 2012	$	115,191

The Company recognizes conditional obligations if such obligations can be reasonably estimated and a legal requirement to perform an asset retirement activity exists. Alagasco recorded a conditional asset retirement obligation, on a discounted basis of $21.5 million and $20.8 million, to purge and cap its gas pipelines upon abandonment as a regulatory liability as of September 30, 2012 and December 31, 2011, respectively. The costs associated with asset retirement obligations are currently either being recovered in rates or are probable of recovery in future rates.

Alagasco accrues removal costs on certain gas distribution assets over the useful lives of its property, plant and equipment through depreciation expense in accordance with rates approved by the APSC. Regulatory assets for accumulated asset removal costs of $1 million as of December 31, 2011 are included as regulatory assets in noncurrent assets on the balance sheets. As of September 30, 2012 and December 31, 2011, the Company recognized $18.4 million and $20.3 million, respectively, of refundable negative salvage as regulatory liabilities in current liabilities on the balance sheet in response to the June 28, 2010, APSC order. As of September 30, 2012 and December 31, 2011, the Company recognized $55.4 million and $65.6 million, respectively, of refundable negative salvage as regulatory liabilities in deferred credit and other liabilities on the balance sheet in response to the June 28, 2010, APSC order.

XML

Consolidated Condensed Statements of Comprehensive Income (Parenthetical) (USD $) In Thousands, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2012	Sep. 30, 2011	Sep. 30, 2012	Sep. 30, 2011
Current period change in fair value of commodity derivative instruments, tax	$ (30,622)	$ 105,683	$ 30,621	$ 76,616
Amortization of net obligation at transition, tax	25	24	75	72
Amortization of prior service cost, tax	30	26	89	78
Amortization of net loss, tax	(4,073)	(5,988)	(4,073)	(5,988)
Current period change in fair value of pension and postretirement plans, tax	413	318	1,238	953
Current period change in fair value of interest rate swap, tax	(375)		(1,205)
Commodity Contract [Member]
Reclassification adjustment for derivative instruments, tax	(4,924)	(6,399)	(14,303)	(6,181)
Interest Rate Swap [Member]
Reclassification adjustment for derivative instruments, tax	$ 142		$ 422

XML

Segment Information

9 Months Ended

Sep. 30, 2012

Segment Reporting [Abstract]

Segment Information

SEGMENT INFORMATION

The Company principally is engaged in two business segments: the development, acquisition, exploration and production of oil and gas in the continental United States (oil and gas operations) and the purchase, distribution and sale of natural gas in central and north Alabama (natural gas distribution).

	Three months ended						Nine months ended
	September 30,						September 30,
(in thousands)	2012			2011			2012			2011
Operating revenues
Oil and gas operations	$	233,515		$	318,952		$	856,940		$	779,834
Natural gas distribution	61,809			59,616			327,183			415,497
Total	$	295,324		$	378,568		$	1,184,123		$	1,195,331
Operating income (loss)
Oil and gas operations	$	32,407		$	161,331		$	274,818		$	351,808
Natural gas distribution	(12,743		)	(10,681		)	70,265			65,541
Eliminations and corporate expenses	(206		)	(238		)	(857		)	(721		)
Total	$	19,458		$	150,412		$	344,226		$	416,628
Other income (expense)
Oil and gas operations	$	(12,633	)	$	(9,363	)	$	(35,195	)	$	(20,632	)
Natural gas distribution	(3,274		)	(4,162		)	(10,062		)	(10,115		)
Eliminations and other	148			94			234			182
Total	$	(15,759	)	$	(13,431	)	$	(45,023	)	$	(30,565	)
Income before income taxes	$	3,699		$	136,981		$	299,203		$	386,063

(in thousands)	September 30, 2012		December 31, 2011
Identifiable assets
Oil and gas operations	$	4,734,269	$	4,046,242
Natural gas distribution	1,120,161		1,163,959
Eliminations and other	65,399		27,215
Total	$	5,919,829	$	5,237,416

XML

Reconciliation of Earnings Per Share (EPS)

9 Months Ended

Sep. 30, 2012

Earnings Per Share [Abstract]

Reconciliation of Earnings Per Share (EPS)

RECONCILIATION OF EARNINGS PER SHARE (EPS)

	Three months ended					Three months ended
(in thousands, except per share amounts)	September 30, 2012					September 30, 2011
	Net			Per Share		Net			Per Share
	Income		Shares	Amount		Income		Shares	Amount
Basic EPS	$	2,046	72,130	$	0.03	$	87,599	72,068	$	1.22
Effect of dilutive securities
Stock options			183					298
Non-vested restricted stock			3					9
Diluted EPS	$	2,046	72,316	$	0.03	$	87,599	72,375	$	1.21

	Nine months ended					Nine months ended
(in thousands, except per share amounts)	September 30, 2012					September 30, 2011
	Net			Per Share		Net			Per Share
	Income		Shares	Amount		Income		Shares	Amount
Basic EPS	$	190,739	72,121	$	2.64	$	245,192	72,045	$	3.40
Effect of dilutive securities
Stock options			177					355
Non-vested restricted stock			3					9
Diluted EPS	$	190,739	72,301	$	2.64	$	245,192	72,409	$	3.39

For the three months and nine months ended September 30, 2012, the Company had 849,583 options that were excluded from the computation of diluted EPS, as their effect was non-dilutive. For the three months and nine months ended September 30, 2011, the Company had 293,978 options that were excluded from the computation of diluted EPS. For the three months and nine months ended September 30, 2012 and 2011, the Company had no options or shares of non-vested restricted stock that were excluded from the computation of diluted EPS.

XML

Derivative Commodity Instruments (Tables)

9 Months Ended

Sep. 30, 2012

Derivative [Line Items]

Schedule of Fair Values of Commodity Contracts by business Segment on Balance Sheet

The following tables detail the fair values of commodity contracts by business segment on the balance sheets:

(in thousands)	September 30, 2012
	Oil and Gas Operations				Natural Gas Distribution			Total
Derivative assets or (liabilities) designated as hedging instruments
Accounts receivable	$	76,354			$	—		$	76,354
Long-term asset derivative instruments	51,181				—			51,181
Total derivative assets	127,535				—			127,535
Accounts receivable	(33,476		)	*	—			(33,476		)
Long-term asset derivative instruments	(17,575		)	*	—			(17,575		)
Accounts payable	(12,471		)		—			(12,471		)
Long-term liability derivative instruments	(7,739		)		—			(7,739		)
Total derivative liabilities	(71,261		)		—			(71,261		)
Total derivatives designated	56,274				—			56,274
Derivative assets or (liabilities) not designated as hedging instruments
Accounts receivable	(6,603		)	*	—			(6,603		)
Long-term asset derivative instruments	9,531				—			9,531
Total derivative assets	2,928				—			2,928
Accounts payable	(4,476		)		(14,990		)	(19,466		)
Long-term liability derivative instruments	(1,316		)		—			(1,316		)
Total derivative liabilities	(5,792		)		(14,990		)	(20,782		)
Total derivatives not designated	(2,864		)		(14,990		)	(17,854		)
Total derivatives	$	53,410			$	(14,990	)	$	38,420

(in thousands)	December 31, 2011
	Oil and Gas Operations				Natural Gas Distribution			Total
Derivative assets or (liabilities) designated as hedging instruments
Accounts receivable	$	73,636			$	—		$	73,636
Long-term asset derivative instruments	75,982				—			75,982
Total derivative assets	149,618				—			149,618
Accounts receivable	(48,174		)	*	—			(48,174		)
Long-term asset derivative instruments	(36,341		)	*	—			(36,341		)
Accounts payable	(37,070		)		—			(37,070		)
Long-term liability derivative instruments	(20,386		)		—			(20,386		)
Total derivative liabilities	(141,971		)		—			(141,971		)
Total derivatives designated	7,647				—			7,647
Derivative assets or (liabilities) not designated as hedging instruments
Accounts receivable	(3,670		)	*	—			(3,670		)
Long-term asset derivative instruments	(8,585		)	*	—			(8,585		)
Total derivative assets	(12,255		)		—			(12,255		)
Accounts payable	(13,416		)		(56,804		)	(70,220		)
Long-term liability derivative instruments	(10,922		)		(3,070		)	(13,992		)
Total derivative liabilities	(24,338		)		(59,874		)	(84,212		)
Total derivatives not designated	(36,593		)		(59,874		)	(96,467		)
Total derivatives	$	(28,946	)		$	(59,874	)	$	(88,820	)

* Amounts classified in accordance with accounting guidance which permits offsetting fair value amounts recognized for multiple derivative instruments executed with the same counterparty under a master netting arrangement.

Schedule of Cash Flow Hedging Relationships on Financial Statements

The following table details the effect of derivative commodity instruments in cash flow hedging relationships on the financial statements:

(in thousands)	Location on Income Statement	Three months ended September 30, 2012			Three months ended September 30, 2011
Gain (loss) recognized in OCI on derivative (effective portion), net of tax of ($30.6) million and $105.7 million	—	$	(49,962	)	$	172,430
Gain reclassified from accumulated OCI into income (effective portion)	Operating revenues	$	15,998		$	11,207
Gain (loss) recognized in income on derivative (ineffective portion and amount excluded from effectiveness testing)	Operating revenues	$	(3,042	)	$	5,631

(in thousands)	Location on Income Statement	Nine months ended September 30, 2012			Nine months ended September 30, 2011
Gain recognized in OCI on derivative (effective portion), net of tax of $30.6 million and $76.6 million	—	$	49,961		$	125,005
Gain reclassified from accumulated OCI into income (effective portion)	Operating revenues	$	39,012		$	13,028
Gain (loss) recognized in income on derivative (ineffective portion and amount excluded from effectiveness testing)	Operating revenues	$	(1,372	)	$	3,240

Schedule of Derivatives Not Designated as Hedging Instruments on Income Statements

The following table details the effect of derivative commodity instruments not designated as hedging instruments on the income statements:

(in thousands)	Location on Income Statement	Three months ended September 30, 2012			Three months ended September 30, 2011
Gain (loss) recognized in income on derivative	Operating revenues	$	(45,618	)	$	53,227

(in thousands)	Location on Income Statement	Nine months ended September 30, 2012		Nine months ended September 30, 2011
Gain recognized in income on derivative	Operating revenues	$	33,825	$	53,225

Schedule of Hedging Transactions

Energen Resources entered into the following transactions for the remainder of 2012 and subsequent years:

