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 JUNE 30, 2011

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 July 27, 2011.

Energen Corporation	$0.01 par value	72,078,908 shares
Alabama Gas Corporation	$0.01 par value	1,972,052 shares

EXPLANATORY NOTE

This Amendment No. 1 to Energen's Quarterly Report on Form 10-Q for the quarter ended June 30, 2011, which was filed with the Securities and Exchange Commission on August 1, 2011 (the Original Filing), is being filed solely to amend the Original Filing to furnish our XBRL interactive data files as Exhibit 101, as required by Rule 405 of Regulations S-T. This amendment does not change or update the disclosures or amounts set forth in the Original Filing.

ITEM 6. EXHIBITS

*31(a)	-	Section 302 Energen Corporation Certification required by Rule 13a-14(a) or Rule 15d-14(a), which was filed as Exhibit 31(a) to Energen's Quarterly Report on Form 10-Q dated August 1, 2011
*31(b)	-	Section 302 Energen Corporation Certification required by Rule 13a-14(a) or Rule 15d-14(a) which was filed as Exhibit 31(b) to Energen's Quarterly Report on Form 10-Q dated August 1, 2011
*31(c)	-	Section 302 Alabama Gas Corporation Certification required by Rule 13a-14(a) or Rule 15d-14(a) which was filed as Exhibit 31(c) to Energen's Quarterly Report on Form 10-Q dated August 1, 2011
*31(d)	-	Section 302 Alabama Gas Corporation Certification required by Rule 13a-14(a) or Rule 15d-14(a) which was filed as Exhibit 31(d) to Energen's Quarterly Report on Form 10-Q dated August 1, 2011
*32(a)	-	Section 906 Energen Corporation Certification pursuant to 18 U.S.C. Section 1350 which was filed as Exhibit 32(a) to Energen's Quarterly Report on Form 10-Q dated August 1, 2011
*32(b)	-	Section 906 Alabama Gas Corporation Certification pursuant to 18 U.S.C. Section 1350 which was filed as Exhibit 32(b) to Energen's Quarterly Report on Form 10-Q dated August 1, 2011
101	-	The following financial statements from Energen Corporation's Quarterly Report on Form 10-Q for the quarter ended June 30, 2011, formatted in XBRL: (i) Consolidated Condensed Statements of Income, (ii) Consolidated Condensed Balance Sheets, (iii) Consolidated Condensed Statements of Cash Flows, (iv) the Notes to Unaudited Condensed Financial Statements.

* Incorporated by reference

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
August 26, 2011	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
August 26, 2011	By	/s/ Charles W. Porter, Jr.
		Charles W. Porter, Jr.
		Vice President, Chief Financial Officer and Treasurer of Energen Corporation and Alabama Gas Corporation
August 26, 2011	By	/s/ Russell E. Lynch, Jr.
		Russell E. Lynch, Jr.
		Vice President and Controller of Energen Corporation
August 26, 2011	By	/s/ William D. Marshall
		William D. Marshall
		Vice President and Controller of Alabama Gas Corporation

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Consolidated Condensed Balance Sheets (USD $) In Thousands	Jun. 30, 2011	Dec. 31, 2010
Current Assets
Cash and cash equivalents	$ 15,432	$ 22,659
Accounts receivable
Allowance for doubtful accounts	(13,558)	(15,048)
Accounts receivable, net of allowance for doubtful accounts of $13,558 at June 30, 2011, and $15,048 at December 31, 2010	164,031	286,849
Inventories
Storage gas inventory	34,632	36,706
Materials and supplies	27,038	19,045
Liquified natural gas in storage	3,693	3,551
Regulatory asset	32,563	28,286
Income tax receivable	5,264	44,489
Deferred income taxes	49,930	32,732
Prepayments and other	10,353	11,966
Total current assets	342,936	486,283
Property, Plant and Equipment
Oil and gas properties, successful efforts method	4,461,460	4,080,779
Less accumulated depreciation, depletion and amortization	1,256,178	1,161,635
Oil and gas properties, net	3,205,282	2,919,144
Utility plant	1,322,695	1,292,611
Less accumulated depreciation	523,051	509,989
Utility plant, net	799,644	782,622
Other property, net	23,117	17,461
Total property, plant and equipment, net	4,028,043	3,719,227
Other Assets
Regulatory asset	89,465	105,365
Pension and other postretirement assets	11,947	13,907
Long-term derivative instruments	1,002	0
Deferred charges and other	38,001	38,778
Total other assets	140,415	158,050
TOTAL ASSETS	4,511,394	4,363,560
Current Liabilities
Long-term debt due within one year	5,000	5,000
Notes payable to banks	302,000	305,000
Accounts payable	263,142	268,214
Accrued taxes	42,783	52,845
Customers' deposits	21,471	20,459
Amounts due customers	10,407	20,161
Accrued wages and benefits	27,985	25,203
Regulatory liability	65,024	75,703
Royalty payable	23,228	19,221
Other	23,275	26,805
Total current liabilities	784,315	818,611
Long-term debt	404,980	405,254
Deferred Credits and Other Liabilities
Asset retirement obligation	102,120	97,415
Pension and other postretirement liabilities	34,248	36,551
Regulatory liability	92,951	110,447
Long-term derivative instruments	128,505	112,936
Deferred income taxes	697,540	615,084
Other	9,297	13,219
Total deferred credits and other liabilities	1,064,661	985,652
Commitments and Contingencies
Shareholders' Equity
Preferred stock, cumulative $0.01 par value	0	0
Common shareholders' equity
Common stock, $0.01 par value	750	748
Premium on capital stock	480,559	468,934
Capital surplus	2,802	2,802
Retained earnings	2,018,318	1,880,183
Accumulated other comprehensive loss, net of tax
Unrealized loss on hedges, net	(90,738)	(43,667)
Pension and postretirement plans	(29,365)	(30,730)
Deferred compensation plan	3,468	3,288
Treasury stock, at cost; 3,036,997 shares at June 30, 2011, and 3,024,847 shares at December 31, 2010	(128,356)	(127,515)
Total shareholders' equity	2,257,438	2,154,043
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY	4,511,394	4,363,560
Alabama Gas Corporation
Current Assets
Cash and cash equivalents	13,739	16,910
Accounts receivable
Gas	52,084	136,800
Other	11,268	10,229
Affiliated companies	2,140	698
Allowance for doubtful accounts	(12,700)	(14,200)
Inventories
Storage gas inventory	34,632	36,706
Materials and supplies	4,160	4,147
Liquified natural gas in storage	3,693	3,551
Regulatory asset	32,563	28,286
Income tax receivable	2,077	10,315
Deferred income taxes	25,759	27,302
Prepayments and other	1,771	4,223
Total current assets	171,186	264,967
Property, Plant and Equipment
Utility plant	1,322,695	1,292,611
Less accumulated depreciation	523,051	509,989
Utility plant, net	799,644	782,622
Other property, net	43	43
Other Assets
Regulatory asset	89,465	105,365
Pension and other postretirement assets	7,800	9,201
Deferred charges and other	4,833	5,399
Total other assets	102,098	119,965
TOTAL ASSETS	1,072,971	1,167,597
Current Liabilities
Long-term debt due within one year	5,000	5,000
Notes payable to banks	0	70,000
Accounts payable	71,504	83,515
Accrued taxes	35,872	48,476
Customers' deposits	21,471	20,459
Amounts due customers	10,407	20,161
Accrued wages and benefits	10,345	11,851
Regulatory liability	65,024	75,703
Other	10,154	11,822
Total current liabilities	229,777	346,987
Long-term debt	200,500	200,793
Deferred Credits and Other Liabilities
Pension and other postretirement liabilities	4,190	4,733
Regulatory liability	92,951	110,447
Long-term derivative instruments	17,657	32,461
Deferred income taxes	170,004	141,780
Other	834	3,077
Total deferred credits and other liabilities	285,636	292,498
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	322,554	292,815
Accumulated other comprehensive loss, net of tax
Total shareholders' equity	357,058	327,319
Total capitalization	557,558	528,112
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY	$ 1,072,971	$ 1,167,597

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Consolidated Condensed Balance Sheets (Parenthetical) (USD $) In Thousands, except Share data	Jun. 30, 2011	Dec. 31, 2010
Current Assets
Allowance for doubtful accounts	$ 13,558	$ 15,048
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	74,989,460	74,786,376
Treasury stock, shares	3,036,997	3,024,847
Alabama Gas Corporation
Current Assets
Allowance for doubtful accounts	$ 12,700	$ 14,200
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

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Comprehensive Income (Tables)

6 Months Ended

Jun. 30, 2011

Statement of Income and Comprehensive Income [Abstract]

Schedule of Comprehensive Income (Loss)

	Three months ended
	June 30,
(in thousands)	2011		2010
Net income	$	63,325	$	55,543
Other comprehensive income (loss):
Current period change in fair value of derivative instruments, net of tax of $30.3 million and $26.3 million	49,449		42,917
Reclassification adjustment for derivative instruments, net of tax of $2.5 million and ($21.6) million	4,037		(35,241		)
Pension and postretirement plans, net of tax of $0.4 million and $0.3 million	683		630
Comprehensive income	$	117,494	$	63,849

	Six months ended
	June 30,
(in thousands)	2011			2010
Net income	$	157,593		$	172,253
Other comprehensive income (loss):
Current period change in fair value of derivative instruments, net of tax of ($29.1) million and $60.3 million	(47,425		)	98,385
Reclassification adjustment for derivative instruments, net of tax of $0.2 million and ($36.2) million	354			(59,066		)
Pension and postretirement plans, net of tax of $0.7 million and $0.7 million	1,365			1,258
Comprehensive income	$	111,887		$	212,830

Schedule of Accumulated Other Comprehensive Income (Loss)

(in thousands)	June 30, 2011			December 31, 2010
Unrealized loss on hedges, net of tax of ($55.6) million and ($26.8) million	$	(90,738	)	$	(43,667	)
Pension and postretirement plans, net of tax of ($15.8) million and ($16.5) million	(29,365		)	(30,730		)
Accumulated other comprehensive loss	$	(120,103	)	$	(74,397	)

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Document and Entity Information	6 Months Ended
	Jun. 30, 2011	Jul. 27, 2011
Entity Information
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Jun. 30, 2011
Document Fiscal Year Focus	2011
Document Fiscal Period Focus	Q2
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		72,078,908
Alabama Gas Corporation
Entity Information
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Jun. 30, 2011
Document Fiscal Year Focus	2011
Document Fiscal Period Focus	Q2
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

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Acquisition and Dispositions of Oil and Gas Properties (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended		6 Months Ended		1 Months Ended								1 Months Ended	6 Months Ended			1 Months Ended	6 Months Ended
	Jun. 30, 2011	Jun. 30, 2010	Jun. 30, 2011	Jun. 30, 2010	Dec. 31, 2010 Oil Reserves Dec 15, 2010, Permian Basin	Sep. 30, 2010 Oil Reserves Sep 30, 2010, Permian Basin	Dec. 31, 2010 Natural Gas Liquids Reserves Dec 15, 2010, Permian Basin	Sep. 30, 2010 Natural Gas Liquids Reserves Sep 30, 2010, Permian Basin	Dec. 31, 2010 Natural Gas Reserves Dec 15, 2010, Permian Basin	Sep. 30, 2010 Natural Gas Reserves Sep 30, 2010, Permian Basin	Jul. 31, 2011 July 2011, Permian Basin	Apr. 30, 2011 April 2011, Permian Basin A	Dec. 31, 2010 Dec 15, 2010, Permian Basin	Jun. 30, 2011 Dec 15, 2010, Permian Basin	Dec. 15, 2010 Dec 15, 2010, Permian Basin Boe	Dec. 09, 2010 Dec 9, 2010, Permian Basin Boe	Sep. 30, 2010 Sep 30, 2010, Permian Basin Boe	Jun. 30, 2011 Sep 30, 2010, Permian Basin
Significant Acquisitions and Disposals [Line Items]
Consideration - Purchase Price											$ 20,000	$ 37,000			$ 73,630	$ 103,000	$ 188,314
Gas and Oil Acreage, Undeveloped, Net												11,000
Proved Developed and Undeveloped Reserves, Net															7,600,000	0	18
Percentage of Undeveloped Portion of Proved Reserves													92.00%				89.00%
Acquired Proved Reserves by Type of Reserve, Percentage					62.00%	65.00%	24.00%	22.00%	14.00%	13.00%
Recognized amounts of identifiable assets acquired and liabilities assumed
Proved properties															41,066		151,747
Unproved leasehold properties															32,500		35,360
Accounts receivable															143		1,461
Asset retirement obligation															(79)		(142)
Accounts payable																	(112)
Total identifiable net assets															73,630		188,314
Operating revenues	330,399	333,725	816,763	908,639										2,000				19,200
Operating income	$ 106,335	$ 98,293	$ 266,216	$ 290,491										$ 500				$ 9,600

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

6 Months Ended

Jun. 30, 2011

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)	June 30, 2011				December 31, 2010
	Current		Noncurrent		Current		Noncurrent
Regulatory assets:
Pension and postretirement assets	$	170	$	58,469	$	132	$	60,284
Accretion and depreciation for asset retirement obligation	—		8,898		—		8,681
Risk management activities	32,159		17,657		27,906		32,461
RSE adjustment	25		—		25		—
Enhanced stability reserve	—		4,395		—		3,794
Other	209		46		223		145
Total regulatory assets	$	32,563	$	89,465	$	28,286	$	105,365
Regulatory liabilities:
RSE adjustment	$	7,696	$	—	$	4,147	$	—
Unbilled service margin	6,957		—		34,197		—
Postretirement liabilities	—		959		—		754
Gas supply adjustment	29,695		—		14,990		—
Asset removal costs, net	—		7,665		—		6,913
Refundable negative salvage	20,643		71,896		22,336		90,504
Asset retirement obligation	—		11,611		—		11,439
Other	33		820		33		837
Total regulatory liabilities	$	65,024	$	92,951	$	75,703	$	110,447