Production Period	Total Hedged Volumes		Average Contract Price	Description
Natural Gas
2012	3.6	Bcf	$4.49 Mcf	NYMEX Swaps
	8.9	Bcf	$4.14 Mcf	Basin Specific Swaps - San Juan
	2.0	Bcf	$2.89 Mcf	Basin Specific Swaps - Permian
2013	12.7	Bcf	$4.82 Mcf	NYMEX Swaps
	32.8	Bcf	$4.56 Mcf	Basin Specific Swaps - San Juan
	4.6	Bcf	$3.45 Mcf	Basin Specific Swaps - Permian
2014	10.6	Bcf	$4.55 Mcf	NYMEX Swaps
	25.7	Bcf	$4.72 Mcf	Basin Specific Swaps - San Juan
	9.7	Bcf	$3.81 Mcf	Basin Specific Swaps - Permian
Gas Basis Differential
2012	0.1	Bcf	$(0.23) Mcf	San Juan Basis Swaps
Oil
2012	1,850	MBbl	$88.51 Bbl	NYMEX Swaps
2013	8,858	MBbl	$90.95 Bbl	NYMEX Swaps
2014	9,796	MBbl	$92.64 Bbl	NYMEX Swaps
Oil Basis Differential
2012	752	MBbl	$(2.95) Bbl	WTS/WTI Basis Swaps*
2013	3,592	MBbl	$(3.03) Bbl	WTS/WTI Basis Swaps*
	1,740	MBbl	$(1.13) Bbl	WTI/WTI Basis Swaps**
Natural Gas Liquids
2012	15.3	MMGal	$0.99 Gal	Liquids Swaps
2013	44.5	MMGal	$1.02 Gal	Liquids Swaps
*WTS - West Texas Sour/Midland, WTI - West Texas Intermediate/Cushing
**WTI - West Texas Intermediate/Midland, WTI - West Texas Intermediate/Cushing

Schedule of Fair Value, Assets and Liabilities Measured on Recurring Basis

The following sets forth derivative assets and liabilities that were measured at fair value on a recurring basis:

	September 30, 2012
(in thousands)	Level 2*			Level 3*			Total
Current assets	$	(1,048	)	$	37,323		$	36,275
Noncurrent assets	18,133			25,004			43,137
Current liabilities	(30,588		)	(1,349		)	(31,937		)
Noncurrent liabilities	(5,358		)	(3,697		)	(9,055		)
Net derivative asset (liability)	$	(18,861	)	$	57,281		$	38,420

	December 31, 2011
(in thousands)	Level 2*			Level 3*			Total
Current assets	$	(14,843	)	$	36,635		$	21,792
Noncurrent assets	(8,382		)	39,438			31,056
Current liabilities	(98,468		)	(8,822		)	(107,290		)
Noncurrent liabilities	(32,928		)	(1,450		)	(34,378		)
Net derivative asset (liability)	$	(154,621	)	$	65,801		$	(88,820	)

* Amounts classified in accordance with accounting guidance which permits offsetting fair value amounts recognized for multiple derivative instruments executed with the same counterparty under a master netting arrangement.

Schedule of Changes in Fair Value of Derivative Instruments Classified as Level 3

The tables below set forth a summary of changes in the fair value of the Company’s Level 3 derivative commodity instruments as follows:

	Three months ended			Three months ended
(in thousands)	September 30, 2012			September 30, 2011
Balance at beginning of period	$	103,456		$	13,446
Realized gains	18,737			9,370
Unrealized gains (losses) relating to instruments held at the reporting date*	(46,983		)	23,953
Settlements during period	(17,929		)	(10,565		)
Balance at end of period	$	57,281		$	36,204

	Nine months ended			Nine months ended
(in thousands)	September 30, 2012			September 30, 2011
Balance at beginning of period	$	65,801		$	42,755
Realized gains	51,858			37,031
Unrealized losses relating to instruments held at the reporting date*	(9,328		)	(5,356		)
Settlements during period	(51,050		)	(38,226		)
Balance at end of period	$	57,281		$	36,204

Schedule of Fair Value Inputs, Derivatives, Quantitative Information

The tables below set forth quantitative information about the Company’s Level 3 fair value measurements of derivative commodity instruments as follows:

(in thousands)	Fair Value as of September 30, 2012			Valuation Technique*	Unobservable Input*	Range
Natural Gas Basis - San Juan
2012	$	8,807		Discounted Cash Flow	Forward Basis	($0.10 - $0.12) Mcf
2013	$	27,968		Discounted Cash Flow	Forward Basis	($0.14 - $0.15) Mcf
2014	$	17,273		Discounted Cash Flow	Forward Basis	($0.14 - $0.16) Mcf
Natural Gas Basis - Permian
2012	$	(634	)	Discounted Cash Flow	Forward Basis	($0.08) Mcf
2013	$	(1,221	)	Discounted Cash Flow	Forward Basis	($0.13) Mcf
2014	$	(2,132	)	Discounted Cash Flow	Forward Basis	($0.13 - $0.15) Mcf
Oil Basis - WTS/WTI
2012	$	14		Discounted Cash Flow	Forward Basis	($2.74 - $2.81) Bbl
2013	$	(5,085	)	Discounted Cash Flow	Forward Basis	($1.59) Bbl
Oil Basis - WTI/WTI
2013	$	(379	)	Discounted Cash Flow	Forward Basis	($0.75 - $1.15) Bbl
Natural Gas Liquids
2012	$	3,594		Discounted Cash Flow	Forward Price	$0.75 - $0.89 Gal
2013	$	9,076		Discounted Cash Flow	Forward Price	$0.77 - $0.85 Gal

*Discounted cash flow represents an income approach in calculating fair value including the referenced unobservable input and a discount reflecting credit quality of the counterparty.

Alabama Gas Corporation

Derivative [Line Items]

Schedule of Hedging Transactions

Alagasco entered into the following natural gas transactions for the remainder of 2012 and subsequent years:

Production Period	Total Hedged Volumes		Description
2012	4.6	Bcf	NYMEX Swaps
2013	1.5	Bcf	NYMEX Swaps

XML

Acquisition and Dispositions of Oil and Gas Properties

9 Months Ended

Sep. 30, 2012

Acquisition and Dispositions of Oil and Gas Properties [Abstract]

Acquisition and Dispositions of Oil and Gas Properties

ACQUISITION AND DISPOSITION OF OIL AND GAS PROPERTIES

During the first quarter of 2012, Energen Resources recognized a noncash impairment writedown on certain properties in East Texas of $21.5 million pre-tax to adjust the carrying amount of these properties to their fair value based on expected future discounted cash flows. Significant assumptions in valuing the proved reserves included the reserve quantities, anticipated operating costs, anticipated production taxes, future expected natural gas prices and basis differentials, anticipated production declines, and a discount rate of 10 percent commensurate with the risk of the underlying cash flow estimates. The impairment was caused by the impact of lower future natural gas prices. During the first quarter of 2012, future natural gas price curves shifted significantly lower, especially in the next 5 years. This nonrecurring impairment writedown is classified as Level 3 fair value.

On February 21, 2012, Energen Resources entered into a definitive agreement with BHP Billiton (BHP) to buy a 50 percent undivided interest in three existing wells in Reeves County, Texas, from Energen Resources for approximately $18 million. Following the purchase of the wells, BHP completed two of the wells and earned a 50 percent undivided interest in 4,829 net acres. The agreement also included the option for BHP to purchase from Energen Resources a 50 percent undivided interest in 51,720 net acres in the Permian Basin. On May 1, 2012, BHP elected not to exercise the option.

On February 14, 2012, Energen completed the purchase of certain properties in the Permian Basin for a cash purchase price of $68 million. This purchase had an effective date of December 1, 2011. Energen acquired total proved reserves of approximately 8.1 MMBOE. Of the proved reserves acquired, an estimated 81 percent are undeveloped. Approximately 64 percent of the proved reserves are oil, 22 percent are natural gas liquids and natural gas comprises the remaining 14 percent. Energen Resources used its credit facilities and internally generated cash flows to finance the acquisition. Pro forma financial information for this acquisition is not presented because it would not be materially different from the information presented in the consolidated statements of income.

The following table summarizes the consideration paid and the amounts of the assets acquired and liabilities assumed recognized as of February 14, 2012 (including the effects of closing adjustments).

(in thousands)
Consideration given
Cash (net)	$	67,615
Recognized amounts of identifiable assets acquired and liabilities assumed
Proved properties	$	65,581
Unproved leasehold properties	911
Accounts receivable	1,358
Accounts payable	(25		)
Asset retirement obligation	(210		)
Total identifiable net assets	$	67,615

Included in the Company’s consolidated results of operations for the nine months ended September 30, 2012, were $8.8 million of operating revenues and $3.2 million in operating income resulting from the operation of the properties acquired above.

On December 27, 2011, Energen completed the purchase of certain properties in the Permian Basin for a cash purchase price of $60 million (subject to closing adjustments). This purchase had an effective date of July 1, 2011. Energen acquired total proved reserves of approximately 3.4 MMBOE. Of the proved reserves acquired, an estimated 77 percent are undeveloped. Approximately 61 percent of the proved reserves are oil, 24 percent are natural gas liquids and natural gas comprises the remaining 15 percent. Energen Resources used its credit facilities and internally generated cash flows to finance the acquisition. Pro forma financial information for this acquisition is not presented because it would not be materially different from the information presented in the consolidated statements of income.

The following table summarizes the consideration paid and the amounts of the assets acquired and liabilities assumed recognized as of December 27, 2011. The purchase price allocation is preliminary and subject to adjustment as the final closing statement is not complete.

(in thousands)
Consideration given
Cash (net)	$	59,997
Recognized amounts of identifiable assets acquired and liabilities assumed
Proved properties	$	36,048
Unproved leasehold properties	23,686
Accounts receivable	680
Accounts payable	(244		)
Asset retirement obligation	(173		)
Total identifiable net assets	$	59,997

The impact to operating revenues and operating income from this acquisition was not material for the year ended December 31, 2011.

On November 16, 2011, Energen completed the purchase of certain liquids-rich properties in the Permian Basin for a cash purchase price of $162 million. This purchase had an effective date of August 1, 2011. Energen acquired total proved reserves of approximately 13.6 million MMBOE. Of the proved reserves acquired, an estimated 76 percent are undeveloped. Approximately 59 percent of the proved reserves are oil, 25 percent are natural gas liquids and natural gas comprises the remaining 16 percent. Energen Resources used its credit facilities and internally generated cash flows to finance the acquisition. Pro forma financial information for this acquisition is not presented because it would not be materially different from the information presented in the consolidated statements of income.