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Asset Retirement Obligations (Details) (USD $) In Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2011	Jun. 30, 2010	Jun. 30, 2011	Jun. 30, 2010	Dec. 31, 2010
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Balance of ARO, beginning			$ 97,415
Liabilities incurred			2,291
Liabilities settled			(924)
Accretion expense	1,689	1,521	3,338	3,007
Balance of ARO, end	102,120		102,120
Regulatory Liability, Current	65,024		65,024		75,703
Regulatory Liability, Noncurrent	92,951		92,951		110,447
Alabama Gas Corporation | Asset removal costs
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Regulatory Liability, Current	0		0		0
Regulatory Liability, Noncurrent	7,665		7,665		6,913
Alabama Gas Corporation | Refundable negative salvage
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Regulatory Liability, Current	20,643		20,643		22,336
Regulatory Liability, Noncurrent	71,896		71,896		90,504
Refundable negative salvage
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Regulatory Liability, Current	20,643		20,643
Regulatory Liability, Noncurrent	71,896		71,896
Alabama Gas Corporation
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Balance of ARO, beginning					11,400
Balance of ARO, end	11,600		11,600		11,400
Regulatory Liability, Current	65,024		65,024		75,703
Regulatory Liability, Noncurrent	$ 92,951		$ 92,951		$ 110,447

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Stock Compensation

6 Months Ended

Jun. 30, 2011

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, or a combination thereof to officers and key employees. On April 27, 2011, the Company amended the Stock Incentive Plan to increase the number of shares authorized for issuance by 3,000,000 shares. This increase resulted in 3,794,326 shares being available for future issuances. Options granted under the 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 293,978 non-qualified option shares during the first quarter of 2011 with a grant-date fair value of $19.65.

2004 Stock Appreciation Rights Plan

The Energen 2004 Stock Appreciation Rights Plan provides for the payment of cash incentives measured by the long-term appreciation of Company stock. These awards are liability awards which settle in cash and are re-measured each reporting period until settlement and have a three year vesting period. The Company granted 189,984 awards during the first quarter of 2011. These awards had a fair value of $20.86 as of June 30, 2011.

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 2011, Energen Resources awarded 5,076 Petrotech units with a three-year vesting period. These awards had a fair value of $55.17 as of June 30, 2011.

1997 Deferred Compensation Plan

During the three months and six months ended June 30, 2011, the Company had noncash purchases of approximately $26,000 and $0.4 million, 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.

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Asset Retirement Obligations (Tables)

6 Months Ended

Jun. 30, 2011

Asset Retirement Obligation Disclosure [Abstract]

Schedule of Change in Asset Retirement Obligation

During the six months ended June 30, 2011, 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, 2010	$	97,415
Liabilities incurred	2,291
Liabilities settled	(924		)
Accretion expense	3,338
Balance of ARO as of June 30, 2011	$	102,120

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Commitments and Contingencies (Details) - New Mexico Audits (Unfavorable Regulatory Action, USD $)	3 Months Ended
	Jun. 30, 2011
Unfavorable Regulatory Action
Loss Contingencies [Line Items]
Loss Contingency, Range of Possible Loss, Minimum	$ 142,000
Loss Contingency, Range of Possible Loss, Maximum	$ 20,000,000
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 Department's findings and the ONRR Order. 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, 2011.

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Comprehensive Income (Details) (USD $)	3 Months Ended		6 Months Ended
	Jun. 30, 2011	Jun. 30, 2010	Jun. 30, 2011	Jun. 30, 2010	Dec. 31, 2010
Net income	$ 63,325,000	$ 55,543,000	$ 157,593,000	$ 172,253,000
Current period change in fair value of derivative instruments, net of tax	49,449,000	42,917,000	(47,425,000)	98,385,000
Reclassification adjustment for derivative instruments, net of tax	4,037,000	(35,241,000)	354,000	(59,066,000)
Pension and postretirement plans, net of tax	683,000	630,000	1,365,000	1,258,000
Comprehensive income	117,494,000	63,849,000	111,887,000	212,830,000
Current period change in fair value of derivative instruments, tax	30,300,000	26,300,000	(29,100,000)	60,300,000
Reclassification adjustement for derivative instruments, tax	2,500,000	(21,600,000)	200,000	(36,200,000)
Pension and postretirement plans, tax	400,000	300,000	700,000	700,000
Accumulated other comprehensive loss, net of tax
Unrealized loss on hedges, net	(90,738,000)		(90,738,000)		(43,667,000)
Pension and postretirement plans	(29,365,000)		(29,365,000)		(30,730,000)
Accumulated other comprehensive loss	(120,103,000)		(120,103,000)		(74,397,000)
Unrealized loss on hedges, tax	(55,600,000)		(55,600,000)		(26,800,000)
Pension and postretirement plans, tax	$ (15,800,000)		$ (15,800,000)		$ (16,500,000)

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Financial Instruments (Tables)

6 Months Ended

Jun. 30, 2011

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, 2010	$	447
Provision	80
Allowance for credit losses as of June 30, 2011	$	527

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Asset Retirement Obligations

6 Months Ended

Jun. 30, 2011

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 six months ended June 30, 2011, 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, 2010	$	97,415
Liabilities incurred	2,291
Liabilities settled	(924		)
Accretion expense	3,338
Balance of ARO as of June 30, 2011	$	102,120

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 $11.6 million and $11.4 million to purge and cap its gas pipelines upon abandonment, as a regulatory liability as of June 30, 2011, and December 31, 2010, respectively. The conditional asset retirement obligations reflect the re-estimation of removal costs associated with Alagasco’s revised depreciation rate. 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 liabilities for accumulated asset removal costs of $7.7 million and $6.9 million for June 30, 2011, and December 31, 2010, respectively, are included as regulatory liabilities in deferred credits and other liabilities on the balance sheets. As of June 30, 2011, the Company recognized $20.6 million and $71.9 million of refundable negative salvage as regulatory liabilities in current liabilities and deferred credit and other liabilities, respectively, on the balance sheet in response to the June 28, 2010, APSC order.

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Derivative Commodity Instruments

6 Months Ended

Jun. 30, 2011

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 that qualify as cash flow hedges to hedge its exposure to price fluctuations on oil, natural gas and natural gas liquids production. In addition, Alagasco periodically enters into cash flow derivative commodity instruments to hedge its exposure to price fluctuations on its gas supply. Such instruments may include over-the-counter (OTC) swaps and basis hedges with major energy derivative product specialists. The counterparties to the commodity instruments are investment 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 loss position with ten of its active counterparties and in a net gain position with the remaining one at June 30, 2011. The four largest counterparty positions at June 30, 2011, Morgan Stanley Capital Group, Inc., Citibank, N.A., J Aron & Company and Shell Energy North America (US), L.P., constituted approximately $57.9 million, $36.2 million, $20.8 million and $20.2 million, respectively, of Energen Resources’ net loss on fair value of derivatives. Barclays Bank PLC was the only counterparty in a gain position of $6.7 million.