The following table summarizes the consideration paid and the amounts of the assets acquired and liabilities assumed recognized as of November 16, 2011, (including the effects of closing adjustments).

(in thousands)
Consideration given
Cash (net)	$	161,967
Recognized amounts of identifiable assets acquired and liabilities assumed
Proved properties	$	151,544
Unproved leasehold properties	7,883
Accounts receivable	3,070
Accounts payable	(388		)
Asset retirement obligation	(142		)
Total identifiable net assets	$	161,967

The impact to operating revenues and operating income from this acquisition was not material for the year ended December 31, 2011.

In July 2011, Energen completed the purchase of liquids-rich properties in the Permian Basin for a cash purchase price of approximately $20 million. In April 2011, Energen completed the purchase of unproved leasehold properties for a cash purchase price of approximately $37 million covering an estimated 11,000 net acres in the Permian Basin.

XML

Commitments and Contingencies

9 Months Ended

Sep. 30, 2012

Commitments and Contingencies Disclosure [Abstract]

Commitments and Contingencies

COMMITMENTS AND CONTINGENCIES    

Commitments and Agreements: Under various agreements for third party gathering, treatment, transportation or other services, Energen Resources is committed to deliver minimum production volumes or to pay certain costs in the event the minimum quantities are not delivered. These delivery commitments are approximately 33.4 million barrels of oil equivalent (MMBOE) through November 2021.

Energen Resources entered into three agreements which commenced at various dates from November 15, 2011 to January 15, 2012 and expire at various dates through January 2015 to secure drilling rigs necessary to execute a portion of its drilling plans. In the unlikely event that Energen Resources discontinues use of these drilling rigs, Energen Resources' total resulting exposure could be as much as $24 million depending on the contractor's ability to remarket the drilling rig.

Certain of Alagasco's long-term contracts associated with the delivery and storage of natural gas include fixed charges of approximately $74 million through September 2024. During the nine months ending September 30, 2012 and 2011, Alagasco recognized approximately $36.8 million of long-term commitments through expense and its regulatory accounts in the accompanying financial statements. Alagasco also is committed to purchase minimum quantities of gas at market-related prices or to pay certain costs in the event the minimum quantities are not taken. These purchase commitments are approximately 177 Bcf through August 2020.

Alagasco purchases gas as an agent for certain of its large commercial and industrial customers. Alagasco has, in certain instances, provided commodity-related guarantees to the counterparties in order to facilitate these agency purchases. Liabilities existing for gas delivered to customers subject to these guarantees are included in the balance sheets. In the event the customer for whom the guarantee was entered fails to take delivery of the gas, Alagasco can sell such gas for the customer, with the customer liable for any resulting loss. Although the substantial majority of purchases under these guarantees are for the customers' current monthly consumption and are at current market prices, in some instances, the purchases are for an extended term at a fixed price. At September 30, 2012, the fixed price purchases under these guarantees had a maximum term outstanding through March 2013 and an aggregate purchase price of $0.8 million with a market value of $0.8 million.

Income Taxes: The Company and Alagasco have on-going tax examinations under various U.S. and state tax jurisdictions. Accordingly, it is reasonably possible that significant changes to the reserve for uncertain tax benefits may occur as a result of the completion of various audits and the expiration of statute of limitations. Although the timing and outcome of these tax examinations is highly uncertain, the Company does not expect the change in the unrecognized tax benefit within the next 12 months would have a material impact to the financial statements.

Legal Matters: Energen and its affiliates are, from time to time, parties to various pending or threatened legal proceedings. Certain of these lawsuits include claims for punitive damages in addition to other specified relief. Based upon information presently available and in light of available legal and other defenses, contingent liabilities arising from threatened and pending litigation are not considered material in relation to the respective financial positions of Energen and its affiliates. It should be noted, however, that Energen and its affiliates conduct business in jurisdictions in which the magnitude and frequency of punitive and other damage awards may bear little or no relation to culpability or actual damages, thus making it difficult to predict litigation results.

Various pending or threatened legal proceedings are in progress currently, and the Company has accrued a provision for estimated liability. This provision was increased by $1.4 million during the nine months ended September 30, 2012.

Environmental Matters: Various environmental laws and regulations apply to the operations of Energen Resources and Alagasco. Historically, the cost of environmental compliance has not materially affected the Company's financial position, results of operations or cash flows. New regulations, enforcement policies, claims for damages or other events could result in significant unanticipated costs.

Alagasco is in the chain of title of nine former manufactured gas plant sites, four of which it still owns, and five former manufactured gas distribution sites, one of which it still owns and is the subject of a recent inquiry discussed below. Also discussed below is the recent completion of a removal action at the Huntsville, Alabama manufactured gas plant site. An investigation of the sites does not indicate the present need for other remediation activities and management expects that, should remediation of any such sites be required in the future, Alagasco's share, if any, of such costs will not materially affect the financial position of Alagasco.

In May 2012, Alagasco received from the United States Environmental Protection Agency (EPA) a Request for information Pursuant to Section 104 of CERCLA relating to the EPA's investigation of a site which it refers to as the 35^th Avenue Superfund Site in and around Birmingham, Jefferson County, Alabama. The inquiry requests information about a parcel owned by Alagasco and located in the vicinity of the 35^th Avenue site. The parcel is the former site of a manufactured gas distribution facility. Alagasco has responded to the inquiry.

In June 2009, Alagasco received a General Notice Letter from the EPA identifying Alagasco as a responsible party for a former manufactured gas plant (MGP) site located in Huntsville, Alabama, and inviting Alagasco to enter an Administrative Settlement Agreement and Order on Consent to perform a removal action at that site. The Huntsville MGP, along with the Huntsville gas distribution system, was sold by Alagasco to the City of Huntsville in 1949. While Alagasco no longer owns the Huntsville site, the Company and the current site owner entered into a Consent Order, and developed and completed during 2011 an action plan for the site. Alagasco has incurred costs associated with the site of approximately $5.0 million. As of September 30, 2012, the expected remaining costs are not expected to be material to the Company. Alagasco has recorded a corresponding amount to its Enhanced Stability Reserve regulatory asset account of which a debit balance of $4.8 million was cleared as of September 30, 2011 and allocated, subject to APSC review guidelines, against the refundable negative salvage costs being refunded to customers.

New Mexico Audits: During the third quarter of 2010, Energen Resources received preliminary findings from the Taxation and Revenue Department (the Department) of the State of New Mexico relating to its audit, conducted on behalf of the Office of Natural Resources Revenue (ONRR), of federal oil and gas leases in New Mexico. The audit covered periods from January 2004 through December 2008 and included a review of the computation and payment of royalties due on minerals removed from specified U.S. federal leases. The ONRR has proposed certain changes in the method of determining allowable deductions of transportation, fuel and processing costs from royalties due under the terms of the related leases.

As a result of the audit, Energen Resources has been ordered by the ONRR to pay additional royalties on the specified U.S. federal leases in the amount of $142,000 and restructure its accounting for all federal leases in two counties in New Mexico from March 1, 2004, forward. The Company preliminarily estimates that application of the Order to all of the Company's New Mexico federal leases would result in ONRR claims for up to approximately $23 million of additional royalties plus interest and penalties for the period from March 1, 2004, forward. The preliminary findings and subsequent Order (issued April 25, 2011) are contrary to deductions allowed under previous audits, retroactive in application and inconsistent with the Company’s understanding of industry practice. The Company is vigorously contesting the Order and has requested additional information from the ONRR and the Department to assist the Company in evaluating the ONRR Order and the Department's findings. Management is unable, at this time, to determine a range of reasonably possible losses as a result of this Order, and no amount has been accrued as of September 30, 2012.

Capital Lease Obligations: During the first quarter of 2012, the Company entered into certain capital leases related to certain equipment. The following is a schedule of future minimum lease payments under capital leases together with the present value of the net minimum lease payments as of September 30, 2012:

(in thousands)
2012	$	436
2013	1,743
2014	1,743
2015	145
Total minimum lease payments	4,067
Less amount representing interest	93
Total present value of minimum lease payments	$	3,974

XML

Stock Compensation

9 Months Ended

Sep. 30, 2012

Share-based Compensation [Abstract]

Stock Compensation

STOCK COMPENSATION

Stock Incentive Plan

The Stock Incentive Plan provides for the grant of incentive stock options, non-qualified stock options, restricted stock, performance shares or a combination thereof to officers and key employees. Options granted under the Stock Incentive Plan provide for the purchase of Company common stock at not less than the fair market value on the date the option is granted. The sale or transfer of the shares is limited during certain periods. All outstanding options vest within three years from date of grant and expire 10 years from the grant date. The Company granted 371,040 non-qualified option shares during the first quarter of 2012 with a grant-date fair value of $18.79.

Petrotech Incentive Plan

The Energen Resources’ Petrotech Incentive Plan provides for the grant of stock equivalent units. These awards are liability awards which settle in cash and are re-measured each reporting period until settlement. During the nine months ended September 30, 2012, Energen Resources awarded 102,349, 3,768 and 40,822 Petrotech units with a three-year, two-year and 18 month vesting period, respectively. These awards have a fair value of $51.17, $51.72 and $51.99 per unit, respectively, as of September 30, 2012.

Stock Repurchase Program

During the three months and nine months ended September 30, 2012, the Company had noncash purchases of approximately $111,000 and $229,000, respectively, of Company common stock in conjunction with tax withholdings on its non-qualified deferred compensation plan and other stock compensation. The Company utilized internally generated cash flows in payment of the related tax withholdings.