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 June 30, 2011, 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 may also enter 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, basis hedges without a corresponding New York Mercantile Exchange 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 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)	June 30, 2011
	Oil and Gas Operations				Natural Gas Distribution			Total
Derivative assets or (liabilities) designated as hedging instruments
Accounts receivable	$	49,182			$	—		$	49,182
Long-term asset derivative instruments	10,427			*	—			10,427
Total derivative assets	59,609				—			59,609
Accounts receivable	(37,177		)	*	—			(37,177		)
Accounts payable	(54,926		)		—			(54,926		)
Long-term liability derivative instruments	(120,273		)		—			(120,273		)
Total derivative liabilities	(212,376		)		—			(212,376		)
Total derivatives designated	(152,767		)		—			(152,767		)
Derivative assets or (liabilities) not designated as hedging instruments
Accounts payable	(68		)		(32,159		)	(32,227		)
Long-term liability derivative instruments	—				(17,657		)	(17,657		)
Total derivative liabilities	(68		)		(49,816		)	(49,884		)
Total derivatives not designated	(68		)		(49,816		)	(49,884		)
Total derivatives	$	(152,835	)		$	(49,816	)	$	(202,651	)

(in thousands)	December 31, 2010
	Oil and Gas Operations				Natural Gas Distribution			Total
Derivative assets or (liabilities) designated as hedging instruments
Accounts receivable	$	85,867			$	—		$	85,867
Long-term asset derivative instruments	3,156			*	—			3,156
Total derivative assets	89,023				—			89,023
Accounts receivable	(25,315		)	*	—			(25,315		)
Accounts payable	(50,508		)		—			(50,508		)
Long-term liability derivative instruments	(83,631		)		—			(83,631		)
Total derivative liabilities	(159,454		)		—			(159,454		)
Total derivatives designated	(70,431		)		—			(70,431		)
Derivative assets or (liabilities) not designated as hedging instruments
Accounts payable	(110		)		(27,906		)	(28,016		)
Long-term liability derivative instruments	—				(32,461		)	(32,461		)
Total derivative liabilities	(110		)		(60,367		)	(60,477		)
Total derivatives not designated	(110		)		(60,367		)	(60,477		)
Total derivatives	$	(70,541	)		$	(60,367	)	$	(130,908	)

* 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 $55.6 million and a net $26.8 million deferred tax asset included in current and noncurrent deferred income taxes on the consolidated condensed balance sheets related to derivative items included in OCI as of June 30, 2011, and December 31, 2010, respectively.

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

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 June 30, 2011			Three months ended June 30, 2010
Gain recognized in OCI on derivative (effective portion), net of tax of $30.3 million and $26.3 million	—	$	49,449		$	42,917
Gain (loss) reclassified from accumulated OCI into income (effective portion)	Operating revenues	$	(5,770	)	$	56,666
Gain (loss) recognized in income on derivative (ineffective portion and amount excluded from effectiveness testing)	Operating revenues	$	(740	)	$	175

(in thousands)	Location on Income Statement	Six months ended June 30, 2011			Six months ended June 30, 2010
Gain (loss) recognized in OCI on derivative (effective portion), net of tax of ($29.1) million and $60.3 million	—	$	(47,425	)	$	98,385
Gain reclassified from accumulated OCI into income (effective portion)	Operating revenues	$	1,821		$	93,390
Gain (loss) recognized in income on derivative (ineffective portion and amount excluded from effectiveness testing)	Operating revenues	$	(2,391	)	$	1,879

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 June 30, 2011			Three months ended June 30, 2010
Loss recognized in income on derivative	Operating revenues	$	(1	)	$	(1	)
(in thousands)	Location on Income Statement	Six months ended June 30, 2011			Six months ended June 30, 2010
Loss recognized in income on derivative	Operating revenues	$	(1	)	$	(4	)

As of June 30, 2011, $22.6 million, net of tax, of deferred net losses 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 June 30, 2011, the Company had 7 thousand barrels (MBbl) of oil hedges which expire during 2011 that did not meet the definition of a cash flow hedge but are considered by the Company to be economic hedges.

Energen Resources entered into the following transactions for the remainder of 2011 and subsequent years:

Production Period	Total Hedged Volumes	Average Contract Price	Description
Natural Gas
2011	7.1 Bcf	$6.47 Mcf	NYMEX Swaps
	19.4 Bcf	$5.65 Mcf	Basin Specific Swaps
2012	11.0 Bcf	$5.07 Mcf	NYMEX Swaps
	29.5 Bcf	$4.60 Mcf	Basin Specific Swaps
2013	8.8 Bcf	$5.30 Mcf	NYMEX Swaps
	25.1 Bcf	$4.88 Mcf	Basin Specific Swaps
2014	3.0 Bcf	$5.72 Mcf	NYMEX Swaps
	6.0 Bcf	$5.34 Mcf	Basin Specific Swaps
Oil
2011	2,242 MBbl	$80.47 Bbl	NYMEX Swaps
2012	3,881 MBbl	$83.53 Bbl	NYMEX Swaps
2013	3,296 MBbl	$85.97 Bbl	NYMEX Swaps
2014	2,818 MBbl	$87.92 Bbl	NYMEX Swaps
Oil Basis Differential
2011	1,103 MBbl	*	Basis Swaps
2012	753 MBbl	*	Basis Swaps
Natural Gas Liquids
2011	21.1 MMGal	$0.90 Gal	Liquids Swaps
2012	39.9 MMGal	$0.86 Gal	Liquids Swaps
2013	35.2 MMGal	$1.02 Gal	Liquids Swaps
* Average contract prices are not meaningful due to the varying nature of each contract.

Alagasco entered into the following natural gas transactions for the remainder of 2011 and subsequent years:

Production Period	Total Hedged Volumes	Description
2011	6.0 Bcf	NYMEX Swaps
2012	17.2 Bcf	NYMEX Swaps
2013	1.5 Bcf	NYMEX Swaps

As of June 30, 2011, the maximum term over which Energen Resources and Alagasco have hedged exposures to the variability of cash flows is through December 31, 2014, and December 31, 2013, respectively.

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). 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.

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 New York Mercantile Exchange (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 liquids swaps.