XML

Employee Benefit Plans

9 Months Ended

Sep. 30, 2012

Defined Benefit Pension Plans and Defined Benefit Postretirement Plans Disclosure [Abstract]

Employee Benefit Plans

EMPLOYEE BENEFIT PLANS

The components of net pension expense for the Company’s two defined benefit non-contributory pension plans and certain nonqualified supplemental pension plans were:

	Three months ended September 30,						Nine months ended September 30,
(in thousands)	2012			2011			2012			2011
Components of net periodic benefit cost:
Service cost	$	2,632		$	2,293		$	7,895		$	6,879
Interest cost	2,700			2,740			8,101			8,220
Expected long-term return on assets	(3,563		)	(3,868		)	(10,689		)	(11,603		)
Actuarial loss	2,099			1,609			6,297			4,826
Prior service cost amortization	129			124			388			372
Net periodic expense	$	3,997		$	2,898		$	11,992		$	8,694

During the third quarter of 2012, the Moving Ahead for Progress in the 21st Century Act (MAP-21) was signed into law. This law included pension funding stabilization measures designed to stabilize the discount rate used to determine funding requirements. The impact of MAP-21 on Energen's pension plans was to reduce the required contributions during 2012 from approximately $12.8 million to $2.1 million to the qualified pension plans. These contribution requirements were satisfied during the third quarter of 2012 by applying the plans' funding balances, as established under Internal Revenue Code Section 430(f). It is not anticipated that the funded status of the qualified pension plans will fall below statutory thresholds requiring accelerated funding or constraints on benefit levels or plan administration. No additional discretionary contributions are currently expected to be made to the pension plans by the Company during 2012. For the three months and nine months ending September 30, 2012, the Company made benefit payments aggregating $36,000 and $2.3 million, respectively, to retirees from the nonqualified supplemental retirement plans and expects to make additional benefit payments of approximately $36,000 through the remainder of 2012.

The components of net periodic postretirement benefit expense for the Company’s postretirement benefit plans were:

	Three months ended September 30,						Nine months ended September 30,
(in thousands)	2012			2011			2012			2011
Components of net periodic benefit cost:
Service cost	$	463		$	442		$	1,390		$	1,327
Interest cost	1,062			1,111			3,186			3,332
Expected long-term return on assets	(1,109		)	(1,104		)	(3,328		)	(3,314		)
Actuarial loss	9			—			27			—
Transition amortization	479			479			1,438			1,438
Net periodic expense	$	904		$	928		$	2,713		$	2,783

For the three months and nine months ended September 30, 2012, the Company made contributions aggregating $0.9 million and $2.7 million, respectively, to the postretirement benefit plans. The Company expects to make additional discretionary contributions of approximately $0.9 million to the postretirement benefit plans through the remainder of 2012.

XML

Financial Instruments

9 Months Ended

Sep. 30, 2012

Fair Value Disclosures [Abstract]

Financial Instruments

FINANCIAL INSTRUMENTS

The stated value of cash and cash equivalents, short-term investments, trade receivables (net of allowance), and short-term debt approximates fair value due to the short maturity of the instruments. The fair value of Energen's long-term debt, including the current portion, approximates $1,256.2 million and has a carrying value of $1,154.1 million at September 30, 2012. The fair value of Alagasco's fixed-rate long-term debt, including the current portion, approximates $284.9 million and has a carrying value of $250.1 million at September 30, 2012. The fair values were based on market prices of similar debt issues having the same remaining maturities, redemption terms and credit rating. Short-term debt is classified as Level 1 fair value and long-term debt is classified as Level 2 fair value.

In December 2011, the Company entered into interest rate swap agreements for $200 million of the Senior Term Loans. The swap agreements exchange a variable interest rate for a fixed interest rate of 2.4175 percent on $200 million of the principal amount outstanding. The fair value of the Company's interest rate swap was a $3.7 million liability at September 30, 2012 and is classified as Level 1 fair value.

Finance Receivables: Alagasco finances third-party contractor sales of merchandise including gas furnaces and appliances. At September 30, 2012 and December 31, 2011, Alagasco’s finance receivable totaled $10.7 million and $10.5 million, respectively. These finance receivables currently have an average balance of approximately $3,000 and with terms of up to 60 months. Financing is available only to qualified customers who meet credit worthiness thresholds for customer payment history and external agency credit reports. Alagasco relies upon ongoing payments as the primary indicator of credit quality during the term of each contract. The allowance for credit losses is recognized using an estimate of write-off percentages based on historical experience applied to an aging of the finance receivable balance. Delinquent accounts are evaluated on a case-by-case basis and, absent evidence of debt repayment after 90 days, are due in full and assigned to a third-party collection agency. The remaining finance receivable is written off approximately 12 months after being assigned to the third-party collection agency. Alagasco had finance receivables past due 90 days or more of $467,000 as of September 30, 2012.

The following table sets forth a summary of changes in the allowance for credit losses as follows:

(in thousands)
Allowance for credit losses as of December 31, 2011	$	421
Provision	21
Allowance for credit losses as of September 30, 2012	$	442

XML

Derivative Commodity Instruments - Derivative Instruments by Income Statement Location (Details) (USD $)	3 Months Ended		9 Months Ended
	Sep. 30, 2012	Sep. 30, 2011	Sep. 30, 2012	Sep. 30, 2011
Derivative Instruments, Gain (Loss) [Line Items]
Derivative Instruments, Gain (Loss) Recognized in Other Comprehensive Income (Loss), Effective Portion, Tax	$ (30,622,000)	$ 105,683,000	$ 30,621,000	$ 76,616,000
Gain recognized in OCI on derivative (effective portion), net of tax	(49,962,000)	172,430,000	49,961,000	125,005,000
Derivative Instruments, Gain (Loss) Reclassification from Accumulated OCI to Income, Estimated Net Amount to be Transferred	20,200,000
Gain (Loss) on Discontinuation of Cash Flow Hedge Due to Forecasted Transaction Probable of Not Occurring, Net			0
Fair Value Hedging [Member] | Natural Gas [Member] | 2012
Derivative Instruments, Gain (Loss) [Line Items]
Derivative, Nonmonetary Notional Amount	2,000,000		2,000,000
Fair Value Hedging [Member] | Natural Gas [Member] | 2013
Derivative Instruments, Gain (Loss) [Line Items]
Derivative, Nonmonetary Notional Amount	5,600,000		5,600,000
Fair Value Hedging [Member] | Natural Gas [Member] | 2014
Derivative Instruments, Gain (Loss) [Line Items]
Derivative, Nonmonetary Notional Amount	9,700,000		9,700,000
Fair Value Hedging [Member] | Crude Oil [Member] | 2012
Derivative Instruments, Gain (Loss) [Line Items]
Derivative, Nonmonetary Notional Amount	1,200,000		1,200,000
Fair Value Hedging [Member] | Crude Oil [Member] | 2013
Derivative Instruments, Gain (Loss) [Line Items]
Derivative, Nonmonetary Notional Amount	8,700,000		8,700,000
Fair Value Hedging [Member] | Crude Oil [Member] | 2014
Derivative Instruments, Gain (Loss) [Line Items]
Derivative, Nonmonetary Notional Amount	5,400,000		5,400,000
Fair Value Hedging [Member] | Natural Gas Liquids [Member] | 2012
Derivative Instruments, Gain (Loss) [Line Items]
Derivative, Nonmonetary Notional Amount	3,800,000		3,800,000
Fair Value Hedging [Member] | Natural Gas Liquids [Member] | 2013
Derivative Instruments, Gain (Loss) [Line Items]
Derivative, Nonmonetary Notional Amount	1,600,000		1,600,000
Operating revenues
Derivative Instruments, Gain (Loss) [Line Items]
Gain (loss) reclassified from accumulated OCI into income (effective portion)	15,998,000	11,207,000	39,012,000	13,028,000
Gain (Loss) recognized in income on derivative (ineffective portion and amount excluded from effectiveness testing)	(3,042,000)	5,631,000	(1,372,000)	3,240,000
Derivative Instruments, Loss Recognized in Income	(45,618,000)
Derivative Instruments, Gain Recognized in Income		$ 53,227,000	$ 33,825,000	$ 53,225,000

XML

Acquisition and Dispositions of Oil and Gas Properties (Details) (USD $)	3 Months Ended		9 Months Ended		0 Months Ended		3 Months Ended	0 Months Ended													0 Months Ended
	Sep. 30, 2012	Sep. 30, 2011	Sep. 30, 2012	Sep. 30, 2011	Feb. 21, 2012 Feb 21, 2012, Reeves County [Member] A well	Feb. 14, 2012 Feb 14, 2012, Permian Basin [Member] mmboe	Sep. 30, 2012 Feb 14, 2012, Permian Basin [Member]	Feb. 14, 2012 Feb 14, 2012, Permian Basin [Member] Oil Reserves	Feb. 14, 2012 Feb 14, 2012, Permian Basin [Member] Natural Gas Liquids Reserves	Feb. 14, 2012 Feb 14, 2012, Permian Basin [Member] Natural Gas Reserves	Dec. 27, 2011 Dec 27, 2011, Permian Basin [Member] mmboe	Dec. 27, 2011 Dec 27, 2011, Permian Basin [Member] Oil Reserves	Dec. 27, 2011 Dec 27, 2011, Permian Basin [Member] Natural Gas Liquids Reserves	Dec. 27, 2011 Dec 27, 2011, Permian Basin [Member] Natural Gas Reserves	Nov. 16, 2011 Nov 16, 2011, Permian Basin [Member] mmboe	Nov. 16, 2011 Nov 16, 2011, Permian Basin [Member] Oil Reserves	Nov. 16, 2011 Nov 16, 2011, Permian Basin [Member] Natural Gas Liquids Reserves	Nov. 16, 2011 Nov 16, 2011, Permian Basin [Member] Natural Gas Reserves	Jul. 31, 2011 July 2011, Permian Basin	Apr. 30, 2011 April 2011, Permian Basin A	May 01, 2012 Contingent Sales Agreement [Member] Feb 21, 2012, Reeves County [Member] A
Significant Acquisitions and Disposals [Line Items]
Asset Impairment Charges	$ 0	$ 0	$ 21,545,000	$ 0
Standardized Measure of Discounted Percentage of Future Net Cash Flow of Proved Oil and Gas Reserves, Other	10.00%
Significant Acquisitions and Disposals, Percentage of Undivided Interest, Sale					50.00%																50.00%
Wells in Process of Drilling					3
Proceeds from Sale of Oil and Gas Property and Equipment					18,000,000
Gas and Oil Acreage, Undeveloped, Net					4,829															11,000	51,720
Consideration - Purchase Price						67,615,000					59,997,000				161,967,000				20,000,000	37,000,000
Proved Developed and Undeveloped Reserves, Net						8.1					3.4				13.6
Percentage of Undeveloped Portion of Proved Reserves						81.00%					77.00%				76.00%
Acquired Proved Reserves by Type of Reserve, Percentage								64.00%	22.00%	14.00%		61.00%	24.00%	15.00%		59.00%	25.00%	16.00%
Recognized amounts of identifiable assets acquired and liabilities assumed
Proved properties						65,581,000					36,048,000				151,544,000
Unproved leasehold properties						911,000					23,686,000				7,883,000
Accounts receivable						1,358,000					680,000				3,070,000
Accounts payable						(25,000)					(244,000)				(388,000)
Asset retirement obligation						(210,000)					(173,000)				(142,000)
Total identifiable net assets						67,615,000					59,997,000				161,967,000
Operating revenues	295,324,000	378,568,000	1,184,123,000	1,195,331,000			8,800,000
Operating income	$ 19,458,000	$ 150,412,000	$ 344,226,000	$ 416,628,000			$ 3,200,000

XML

Derivative Commodity Instruments Derivative Commodity Investments (Policies)

9 Months Ended

Sep. 30, 2012

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Derivatives, Policy

Energen Resources Corporation, Energen's oil and gas subsidiary, recognizes all derivatives on the balance sheet and measures all derivatives at fair value. If a derivative is designated as a cash flow hedge, the effectiveness of the hedge, or the degree that the gain (loss) for the hedging instrument offsets the loss (gain) on the hedged item, is measured at each reporting period. The effective portion of the gain or loss on the derivative instrument is recognized in other comprehensive income (OCI) as a component of shareholders’ equity and subsequently reclassified as operating revenues when the forecasted transaction affects earnings. The ineffective portion of a derivative's change in fair value is required to be recognized in operating revenues immediately. All derivative transactions are included in operating activities on the consolidated condensed statements of cash flows.