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

	June 30, 2011
(in thousands)	Level 2*			Level 3*			Total
Current assets	$	(7,773	)	$	19,778		$	12,005
Noncurrent assets	78			$	924		$	1,002
Current liabilities	(81,752		)	(5,401		)	(87,153		)
Noncurrent liabilities	(126,650		)	(1,855		)	(128,505		)
Net derivative asset (liability)	$	(216,097	)	$	13,446		$	(202,651	)

	December 31, 2010
(in thousands)	Level 2*			Level 3*			Total
Current assets	$	10,316		$	50,236		$	60,552
Current liabilities	(76,527		)	(1,997		)	(78,524		)
Noncurrent liabilities	(107,452		)	(5,484		)	(112,936		)
Net derivative asset (liability)	$	(173,663	)	$	42,755		$	(130,908	)

* 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 June 30, 2011, Alagasco had $32.2 million and $17.7 million of derivative instruments which are classified as Level 2 fair values and are included in the above table as current liabilities and noncurrent liabilities, respectively. As of December 31, 2010, Alagasco had $27.9 million and $32.5 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 June 30, 2011, and December 31, 2010.

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)	June 30, 2011			June 30, 2010
Balance at beginning of period	$	16,927		$	114,440
Realized (gains) losses	1,204			(303		)
Unrealized gains (losses) relating to instruments held at the reporting date	7,720			9,215
Settlements during period	(12,405		)	(31,535		)
Balance at end of period	$	13,446		$	91,817

	Six months ended			Six months ended
(in thousands)	June 30, 2011			June 30, 2010
Balance at beginning of period	$	42,755		$	64,517
Realized (gains) losses	1,204			(303		)
Unrealized gains (losses) relating to instruments held at the reporting date	(3,554		)	75,886
Settlements during period	(26,959		)	(48,283		)
Balance at end of period	$	13,446		$	91,817

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Reconciliation of Earnings Per Share (Details) - Earnings Per Share Reconciliation (USD $) In Thousands, except Per Share data	3 Months Ended		6 Months Ended
	Jun. 30, 2011	Jun. 30, 2010	Jun. 30, 2011	Jun. 30, 2010
Earnings Per Share Reconciliation
Net Income, Basic EPS	$ 63,325	$ 55,543	$ 157,593	$ 172,253
Basic Shares Oustanding (in shares)	72,065	71,844	72,033	71,830
Earnings Per Share, Basic (dollars per share)	$ 0.88	$ 0.77	$ 2.19	$ 2.40
Effect of dilutive securities
Net Income, Diluted EPS	$ 63,325	$ 55,543	$ 157,593	$ 172,253
Diluted Shares Outstanding (in shares)	72,420	72,089	72,364	72,069
Earnings Per Share, Diluted (dollars per share)	$ 0.87	$ 0.77	$ 2.18	$ 2.39
Stock options
Effect of dilutive securities
Incremental Common Shares Attributable to Share-based Payment Arrangements	347	228	324	223
Non-vested restricted stock
Effect of dilutive securities
Incremental Common Shares Attributable to Share-based Payment Arrangements	8	17	7	16

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Commitments and Contingencies

6 Months Ended

Jun. 30, 2011

Commitments and Contingencies Disclosure [Abstract]

Commitments and Contingencies

COMMITMENTS AND CONTINGENCIES    

Commitments and Agreements: Certain of Alagasco's long-term contracts associated with the delivery and storage of natural gas include fixed charges of approximately $126 million through September 2024. During the six months ending June 30, 2011 and 2010, Alagasco recognized approximately $25.8 million and $26.8 million, respectively, 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 222 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 June 30, 2011, the fixed price purchases under these guarantees had a maximum term outstanding through March 2012 and an aggregate purchase price of $2.0 million with a market value of $2.0 million.

Income Taxes: Energen and its subsidiaries' 2007 and 2008 federal consolidated income tax returns have been under Internal Revenue Service (IRS) examination. In September 2010, the IRS made certain assessments primarily related to Alagasco’s tax accounting method change for the recovery of its gas distribution property. The Company subsequently filed a petition in United States Tax Court challenging the IRS assessment. During the second quarter of 2011, the Company entered into a settlement agreement with the IRS. Under this settlement, Alagasco will be allowed the full repair tax deductions as originally claimed in the 2007 and 2008 federal income tax returns. The Chief Judge of the United States Tax Court signed and entered the Decision putting this settlement agreement into effect on June 16, 2011.

During the quarter, the Company recognized a $2.1 million income tax benefit related to changes in Alabama state income tax laws. In addition, the Company recognized a $1.5 million net benefit for the release of the unrecognized income tax benefit liability due to the Company's settlement with the IRS discussed above. These benefits were partially offset by $1.9 million of income tax expense for additional unrecognized tax benefit liabilities. 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.

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. Remediation of the Huntsville, Alabama, manufactured gas plant site, as discussed below, may also result in unanticipated costs.

Alagasco is in the chain of title of nine former manufactured gas plant sites (four of which it still owns), and five manufactured gas distribution sites (one of which it still owns). Subject to the following paragraph discussing the Huntsville, Alabama manufactured gas plant site, an investigation of the sites does not indicate the present need for 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 June 2009, Alagasco received a General Notice Letter from the United States Environmental Protection Agency (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 have entered into a Consent Order, developed an action plan for the site and as of June 30, 2011, had substantially completed the action plan. Based on information available at this time, Alagasco estimates that it may incur costs associated with the site of approximately $4.7 million, including costs previously incurred. During the three months and six months ended June 30, 2011, the Company incurred costs of $2.0 million and $3.0 million, respectively, associated with the site. As of June 30, 2011, the Company has accrued a contingent liability of $0.8 million in addition to the costs previously incurred. The action plan provided for excavation of affected soil and sediment only. If it is determined that further work is appropriate, then actual costs will likely exceed the estimate. Alagasco expects to recover such costs through future rates and has recorded a corresponding amount to its Enhanced Stability Reserve regulatory asset account.

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 $20 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 Department's findings and the ONRR Order. 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, 2011.

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Recently Issued Accounting Standards

6 Months Ended

Jun. 30, 2011

New Accounting Pronouncements and Changes in Accounting Principles [Abstract]

Recently Issued Accounting Standards

RECENTLY ISSUED ACCOUNTING STANDARDS

In June 2011, the FASB issued ASU No. 2011-05, Comprehensive Income (Topic 220): Presentation of Comprehensive Income. These amendments require that all nonowner changes in stockholders’ equity be presented either in a single continuous statement of comprehensive income or in two separate but consecutive statements. The amendments are effective for fiscal years, and interim periods within those years, beginning after December 15, 2011. The Company is currently evaluating the impact of the ASU.

In May 2011, the FASB issued ASU No. 2011-04, Fair Value Measurement (Topic 820): 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. The Company is currently evaluating the impact of the ASU.

In July 2010, the FASB issued ASU No. 2010-20, Receivables (Topic 310): Disclosures about the Credit Quality of Financing Receivables and the Allowance for Credit Losses. These disclosures, as of the end of a reporting period, are effective for the interim and annual reporting periods ending on or after December 15, 2010. The disclosures about activity that occurs during a reporting period are effective for interim and annual reporting periods beginning on or after December 15, 2010. The disclosures required under this standard have been included in Note 10, Financial Instruments.