Energen Resources periodically enters into derivative commodity instruments to hedge its exposure to price fluctuations on oil, natural gas and natural gas liquids production. In prior years, Alagasco entered into cash flow derivative commodity instruments to hedge its exposure to price fluctuations on its gas supply. Hedge transactions are pursuant to standing authorizations by the Board of Directors, which do not authorize speculative positions. Such instruments may include over-the-counter (OTC) swaps and basis hedges typically with investment and commercial banks and energy-trading firms. The Company is at risk for economic loss based upon the creditworthiness of its counterparties. Energen Resources was in a net gain position with eleven of its active counterparties at September 30, 2012. The five largest counterparty net gain positions at September 30, 2012, Macquarie Bank Limited, J Aron & Company, BP Corporation North America Inc., Shell Energy North America (US), L.P. and Citibank, N.A. constituted approximately $16.8 million, $9.7 million, $9.6 million, $8.5 million and $7.7 million, respectively, of Energen Resources’ net gain on fair value of derivatives. Energen Resources was in a net loss position with three of its active counterparties at September 30, 2012. The largest counterparty net loss position at September 30, 2012, Morgan Stanley Capital Group, Inc constituted approximately $24.3 million of Energen Resources’ net loss on fair value of derivatives.

The current policy of the Company is to not enter into agreements that require the posting of collateral. The Company has a few older agreements, none of which have active positions as of September 30, 2012, which include collateral posting requirements based on the amount of exposure and counterparty credit ratings. The majority of the Company’s counterparty agreements include provisions for net settlement of transactions payable on the same date and in the same currency. Most of the agreements include various contractual set-off rights, which may be exercised by the non-defaulting party in the event of an early termination due to a default.

The Company periodically enters into derivative transactions that do not qualify for cash flow hedge accounting but are considered by management to represent valid economic hedges and are accounted for as mark-to-market transactions. These economic hedges may include, but are not limited to, hedges on estimated future production not yet flowing, basis hedges without a corresponding New York Mercantile Exchange (NYMEX) hedge, and hedges on non-operated or other properties for which all of the necessary information to qualify for cash flow hedge accounting is either not readily available or subject to change. Derivatives that do not qualify for hedge treatment or are not designated as cash flow hedges are recorded at fair value with gains or losses recognized in operating revenues in the period of change.

XML

Employee Benefit Plans (Tables)

9 Months Ended

Sep. 30, 2012

Pension Plans

Defined Benefit Plan Disclosure

Schedule of Net Benefit Costs

The components of net pension expense for the Company’s two defined benefit non-contributory pension plans and certain nonqualified supplemental pension plans were:

	Three months ended September 30,						Nine months ended September 30,
(in thousands)	2012			2011			2012			2011
Components of net periodic benefit cost:
Service cost	$	2,632		$	2,293		$	7,895		$	6,879
Interest cost	2,700			2,740			8,101			8,220
Expected long-term return on assets	(3,563		)	(3,868		)	(10,689		)	(11,603		)
Actuarial loss	2,099			1,609			6,297			4,826
Prior service cost amortization	129			124			388			372
Net periodic expense	$	3,997		$	2,898		$	11,992		$	8,694

Postretirement Benefit Plans

Defined Benefit Plan Disclosure

Schedule of Net Benefit Costs

The components of net periodic postretirement benefit expense for the Company’s postretirement benefit plans were:

	Three months ended September 30,						Nine months ended September 30,
(in thousands)	2012			2011			2012			2011
Components of net periodic benefit cost:
Service cost	$	463		$	442		$	1,390		$	1,327
Interest cost	1,062			1,111			3,186			3,332
Expected long-term return on assets	(1,109		)	(1,104		)	(3,328		)	(3,314		)
Actuarial loss	9			—			27			—
Transition amortization	479			479			1,438			1,438
Net periodic expense	$	904		$	928		$	2,713		$	2,783

XML

Regulatory Assets and Liabilities (Details) (USD $) In Thousands, unless otherwise specified	Sep. 30, 2012	Dec. 31, 2011
Regulatory Assets and Liabilities [Line Items]
Regulatory Assets, Current	$ 56,188	$ 57,143
Regulatory Assets, Noncurrent	94,869	95,633
Regulatory Liability, Current	27,372	58,279
Regulatory Liability, Noncurrent	77,692	87,234
Refundable negative salvage
Regulatory Assets and Liabilities [Line Items]
Regulatory Liability, Current	18,400	20,300
Regulatory Liability, Noncurrent	55,400	65,600
Alabama Gas Corporation
Regulatory Assets and Liabilities [Line Items]
Regulatory Assets, Current	56,188	57,143
Regulatory Assets, Noncurrent	94,869	95,633
Regulatory Liability, Current	27,372	58,279
Regulatory Liability, Noncurrent	77,692	87,234
Alabama Gas Corporation | RSE adjustment
Regulatory Assets and Liabilities [Line Items]
Regulatory Liability, Current	3,187	2,931
Regulatory Liability, Noncurrent	0	0
Alabama Gas Corporation | Unbilled service margin
Regulatory Assets and Liabilities [Line Items]
Regulatory Liability, Current	5,799	22,419
Regulatory Liability, Noncurrent	0	0
Alabama Gas Corporation | Gas Supply Adjustment [Member]
Regulatory Assets and Liabilities [Line Items]
Regulatory Liability, Current	0	12,626
Regulatory Liability, Noncurrent	0	0
Alabama Gas Corporation | Refundable negative salvage
Regulatory Assets and Liabilities [Line Items]
Regulatory Liability, Current	18,353	20,269
Regulatory Liability, Noncurrent	55,389	65,646
Alabama Gas Corporation | Asset retirement obligation
Regulatory Assets and Liabilities [Line Items]
Regulatory Liability, Current	0	0
Regulatory Liability, Noncurrent	21,525	20,785
Alabama Gas Corporation | Other
Regulatory Assets and Liabilities [Line Items]
Regulatory Liability, Current	33	34
Regulatory Liability, Noncurrent	778	803
Alabama Gas Corporation | Pension and postretirement assets
Regulatory Assets and Liabilities [Line Items]
Regulatory Assets, Current	170	170
Regulatory Assets, Noncurrent	79,984	77,587
Alabama Gas Corporation | Accretion and depreciation for asset retirement obligation
Regulatory Assets and Liabilities [Line Items]
Regulatory Assets, Current	0	0
Regulatory Assets, Noncurrent	14,885	13,981
Alabama Gas Corporation | Risk management activities
Regulatory Assets and Liabilities [Line Items]
Regulatory Assets, Current	14,990	56,804
Regulatory Assets, Noncurrent	0	3,070
Alabama Gas Corporation | Asset removal costs, net
Regulatory Assets and Liabilities [Line Items]
Regulatory Assets, Current	0	0
Regulatory Assets, Noncurrent	0	994
Alabama Gas Corporation | Gas Supply Adjustment [Member]
Regulatory Assets and Liabilities [Line Items]
Regulatory Assets, Current	40,998	0
Regulatory Assets, Noncurrent	0	0
Alabama Gas Corporation | Other
Regulatory Assets and Liabilities [Line Items]
Regulatory Assets, Current	30	169
Regulatory Assets, Noncurrent	$ 0	$ 1

XML

Segment Information (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2012	Sep. 30, 2011	Sep. 30, 2012	Sep. 30, 2011	Dec. 31, 2011
Segment Reporting Information, Profit (Loss)
Operating revenues	$ 295,324	$ 378,568	$ 1,184,123	$ 1,195,331
Operating income (loss)	19,458	150,412	344,226	416,628
Other income (expense)	(15,759)	(13,431)	(45,023)	(30,565)
Income before income taxes	3,699	136,981	299,203	386,063
Identifiable assets	5,919,829		5,919,829		5,237,416
Oil and Gas Operations
Segment Reporting Information, Profit (Loss)
Operating revenues	233,515	318,952	856,940	779,834
Operating income (loss)	32,407	161,331	274,818	351,808
Other income (expense)	(12,633)	(9,363)	(35,195)	(20,632)
Identifiable assets	4,734,269		4,734,269		4,046,242
Natural Gas Distribution
Segment Reporting Information, Profit (Loss)
Operating revenues	61,809	59,616	327,183	415,497
Operating income (loss)	(12,743)	(10,681)	70,265	65,541
Other income (expense)	(3,274)	(4,162)	(10,062)	(10,115)
Identifiable assets	1,120,161		1,120,161		1,163,959
Eliminations and other
Segment Reporting Information, Profit (Loss)
Operating income (loss)	(206)	(238)	(857)	(721)
Other income (expense)	148	94	234	182
Identifiable assets	$ 65,399		$ 65,399		$ 27,215

XML

Consolidated Condensed Balance Sheets (USD $) In Thousands, unless otherwise specified	Sep. 30, 2012	Dec. 31, 2011
Current Assets
Cash and cash equivalents	$ 47,137	$ 9,541
Accounts receivable
Allowance for doubtful accounts	(6,649)	(12,946)
Accounts receivable, net of allowance for doubtful accounts of $6,649 at September 30, 2012, and $12,946 at December 31, 2011	194,473	231,925
Inventories
Storage gas inventory	36,849	44,047
Materials and supplies	33,596	26,420
Liquified natural gas in storage	3,505	3,545
Regulatory asset	56,188	57,143
Income tax receivable	5,526	7,343
Deferred income taxes	32,993	48,818
Prepayments and other	16,998	15,386
Total current assets	427,265	444,168
Property, Plant and Equipment
Oil and gas properties, successful efforts method	6,110,988	5,166,368
Less accumulated depreciation, depletion and amortization	1,662,144	1,382,526
Oil and gas properties, net	4,448,844	3,783,842
Utility plant	1,395,454	1,358,266
Less accumulated depreciation	560,279	544,838
Utility plant, net	835,175	813,428
Other property, net	23,953	23,506
Total property, plant and equipment, net	5,307,972	4,620,776
Other Assets
Regulatory asset	94,869	95,633
Long-term derivative instruments	43,137	31,056
Deferred charges and other	46,586	45,783
Total other assets	184,592	172,472
TOTAL ASSETS	5,919,829	5,237,416
Current Liabilities
Long-term debt due within one year	0	1,000
Notes payable to banks	480,000	15,000
Accounts payable	264,930	302,048
Affiliated Companies		0
Accrued taxes	55,416	32,359
Customers' deposits	23,563	23,950
Amounts due customers	21,828	21,065
Accrued wages and benefits	24,618	35,258
Regulatory liability	27,372	58,279
Royalty payable	38,313	22,592
Other	27,191	32,328
Total current liabilities	963,231	543,879
Long-term debt	1,153,591	1,153,700
Deferred Credits and Other Liabilities
Asset retirement obligation	115,191	107,340
Pension and other postretirement liabilities	82,993	62,532
Regulatory liability	77,692	87,234
Long-term derivative instruments	11,110	34,663
Deferred income taxes	885,839	806,127
Other	9,093	9,778
Total deferred credits and other liabilities	1,181,918	1,107,674
Commitments and Contingencies
Shareholders' Equity
Preferred stock, cumulative $0.01 par value	0	0
Common shareholders' equity
Common stock, $0.01 par value	751	750
Premium on capital stock	491,416	482,918
Capital surplus	2,802	2,802
Retained earnings	2,261,332	2,100,885
Accumulated other comprehensive loss, net of tax
Unrealized gain (loss) on hedges, net	35,897	9,273
Pension and postretirement plans	(43,542)	(38,584)
Interest rate swap	(2,398)	(941)
Deferred compensation plan	3,433	3,511
Treasury stock, at cost; 3,031,622 shares at September 30, 2012, and 3,036,549 shares at December 31, 2011	(128,602)	(128,451)
Total shareholders' equity	2,621,089	2,432,163
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY	5,919,829	5,237,416
Alabama Gas Corporation
Current Assets
Cash and cash equivalents	10,286	7,817
Accounts receivable
Gas	38,014	96,812
Other	5,092	6,858
Affiliated companies	0	2,841
Allowance for doubtful accounts	(5,800)	(12,100)
Inventories
Storage gas inventory	36,849	44,047
Materials and supplies	5,446	4,183
Liquified natural gas in storage	3,505	3,545
Regulatory asset	56,188	57,143
Income tax receivable	3,760	9,762
Deferred income taxes	19,718	21,986
Prepayments and other	6,336	4,422
Total current assets	179,394	247,316
Property, Plant and Equipment
Utility plant	1,395,454	1,358,266
Less accumulated depreciation	560,279	544,838
Utility plant, net	835,175	813,428
Other property, net	42	43
Other Assets
Regulatory asset	94,869	95,633
Deferred charges and other	10,681	10,380
Total other assets	105,550	106,013
TOTAL ASSETS	1,120,161	1,166,800
Current Liabilities
Notes payable to banks	25,000	15,000
Accounts payable	53,899	110,552
Affiliated Companies	24,867
Accrued taxes	24,689	26,861
Customers' deposits	23,563	23,950
Amounts due customers	21,828	21,065
Accrued wages and benefits	7,533	12,971
Regulatory liability	27,372	58,279
Other	9,516	9,250
Total current liabilities	218,267	277,928
Long-term debt	250,103	250,246
Deferred Credits and Other Liabilities
Pension and other postretirement liabilities	31,069	21,383
Regulatory liability	77,692	87,234
Long-term derivative instruments	0	3,070
Deferred income taxes	188,509	181,492
Other	760	709
Total deferred credits and other liabilities	298,030	293,888
Commitments and Contingencies
Shareholders' Equity
Preferred stock, cumulative $0.01 par value	0	0
Common shareholders' equity
Common stock, $0.01 par value	20	20
Premium on capital stock	31,682	31,682
Capital surplus	2,802	2,802
Retained earnings	319,257	310,234
Accumulated other comprehensive loss, net of tax
Total shareholders' equity	353,761	344,738
Total capitalization	603,864	594,984
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY	$ 1,120,161	$ 1,166,800

XML

Derivative Commodity Instruments

9 Months Ended

Sep. 30, 2012

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Derivative Commodity Instruments

DERIVATIVE COMMODITY INSTRUMENTS

Energen Resources Corporation, Energen's oil and gas subsidiary, recognizes all derivatives on the balance sheet and measures all derivatives at fair value. If a derivative is designated as a cash flow hedge, the effectiveness of the hedge, or the degree that the gain (loss) for the hedging instrument offsets the loss (gain) on the hedged item, is measured at each reporting period. The effective portion of the gain or loss on the derivative instrument is recognized in other comprehensive income (OCI) as a component of shareholders’ equity and subsequently reclassified as operating revenues when the forecasted transaction affects earnings. The ineffective portion of a derivative's change in fair value is required to be recognized in operating revenues immediately. All derivative transactions are included in operating activities on the consolidated condensed statements of cash flows.

Energen Resources periodically enters into derivative commodity instruments to hedge its exposure to price fluctuations on oil, natural gas and natural gas liquids production. In prior years, Alagasco entered into cash flow derivative commodity instruments to hedge its exposure to price fluctuations on its gas supply. Hedge transactions are pursuant to standing authorizations by the Board of Directors, which do not authorize speculative positions. Such instruments may include over-the-counter (OTC) swaps and basis hedges typically with investment and commercial banks and energy-trading firms. The Company is at risk for economic loss based upon the creditworthiness of its counterparties. Energen Resources was in a net gain position with eleven of its active counterparties at September 30, 2012. The five largest counterparty net gain positions at September 30, 2012, Macquarie Bank Limited, J Aron & Company, BP Corporation North America Inc., Shell Energy North America (US), L.P. and Citibank, N.A. constituted approximately $16.8 million, $9.7 million, $9.6 million, $8.5 million and $7.7 million, respectively, of Energen Resources’ net gain on fair value of derivatives. Energen Resources was in a net loss position with three of its active counterparties at September 30, 2012. The largest counterparty net loss position at September 30, 2012, Morgan Stanley Capital Group, Inc constituted approximately $24.3 million of Energen Resources’ net loss on fair value of derivatives.

The current policy of the Company is to not enter into agreements that require the posting of collateral. The Company has a few older agreements, none of which have active positions as of September 30, 2012, which include collateral posting requirements based on the amount of exposure and counterparty credit ratings. The majority of the Company’s counterparty agreements include provisions for net settlement of transactions payable on the same date and in the same currency. Most of the agreements include various contractual set-off rights, which may be exercised by the non-defaulting party in the event of an early termination due to a default.

The Company periodically enters into derivative transactions that do not qualify for cash flow hedge accounting but are considered by management to represent valid economic hedges and are accounted for as mark-to-market transactions. These economic hedges may include, but are not limited to, hedges on estimated future production not yet flowing, basis hedges without a corresponding New York Mercantile Exchange (NYMEX) hedge, and hedges on non-operated or other properties for which all of the necessary information to qualify for cash flow hedge accounting is either not readily available or subject to change. Derivatives that do not qualify for hedge treatment or are not designated as cash flow hedges are recorded at fair value with gains or losses recognized in operating revenues in the period of change.

The following tables detail the fair values of commodity contracts by business segment on the balance sheets:

(in thousands)	September 30, 2012
	Oil and Gas Operations				Natural Gas Distribution			Total
Derivative assets or (liabilities) designated as hedging instruments
Accounts receivable	$	76,354			$	—		$	76,354
Long-term asset derivative instruments	51,181				—			51,181
Total derivative assets	127,535				—			127,535
Accounts receivable	(33,476		)	*	—			(33,476		)
Long-term asset derivative instruments	(17,575		)	*	—			(17,575		)
Accounts payable	(12,471		)		—			(12,471		)
Long-term liability derivative instruments	(7,739		)		—			(7,739		)
Total derivative liabilities	(71,261		)		—			(71,261		)
Total derivatives designated	56,274				—			56,274
Derivative assets or (liabilities) not designated as hedging instruments
Accounts receivable	(6,603		)	*	—			(6,603		)
Long-term asset derivative instruments	9,531				—			9,531
Total derivative assets	2,928				—			2,928
Accounts payable	(4,476		)		(14,990		)	(19,466		)
Long-term liability derivative instruments	(1,316		)		—			(1,316		)
Total derivative liabilities	(5,792		)		(14,990		)	(20,782		)
Total derivatives not designated	(2,864		)		(14,990		)	(17,854		)
Total derivatives	$	53,410			$	(14,990	)	$	38,420

(in thousands)	December 31, 2011
	Oil and Gas Operations				Natural Gas Distribution			Total
Derivative assets or (liabilities) designated as hedging instruments
Accounts receivable	$	73,636			$	—		$	73,636
Long-term asset derivative instruments	75,982				—			75,982
Total derivative assets	149,618				—			149,618
Accounts receivable	(48,174		)	*	—			(48,174		)
Long-term asset derivative instruments	(36,341		)	*	—			(36,341		)
Accounts payable	(37,070		)		—			(37,070		)
Long-term liability derivative instruments	(20,386		)		—			(20,386		)
Total derivative liabilities	(141,971		)		—			(141,971		)
Total derivatives designated	7,647				—			7,647
Derivative assets or (liabilities) not designated as hedging instruments
Accounts receivable	(3,670		)	*	—			(3,670		)
Long-term asset derivative instruments	(8,585		)	*	—			(8,585		)
Total derivative assets	(12,255		)		—			(12,255		)
Accounts payable	(13,416		)		(56,804		)	(70,220		)
Long-term liability derivative instruments	(10,922		)		(3,070		)	(13,992		)
Total derivative liabilities	(24,338		)		(59,874		)	(84,212		)
Total derivatives not designated	(36,593		)		(59,874		)	(96,467		)
Total derivatives	$	(28,946	)		$	(59,874	)	$	(88,820	)

* Amounts classified in accordance with accounting guidance which permits offsetting fair value amounts recognized for multiple derivative instruments executed with the same counterparty under a master netting arrangement.