On January 1, 2010, the Company adopted Accounting Standard Update (ASU) No. 2010-06, Fair Value Measurements and Disclosures (Topic 820): Improving Disclosures About Fair Value Measurements. These disclosures are effective for the first interim or annual reporting period beginning after December 15, 2009, except for the gross presentation of the Level 3 roll forward, which is required for annual reporting periods beginning after December 15, 2010, and for interim reporting periods within those years. The disclosures required under this standard have been included in Note 3, Derivative Commodity Instruments.

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Financial Instruments

6 Months Ended

Jun. 30, 2011

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 $443.4 million and has a carrying value of $410.5 million at June 30, 2011. The fair value of Alagasco's fixed-rate long-term debt, including the current portion, approximates $213.9 million and has a carrying value of $205.5 million at June 30, 2011. The fair values were based on market prices of similar debt issues having the same remaining maturities, redemption terms and credit rating.

Finance Receivables: Alagasco finances third-party contractor sales of merchandise including gas furnaces and appliances. At June 30, 2011, and December 31, 2010, Alagasco’s finance receivable totaled $9.6 million and $8.8 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 $361,000 as of June 30, 2011.

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, 2010	$	447
Provision	80
Allowance for credit losses as of June 30, 2011	$	527

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Derivative Commodity Instruments (Details) - Fair Value Derivatives (USD $) In Thousands	Jun. 30, 2011		Dec. 31, 2010
Derivatives, Fair Value [Line Items]
Derivative, Fair Value, Net	$ (202,651)		$ (130,908)
Oil and Gas Operations
Derivatives, Fair Value [Line Items]
Derivative, Fair Value, Net	(152,835)		(70,541)
Oil and Gas Operations | Designated as Hedging Instrument
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	59,609		89,023
Derivative Liability, Fair Value, Net	(212,376)		(159,454)
Derivative, Fair Value, Net	(152,767)		(70,431)
Oil and Gas Operations | Designated as Hedging Instrument | Accounts receivable
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	49,182		85,867
Derivative Liability, Fair Value, Gross Asset	(37,177)	[1]	(25,315)	[1]
Oil and Gas Operations | Designated as Hedging Instrument | Accounts Payable
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	(54,926)		(50,508)
Oil and Gas Operations | Designated as Hedging Instrument | Other Assets
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	10,427	[1]	3,156	[1]
Oil and Gas Operations | Designated as Hedging Instrument | Other Liabilities
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	(120,273)		(83,631)
Oil and Gas Operations | Not Designated as Hedging Instrument
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	(68)		(110)
Derivative, Fair Value, Net	(68)		(110)
Oil and Gas Operations | Not Designated as Hedging Instrument | Accounts Payable
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	(68)		(110)
Oil and Gas Operations | Not Designated as Hedging Instrument | Other Liabilities
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	0		0
Natural Gas Distribution
Derivatives, Fair Value [Line Items]
Derivative, Fair Value, Net	(49,816)		(60,367)
Natural Gas Distribution | Designated as Hedging Instrument
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	0		0
Derivative Liability, Fair Value, Net	0		0
Derivative, Fair Value, Net	0		0
Natural Gas Distribution | Designated as Hedging Instrument | Accounts receivable
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	0		0
Derivative Liability, Fair Value, Gross Asset	0		0
Natural Gas Distribution | Designated as Hedging Instrument | Accounts Payable
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	0		0
Natural Gas Distribution | Designated as Hedging Instrument | Other Assets
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	0		0
Natural Gas Distribution | Designated as Hedging Instrument | Other Liabilities
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	0		0
Natural Gas Distribution | Not Designated as Hedging Instrument
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	(49,816)		(60,367)
Derivative, Fair Value, Net	(49,816)		(60,367)
Natural Gas Distribution | Not Designated as Hedging Instrument | Accounts Payable
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	(32,159)		(27,906)
Natural Gas Distribution | Not Designated as Hedging Instrument | Other Liabilities
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	(17,657)		(32,461)
Designated as Hedging Instrument
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	59,609		89,023
Derivative Liability, Fair Value, Net	(212,376)		(159,454)
Derivative, Fair Value, Net	(152,767)		(70,431)
Designated as Hedging Instrument | Accounts receivable
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	49,182		85,867
Derivative Liability, Fair Value, Gross Asset	(37,177)		(25,315)
Designated as Hedging Instrument | Accounts Payable
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	(54,926)		(50,508)
Designated as Hedging Instrument | Other Assets
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	10,427		3,156
Designated as Hedging Instrument | Other Liabilities
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	(120,273)		(83,631)
Not Designated as Hedging Instrument
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	(49,884)		(60,477)
Derivative, Fair Value, Net	(49,884)		(60,477)
Not Designated as Hedging Instrument | Accounts Payable
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	(32,227)		(28,016)
Not Designated as Hedging Instrument | Other Liabilities
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	$ (17,657)		$ (32,461)

[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.

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Employee Benefit Plans

6 Months Ended

Jun. 30, 2011

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 June 30,						Six months ended June 30,
(in thousands)	2011			2010			2011			2010
Components of net periodic benefit cost:
Service cost	$	2,293		$	2,144		$	4,586		$	4,287
Interest cost	2,740			2,841			5,480			5,683
Expected long-term return on assets	(3,868		)	(3,229		)	(7,736		)	(6,458		)
Actuarial loss	1,609			1,443			3,218			2,887
Prior service cost amortization	124			124			248			248
Net periodic expense	$	2,898		$	3,323		$	5,796		$	6,647

The Companyanticipates required contributions of approximately $7.2 million during 2011 to the pension plans. The Company expects sufficient funding credits, as established under Internal Revenue Code Section 430(f), exist to meet the required funding. It is not anticipated that the funded status of the 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 2011. For the three months and six months ending June 30, 2011, the Company made benefit payments aggregating $36,000 and $2.2 million, respectively, to retirees from the nonqualified supplemental retirement plans and expects to make additional benefit payments of approximately $71,000 through the remainder of 2011.

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

	Three months ended June 30,						Six months ended June 30,
(in thousands)	2011			2010			2011			2010
Components of net periodic benefit cost:
Service cost	$	442		$	516		$	885		$	1,032
Interest cost	1,111			1,208			2,222			2,417
Expected long-term return on assets	(1,104		)	(996		)	(2,209		)	(1,993		)
Transition amortization	479			479			958			958
Net periodic expense	$	928		$	1,207		$	1,856		$	2,414

For the three months and six months ended June 30, 2011, the Company made contributions aggregating $0.9 million and $1.9 million, respectively, to the postretirement benefit plan assets. The Company expects to make additional discretionary contributions of approximately $1.9 million to postretirement benefit plan assets through the remainder of 2011. During the first quarter of 2010, the Company recognized $128,000 in income tax expense resulting from a reduction in deferred tax asset related to changes in the tax treatment for the Medicare Part D subsidy under the recently enacted health care reform legislation.