The Company had a net $22.0 million and a net $5.7 million deferred tax liability included in current and noncurrent deferred income taxes on the consolidated condensed balance sheets related to derivative items included in OCI as of September 30, 2012, and December 31, 2011, respectively.

Alagasco recognizes all derivatives at fair value as either assets or liabilities on the balance sheet. Any gains or losses are passed through to customers using the mechanisms of the GSA in compliance with Alagasco’s APSC-approved tariff and are recognized as a regulatory asset or regulatory liability.

The following table details the effect of derivative commodity instruments in cash flow hedging relationships on the financial statements:

(in thousands)	Location on Income Statement	Three months ended September 30, 2012			Three months ended September 30, 2011
Gain (loss) recognized in OCI on derivative (effective portion), net of tax of ($30.6) million and $105.7 million	—	$	(49,962	)	$	172,430
Gain reclassified from accumulated OCI into income (effective portion)	Operating revenues	$	15,998		$	11,207
Gain (loss) recognized in income on derivative (ineffective portion and amount excluded from effectiveness testing)	Operating revenues	$	(3,042	)	$	5,631

(in thousands)	Location on Income Statement	Nine months ended September 30, 2012			Nine months ended September 30, 2011
Gain recognized in OCI on derivative (effective portion), net of tax of $30.6 million and $76.6 million	—	$	49,961		$	125,005
Gain reclassified from accumulated OCI into income (effective portion)	Operating revenues	$	39,012		$	13,028
Gain (loss) recognized in income on derivative (ineffective portion and amount excluded from effectiveness testing)	Operating revenues	$	(1,372	)	$	3,240

The following table details the effect of derivative commodity instruments not designated as hedging instruments on the income statements:

(in thousands)	Location on Income Statement	Three months ended September 30, 2012			Three months ended September 30, 2011
Gain (loss) recognized in income on derivative	Operating revenues	$	(45,618	)	$	53,227

(in thousands)	Location on Income Statement	Nine months ended September 30, 2012		Nine months ended September 30, 2011
Gain recognized in income on derivative	Operating revenues	$	33,825	$	53,225

As of September 30, 2012, $20.2 million, net of tax, of deferred net gains on derivative instruments recorded in accumulated other comprehensive income are expected to be reclassified and reported in earnings as operating revenues during the next twelve-month period. The actual amount that will be reclassified to earnings over the next year could vary materially from this amount due to changes in market conditions. As of September 30, 2012, the Company had 2.0 billion, 5.6 billion and 9.7 billion cubic feet (Bcf) of natural gas hedges which expire during 2012, 2013 and 2014, respectively, that did not meet the definition of a cash flow hedge but are considered by the Company to be economic hedges. The Company had 1.2 million, 8.7 million and 5.4 million barrels (MMBbl) of oil and oil basis hedges which expire during 2012, 2013 and 2014, respectively, that did not meet the definition of a cash flow hedge but are considered by the Company to be economic hedges. The Company had 3.8 million and 1.6 million gallons (MMgal) of natural gas liquid hedges which expire during 2012 and 2013, respectively, that did not meet the definition of a cash flow hedge but are considered by the Company to be economic hedges. During 2011, the Company had a discontinuance of hedge accounting when Energen Resources determined it was probable certain forecasted volumes would not occur, which resulted in $46,000 after-tax gain being recognized into operating revenues during the nine months ended September 30, 2012.

Energen Resources entered into the following transactions for the remainder of 2012 and subsequent years:

Production Period	Total Hedged Volumes		Average Contract Price	Description
Natural Gas
2012	3.6	Bcf	$4.49 Mcf	NYMEX Swaps
	8.9	Bcf	$4.14 Mcf	Basin Specific Swaps - San Juan
	2.0	Bcf	$2.89 Mcf	Basin Specific Swaps - Permian
2013	12.7	Bcf	$4.82 Mcf	NYMEX Swaps
	32.8	Bcf	$4.56 Mcf	Basin Specific Swaps - San Juan
	4.6	Bcf	$3.45 Mcf	Basin Specific Swaps - Permian
2014	10.6	Bcf	$4.55 Mcf	NYMEX Swaps
	25.7	Bcf	$4.72 Mcf	Basin Specific Swaps - San Juan
	9.7	Bcf	$3.81 Mcf	Basin Specific Swaps - Permian
Gas Basis Differential
2012	0.1	Bcf	$(0.23) Mcf	San Juan Basis Swaps
Oil
2012	1,850	MBbl	$88.51 Bbl	NYMEX Swaps
2013	8,858	MBbl	$90.95 Bbl	NYMEX Swaps
2014	9,796	MBbl	$92.64 Bbl	NYMEX Swaps
Oil Basis Differential
2012	752	MBbl	$(2.95) Bbl	WTS/WTI Basis Swaps*
2013	3,592	MBbl	$(3.03) Bbl	WTS/WTI Basis Swaps*
	1,740	MBbl	$(1.13) Bbl	WTI/WTI Basis Swaps**
Natural Gas Liquids
2012	15.3	MMGal	$0.99 Gal	Liquids Swaps
2013	44.5	MMGal	$1.02 Gal	Liquids Swaps
*WTS - West Texas Sour/Midland, WTI - West Texas Intermediate/Cushing
**WTI - West Texas Intermediate/Midland, WTI - West Texas Intermediate/Cushing

Alagasco entered into the following natural gas transactions for the remainder of 2012 and subsequent years:

Production Period	Total Hedged Volumes		Description
2012	4.6	Bcf	NYMEX Swaps
2013	1.5	Bcf	NYMEX Swaps

As of September 30, 2012, the maximum term over which Energen Resources and Alagasco have hedged exposures to the variability of cash flows is through December 31, 2014, and March 31, 2013, respectively. Alagasco has not entered into any new cash flow derivative transactions on its gas supply since the summer of 2010. 

Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). All assets and liabilities are required to be classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Assessing the significance of a particular input may require judgment considering factors specific to the asset or liability, and may affect the valuation of the asset or liability and its placement within the fair value hierarchy. The fair value hierarchy that prioritizes the inputs used to measure fair value is as follows:

Level 1 - Unadjusted quoted prices in active markets for identical assets or liabilities;

Level 2 - Pricing inputs other than quoted prices in active markets included within Level 1, which are either directly or indirectly observable through correlation with market data as of the reporting date;

Level 3 - Pricing that requires inputs that are both significant and unobservable to the calculation of the fair value measure. The fair value measure represents estimates of the assumption that market value participants would use in pricing the asset or liability. Unobservable inputs are developed based on the best available information and subject to cost-benefit constraints.

Derivative commodity instruments are over-the-counter (OTC) derivatives valued using market transactions and other market evidence whenever possible, including market-based inputs to models and broker or dealer quotations. These OTC derivative contracts trade in less liquid markets with limited pricing information as compared to markets with actively traded, unadjusted quoted prices; accordingly, the determination of fair value is inherently more difficult. OTC derivatives for which the Company is able to substantiate fair value through directly observable market prices are classified within Level 2 of the fair value hierarchy. These Level 2 fair values consist of swaps priced in reference to NYMEX natural gas and oil futures. OTC derivatives valued using unobservable market prices have been classified within Level 3 of the fair value hierarchy. These Level 3 fair values include basin specific, basis and natural gas liquids swaps. The Company considers frequency of pricing and variability in pricing between sources in determining whether a market is considered active. While the Company does not have access to the specific assumptions used in its counterparties' valuation models, the Company maintains communications with its counterparties and discusses pricing practices. Further, the Company corroborates the fair value of its transactions by comparison of market-based price sources.

The following sets forth derivative assets and liabilities that were measured at fair value on a recurring basis:

	September 30, 2012
(in thousands)	Level 2*			Level 3*			Total
Current assets	$	(1,048	)	$	37,323		$	36,275
Noncurrent assets	18,133			25,004			43,137
Current liabilities	(30,588		)	(1,349		)	(31,937		)
Noncurrent liabilities	(5,358		)	(3,697		)	(9,055		)
Net derivative asset (liability)	$	(18,861	)	$	57,281		$	38,420

	December 31, 2011
(in thousands)	Level 2*			Level 3*			Total
Current assets	$	(14,843	)	$	36,635		$	21,792
Noncurrent assets	(8,382		)	39,438			31,056
Current liabilities	(98,468		)	(8,822		)	(107,290		)
Noncurrent liabilities	(32,928		)	(1,450		)	(34,378		)
Net derivative asset (liability)	$	(154,621	)	$	65,801		$	(88,820	)

* Amounts classified in accordance with accounting guidance which permits offsetting fair value amounts recognized for multiple derivative instruments executed with the same counterparty under a master netting arrangement.

As of September 30, 2012, Alagasco had $15.0 million of derivative instruments which are classified as Level 2 fair values and are included in the above table as current liabilities. As of December 31, 2011, Alagasco had $56.8 million and $3.1 million of derivative instruments which are classified as Level 2 fair values and are included in the above table as current and noncurrent liabilities, respectively. Alagasco had no derivative instruments classified as Level 3 fair values as of September 30, 2012, and December 31, 2011.

The Company has prepared a sensitivity analysis to evaluate the hypothetical effect that changes in the prices used to estimate fair value would have on the fair value of its derivative instruments. The Company estimates that a 10 percent increase or decrease in commodity prices would result in an approximate $35 million change in the fair value of open Level 3 derivative contracts. The resulting impact upon the results of operations would be an approximate $5.9 million associated with open Level 3 mark-to-market derivative contracts. Cash flow requirements to meet the obligation would not be significantly impacted as gains and losses on the derivative contracts would be similarly offset by sales at the spot market price.

The tables below set forth a summary of changes in the fair value of the Company’s Level 3 derivative commodity instruments as follows:

	Three months ended			Three months ended
(in thousands)	September 30, 2012			September 30, 2011
Balance at beginning of period	$	103,456		$	13,446
Realized gains	18,737			9,370
Unrealized gains (losses) relating to instruments held at the reporting date*	(46,983		)	23,953
Settlements during period	(17,929		)	(10,565		)
Balance at end of period	$	57,281		$	36,204

	Nine months ended			Nine months ended
(in thousands)	September 30, 2012			September 30, 2011
Balance at beginning of period	$	65,801		$	42,755
Realized gains	51,858			37,031
Unrealized losses relating to instruments held at the reporting date*	(9,328		)	(5,356		)
Settlements during period	(51,050		)	(38,226		)
Balance at end of period	$	57,281		$	36,204

*Includes $7.9 million and $4.5 million in mark-to-market losses for the three months and nine months ended September 30, 2012. Includes $0.1 million in mark-to-market gains for both the three months and nine months ended September 30, 2011.

The tables below set forth quantitative information about the Company’s Level 3 fair value measurements of derivative commodity instruments as follows:

(in thousands)	Fair Value as of September 30, 2012			Valuation Technique*	Unobservable Input*	Range
Natural Gas Basis - San Juan
2012	$	8,807		Discounted Cash Flow	Forward Basis	($0.10 - $0.12) Mcf
2013	$	27,968		Discounted Cash Flow	Forward Basis	($0.14 - $0.15) Mcf
2014	$	17,273		Discounted Cash Flow	Forward Basis	($0.14 - $0.16) Mcf
Natural Gas Basis - Permian
2012	$	(634	)	Discounted Cash Flow	Forward Basis	($0.08) Mcf
2013	$	(1,221	)	Discounted Cash Flow	Forward Basis	($0.13) Mcf
2014	$	(2,132	)	Discounted Cash Flow	Forward Basis	($0.13 - $0.15) Mcf
Oil Basis - WTS/WTI
2012	$	14		Discounted Cash Flow	Forward Basis	($2.74 - $2.81) Bbl
2013	$	(5,085	)	Discounted Cash Flow	Forward Basis	($1.59) Bbl
Oil Basis - WTI/WTI
2013	$	(379	)	Discounted Cash Flow	Forward Basis	($0.75 - $1.15) Bbl
Natural Gas Liquids
2012	$	3,594		Discounted Cash Flow	Forward Price	$0.75 - $0.89 Gal
2013	$	9,076		Discounted Cash Flow	Forward Price	$0.77 - $0.85 Gal

*Discounted cash flow represents an income approach in calculating fair value including the referenced unobservable input and a discount reflecting credit quality of the counterparty.

XML

Commitments and Contingencies Disclosure (Tables)

9 Months Ended

Sep. 30, 2012

Commitments and Contingencies Disclosure [Abstract]

Schedule of Future Minimum Lease Payments for Capital Leases [Table Text Block]

The following is a schedule of future minimum lease payments under capital leases together with the present value of the net minimum lease payments as of September 30, 2012:

(in thousands)
2012	$	436
2013	1,743
2014	1,743
2015	145
Total minimum lease payments	4,067
Less amount representing interest	93
Total present value of minimum lease payments	$	3,974

XML

Derivative Commodity Instruments - Quantitative Disclosures About Fair Value (Details) (Income Approach Valuation Technique [Member], Level 3, USD $)	3 Months Ended
	Sep. 30, 2012
Natural Gas Basis - San Juan [Member] | 2012
Fair Value Inputs, Derivatives, Quantitative Information [Line Items]
Fair Value as of June 30, 2012	$ 8,807,000
Natural Gas Basis - San Juan [Member] | 2012 | Minimum [Member]
Fair Value Inputs, Derivatives, Quantitative Information [Line Items]
Fair Value Inputs, Price Per Cubic Foot	0.10
Natural Gas Basis - San Juan [Member] | 2012 | Maximum [Member]
Fair Value Inputs, Derivatives, Quantitative Information [Line Items]
Fair Value Inputs, Price Per Cubic Foot	0.12
Natural Gas Basis - San Juan [Member] | 2013
Fair Value Inputs, Derivatives, Quantitative Information [Line Items]
Fair Value as of June 30, 2012	27,968,000
Natural Gas Basis - San Juan [Member] | 2013 | Minimum [Member]
Fair Value Inputs, Derivatives, Quantitative Information [Line Items]
Fair Value Inputs, Price Per Cubic Foot	0.14
Natural Gas Basis - San Juan [Member] | 2013 | Maximum [Member]
Fair Value Inputs, Derivatives, Quantitative Information [Line Items]
Fair Value Inputs, Price Per Cubic Foot	0.15
Natural Gas Basis - San Juan [Member] | 2014
Fair Value Inputs, Derivatives, Quantitative Information [Line Items]
Fair Value as of June 30, 2012	17,273,000
Natural Gas Basis - San Juan [Member] | 2014 | Minimum [Member]
Fair Value Inputs, Derivatives, Quantitative Information [Line Items]
Fair Value Inputs, Price Per Cubic Foot	0.14
Natural Gas Basis - San Juan [Member] | 2014 | Maximum [Member]
Fair Value Inputs, Derivatives, Quantitative Information [Line Items]
Fair Value Inputs, Price Per Cubic Foot	0.16
Natural Gas Basis - Permian [Member] | 2012
Fair Value Inputs, Derivatives, Quantitative Information [Line Items]
Fair Value as of June 30, 2012	(634)
Fair Value Inputs, Price Per Cubic Foot	0.08
Natural Gas Basis - Permian [Member] | 2013
Fair Value Inputs, Derivatives, Quantitative Information [Line Items]
Fair Value as of June 30, 2012	(1,221)
Fair Value Inputs, Price Per Cubic Foot	0.13
Natural Gas Basis - Permian [Member] | 2014
Fair Value Inputs, Derivatives, Quantitative Information [Line Items]
Fair Value as of June 30, 2012	(2,132)
Natural Gas Basis - Permian [Member] | 2014 | Minimum [Member]
Fair Value Inputs, Derivatives, Quantitative Information [Line Items]
Fair Value Inputs, Price Per Cubic Foot	0.13
Natural Gas Basis - Permian [Member] | 2014 | Maximum [Member]
Fair Value Inputs, Derivatives, Quantitative Information [Line Items]
Fair Value Inputs, Price Per Cubic Foot	0.15
Oil Basis - WTS/WTI [Member] | 2012
Fair Value Inputs, Derivatives, Quantitative Information [Line Items]
Fair Value as of June 30, 2012	14,000
Oil Basis - WTS/WTI [Member] | 2012 | Minimum [Member]
Fair Value Inputs, Derivatives, Quantitative Information [Line Items]
Fair Value Inputs, Price Per Barrel	2.74
Oil Basis - WTS/WTI [Member] | 2012 | Maximum [Member]
Fair Value Inputs, Derivatives, Quantitative Information [Line Items]
Fair Value Inputs, Price Per Barrel	2.81
Oil Basis - WTS/WTI [Member] | 2013
Fair Value Inputs, Derivatives, Quantitative Information [Line Items]
Fair Value as of June 30, 2012	(5,085,000)
Fair Value Inputs, Price Per Barrel	1.59
WTI/WTI Basis Swaps [Member] | 2013
Fair Value Inputs, Derivatives, Quantitative Information [Line Items]
Fair Value as of June 30, 2012	(379,000)
WTI/WTI Basis Swaps [Member] | 2013 | Minimum [Member]
Fair Value Inputs, Derivatives, Quantitative Information [Line Items]
Fair Value Inputs, Price Per Barrel	0.75
WTI/WTI Basis Swaps [Member] | 2013 | Maximum [Member]
Fair Value Inputs, Derivatives, Quantitative Information [Line Items]
Fair Value Inputs, Price Per Barrel	1.15
Natural Gas Liquids [Member] | 2012
Fair Value Inputs, Derivatives, Quantitative Information [Line Items]
Fair Value as of June 30, 2012	3,594,000
Natural Gas Liquids [Member] | 2012 | Minimum [Member]
Fair Value Inputs, Derivatives, Quantitative Information [Line Items]
Fair Value Inputs, Price Per Gallon	0.75
Natural Gas Liquids [Member] | 2012 | Maximum [Member]
Fair Value Inputs, Derivatives, Quantitative Information [Line Items]
Fair Value Inputs, Price Per Gallon	0.89
Natural Gas Liquids [Member] | 2013
Fair Value Inputs, Derivatives, Quantitative Information [Line Items]
Fair Value as of June 30, 2012	$ 9,076,000
Natural Gas Liquids [Member] | 2013 | Minimum [Member]
Fair Value Inputs, Derivatives, Quantitative Information [Line Items]
Fair Value Inputs, Price Per Gallon	0.77
Natural Gas Liquids [Member] | 2013 | Maximum [Member]
Fair Value Inputs, Derivatives, Quantitative Information [Line Items]
Fair Value Inputs, Price Per Gallon	0.85

XML

Recently Issued Accounting Standards

9 Months Ended

Sep. 30, 2012

New Accounting Pronouncements and Changes in Accounting Principles [Abstract]

Recently Issued Accounting Standards

RECENTLY ISSUED ACCOUNTING STANDARDS

In December 2011, the FASB issued Accounting Standard Update (ASU) No. 2011-11, Disclosures about Offsetting Assets and Liabilities. The amendments in this update require an entity to disclose information about offsetting and related arrangements to enable users of its financial statements to understand the effect of those arrangements on its financial position. The amendment is effective for annual reporting periods beginning on or after January 1, 2013, and interim periods within those annual periods. The Company is currently evaluating the impact of the ASU but does not expect this update to have a material impact on its results of operations.

In June 2011, the FASB issued ASU No. 2011-05, Presentation of Comprehensive Income. This update requires entities to present the components of net income and other comprehensive income either in a single continuous statement of comprehensive income or in two separate but consecutive statements. The amendments in this update do not change the items that must be reported in other comprehensive income or when an item of other comprehensive income must be reclassified to net income. In December 2011, the FASB issued ASU No. 2011-12, Deferral of the Effective Date for Amendments to the Presentation of Reclassifications of Items Out of Accumulated Other Comprehensive Income in Accounting Standards Update No. 2011-05, which indefinitely deferred the requirements to include reclassification adjustments for items that are reclassified from other comprehensive income to net income on the face of the financial statements. The amendments in these updates are effective for fiscal years, and interim periods within those years, beginning after December 15, 2011. Adoption of these updates has not had a material impact on the consolidated condensed financial statements or results of operations.

In May 2011, the FASB issued ASU No. 2011-04, Amendments to Achieve Common Fair Value Measurement and Disclosure Requirement in U.S. GAAP and International Financial Reporting Standards (IFRSs). The amendments in this update result in common fair value measurement and disclosure requirements in U.S. GAAP and IFRSs. The amendments are effective during interim and annual periods beginning after December 15, 2011. This standard did not have a material impact on the consolidated condensed financial statements of the Company. The additional fair value disclosures are included in Note 3, Derivative Commodity Instruments.