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Basis of Presentation

6 Months Ended

Jun. 30, 2011

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, 2010, 2009 and 2008, included in the 2010 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 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 consisted of normal recurring items.

During the first quarter of 2010, Alagasco identified an error in calculating the estimate of the allowance for doubtful accounts as of December 31, 2009. This error resulted in a $3 million overstatement to the allowance for doubtful accounts and a corresponding overstatement of net income by approximately $0.6 million (approximately $0.01 per diluted share) after reflecting the regulatory limits on Alagasco’s allowed rate of return for rate year ending September 30, 2010, in the application of Rate Stabilization and Equalization. The Company considered the net impact of this adjustment on the prior quarterly and year-end results, and the results of Alagasco and Energen for the year ended December 31, 2010, and determined that the amount was not material to these periods. The Company corrected this error in the first quarter of 2010.

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Reconciliation of Earnings Per Share (EPS)

6 Months Ended

Jun. 30, 2011

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)	June 30, 2011					June 30, 2010
	Net			Per Share		Net			Per Share
	Income		Shares	Amount		Income		Shares	Amount
Basic EPS	$	63,325	72,065	$	0.88	$	55,543	71,844	$	0.77
Effect of dilutive securities
Stock options			347					228
Non-vested restricted stock			8					17
Diluted EPS	$	63,325	72,420	$	0.87	$	55,543	72,089	$	0.77

	Six months ended					Six months ended
(in thousands, except per share amounts)	June 30, 2011					June 30, 2010
	Net			Per Share		Net			Per Share
	Income		Shares	Amount		Income		Shares	Amount
Basic EPS	$	157,593	72,033	$	2.19	$	172,253	71,830	$	2.40
Effect of dilutive securities
Stock options			324					223
Non-vested restricted stock			7					16
Diluted EPS	$	157,593	72,364	$	2.18	$	172,253	72,069	$	2.39

For the three months and six months ended June 30, 2011, the Company had no options that were excluded from the computation of diluted EPS. For the three months and six months ended June 30, 2010, the Company had 472,560 options that were excluded from the computation of diluted EPS. For the three months and six months ended June 30, 2011 and 2010, the Company had no shares of non-vested restricted stock that were excluded from the computation of diluted EPS.

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Employee Benefit Plans (Details) (USD $)	3 Months Ended			6 Months Ended		3 Months Ended		6 Months Ended
	Mar. 31, 2010	Jun. 30, 2011 Pension Plans	Jun. 30, 2010 Pension Plans	Jun. 30, 2011 Pension Plans	Jun. 30, 2010 Pension Plans	Jun. 30, 2011 Postretirement Benefit Plans	Jun. 30, 2010 Postretirement Benefit Plans	Jun. 30, 2011 Postretirement Benefit Plans	Jun. 30, 2010 Postretirement Benefit Plans
Components of net periodic benefit cost:
Service cost		$ 2,293,000	$ 2,144,000	$ 4,586,000	$ 4,287,000	$ 442,000	$ 516,000	$ 885,000	$ 1,032,000
Interest cost		2,740,000	2,841,000	5,480,000	5,683,000	1,111,000	1,208,000	2,222,000	2,417,000
Expected long-term return on assets		(3,868,000)	(3,229,000)	(7,736,000)	(6,458,000)	(1,104,000)	(996,000)	(2,209,000)	(1,993,000)
Actuarial loss		1,609,000	1,443,000	3,218,000	2,887,000
Prior service cost amortization		124,000	124,000	248,000	248,000
Transition amortization						479,000	479,000	958,000	958,000
Net periodic expense		2,898,000	3,323,000	5,796,000	6,647,000	928,000	1,207,000	1,856,000	2,414,000
Estimated Future Employer Contributions in Current Fiscal Year		7,200,000		7,200,000		1,900,000		1,900,000
Benefit Payments Made in Current Fiscal Year		36,000		2,200,000
Estimated Future Benefit Payments in Current Fiscal Year		71,000
Contributions by Employer in Current Fiscal Year						900,000		1,900,000
Income Tax Expense, Tax Treatement for Medicare Part D subsidy	$ 128,000

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Derivative Commodity Instruments (Details) - Derivatives (USD $)	3 Months Ended			6 Months Ended
	Jun. 30, 2011		Jun. 30, 2010	Jun. 30, 2011		Jun. 30, 2010	Dec. 31, 2010
Derivative [Line Items]
Derivative Instruments, Gain (Loss) Recognized in Other Comprehensive Income (Loss), Effective Portion, Net	$ 49,449,000		$ 42,917,000	$ (47,425,000)		$ 98,385,000
Deferred Tax Assets, Derivative Instruments	55,600,000			55,600,000			26,800,000
Derivative Assets and Liabilities, Measured at Fair Value, on Recurring Basis
Noncurrent assets	1,002,000			1,002,000			0
Noncurrent liabilities	(128,505,000)			(128,505,000)			(112,936,000)
Alabama Gas Corporation | Cash Flow Hedges | 2011 | Natural Gas | NYMEX Swaps
Derivative [Line Items]
Total hedged Volumes	6.0			6.0
Alabama Gas Corporation | Cash Flow Hedges | 2012 | Natural Gas | NYMEX Swaps
Derivative [Line Items]
Total hedged Volumes	17.2			17.2
Alabama Gas Corporation | Cash Flow Hedges | 2013 | Natural Gas | NYMEX Swaps
Derivative [Line Items]
Total hedged Volumes	1.5			1.5
Cash Flow Hedges | Morgan Stanley Capital Group, Inc.
Derivative [Line Items]
Derivative, Net Loss Position	57,900,000			57,900,000
Cash Flow Hedges | Citibank, N.A. [Member]
Derivative [Line Items]
Derivative, Net Loss Position	36,200,000			36,200,000
Cash Flow Hedges | J Aron and Company [Member]
Derivative [Line Items]
Derivative, Net Loss Position	20,800,000			20,800,000
Cash Flow Hedges | Shell Energy North America US, L.P. [Member]
Derivative [Line Items]
Derivative, Net Loss Position	20,200,000			20,200,000
Cash Flow Hedges | Barclays Bank PLC [Member]
Derivative [Line Items]
Derivative, Net Gain Position	6,700,000			6,700,000
Cash Flow Hedges | 2011 | Natural Gas | NYMEX Swaps
Derivative [Line Items]
Total hedged Volumes	7.1			7.1
Average Contract Price, Per Mcf	6.47			6.47
Cash Flow Hedges | 2011 | Natural Gas | Basin Specific Swaps
Derivative [Line Items]
Total hedged Volumes	19.4			19.4
Average Contract Price, Per Mcf	5.65			5.65
Cash Flow Hedges | 2011 | Crude Oil | NYMEX Swaps
Derivative [Line Items]
Total hedged Volumes	2,242			2,242
Average Contract Price, Per Gal	80.47			80.47
Cash Flow Hedges | 2011 | Crude Oil | Basis Swap
Derivative [Line Items]
Total hedged Volumes	1,103			1,103
Average Contract Price, Per Gal		[1]			[1]
Cash Flow Hedges | 2011 | Natural Gas Liquids | Liquids Swaps
Derivative [Line Items]
Total hedged Volumes	21.1			21.1
Average Contract Price, Per Bbl	0.90			0.90
Cash Flow Hedges | 2012 | Natural Gas | NYMEX Swaps
Derivative [Line Items]
Total hedged Volumes	11.0			11.0
Average Contract Price, Per Mcf	5.07			5.07
Cash Flow Hedges | 2012 | Natural Gas | Basin Specific Swaps
Derivative [Line Items]
Total hedged Volumes	29.5			29.5
Average Contract Price, Per Mcf	4.60			4.60
Cash Flow Hedges | 2012 | Crude Oil | NYMEX Swaps
Derivative [Line Items]
Total hedged Volumes	3,881			3,881
Average Contract Price, Per Gal	83.53			83.53
Cash Flow Hedges | 2012 | Crude Oil | Basis Swap
Derivative [Line Items]
Total hedged Volumes	753			753
Average Contract Price, Per Gal		[1]			[1]
Cash Flow Hedges | 2012 | Natural Gas Liquids | Liquids Swaps
Derivative [Line Items]
Total hedged Volumes	39.9			39.9
Average Contract Price, Per Bbl	0.86			0.86
Cash Flow Hedges | 2013 | Natural Gas | NYMEX Swaps
Derivative [Line Items]
Total hedged Volumes	8.8			8.8
Average Contract Price, Per Mcf	5.30			5.30
Cash Flow Hedges | 2013 | Natural Gas | Basin Specific Swaps
Derivative [Line Items]
Total hedged Volumes	25.1			25.1
Average Contract Price, Per Mcf	4.88			4.88
Cash Flow Hedges | 2013 | Crude Oil | NYMEX Swaps
Derivative [Line Items]
Total hedged Volumes	3,296			3,296
Average Contract Price, Per Gal	85.97			85.97
Cash Flow Hedges | 2013 | Natural Gas Liquids | Liquids Swaps
Derivative [Line Items]
Total hedged Volumes	35.2			35.2
Average Contract Price, Per Bbl	1.02			1.02
Cash Flow Hedges | 2014 | Natural Gas | NYMEX Swaps
Derivative [Line Items]
Total hedged Volumes	3.0			3.0
Average Contract Price, Per Mcf	5.72			5.72
Cash Flow Hedges | 2014 | Natural Gas | Basin Specific Swaps
Derivative [Line Items]
Total hedged Volumes	6.0			6.0
Average Contract Price, Per Mcf	5.34			5.34
Cash Flow Hedges | 2014 | Crude Oil | NYMEX Swaps
Derivative [Line Items]
Total hedged Volumes	2,818			2,818
Average Contract Price, Per Gal	87.92			87.92
Fair Value Hedging | Crude Oil
Derivative [Line Items]
Total hedged Volumes	7,000			7,000
Alabama Gas Corporation
Derivative Assets and Liabilities, Measured at Fair Value, on Recurring Basis
Noncurrent liabilities	(17,657,000)			(17,657,000)			(32,461,000)
Alabama Gas Corporation | Level 2 | Fair Value, Measurements, Recurring
Derivative Assets and Liabilities, Measured at Fair Value, on Recurring Basis
Current liabilities	(32,200,000)			(32,200,000)			(27,900,000)
Noncurrent liabilities	(17,700,000)			(17,700,000)			(32,500,000)
Level 2 | Fair Value, Measurements, Recurring
Derivative Assets and Liabilities, Measured at Fair Value, on Recurring Basis
Current assets	(7,773,000)	[2]		(7,773,000)	[2]		10,316,000	[2]
Noncurrent assets	78,000	[2]		78,000	[2]
Current liabilities	(81,752,000)	[2]		(81,752,000)	[2]		(76,527,000)	[2]
Noncurrent liabilities	(126,650,000)	[2]		(126,650,000)	[2]		(107,452,000)	[2]
Net derivative asset (liability)	(216,097,000)	[2]		(216,097,000)	[2]		(173,663,000)	[2]
Level 3 | Fair Value, Measurements, Recurring
Derivative Assets and Liabilities, Measured at Fair Value, on Recurring Basis
Current assets	19,778,000	[2]		19,778,000	[2]		50,236,000	[2]
Noncurrent assets	924,000	[2]		924,000	[2]
Current liabilities	(5,401,000)	[2]		(5,401,000)	[2]		(1,997,000)	[2]
Noncurrent liabilities	(1,855,000)	[2]		(1,855,000)	[2]		(5,484,000)	[2]
Net derivative asset (liability)	13,446,000	[2]		13,446,000	[2]		42,755,000	[2]
Fair Value, Measurements, Recurring
Derivative Assets and Liabilities, Measured at Fair Value, on Recurring Basis
Current assets	12,005,000			12,005,000			60,552,000
Noncurrent assets	1,002,000			1,002,000
Current liabilities	(87,153,000)			(87,153,000)			(78,524,000)
Noncurrent liabilities	(128,505,000)			(128,505,000)			(112,936,000)
Net derivative asset (liability)	$ (202,651,000)			$ (202,651,000)			$ (130,908,000)

[1] Average contract prices are not meaningful due to the varying nature of each contract.

[2] 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.

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Segment Information

6 Months Ended

Jun. 30, 2011

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						Six months ended
	June 30,						June 30,
(in thousands)	2011			2010			2011			2010
Operating revenues
Oil and gas operations	$	244,090		$	234,586		$	460,882		$	472,200
Natural gas distribution	86,309			99,139			355,881			436,439
Total	$	330,399		$	333,725		$	816,763		$	908,639
Operating income (loss)
Oil and gas operations	$	105,418		$	95,456		$	190,477		$	212,741
Natural gas distribution	1,163			3,138			76,222			78,393
Eliminations and corporate expenses	(246		)	(301		)	(483		)	(643		)
Total	$	106,335		$	98,293		$	266,216		$	290,491
Other income (expense)
Oil and gas operations	$	(5,822	)	$	(6,555	)	$	(11,269	)	$	(12,426	)
Natural gas distribution	(3,040		)	(3,702		)	(5,953		)	(6,763		)
Eliminations and other	65			(548		)	88			(762		)
Total	$	(8,797	)	$	(10,805	)	$	(17,134	)	$	(19,951	)
Income before income taxes	$	97,538		$	87,488		$	249,082		$	270,540

(in thousands)	June 30, 2011		December 31, 2010
Identifiable assets
Oil and gas operations	$	3,404,189	$	3,160,601
Natural gas distribution	1,070,831		1,166,899
Eliminations and other	36,374		36,060
Total	$	4,511,394	$	4,363,560

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Commitments and Contingencies (Details) - Environmental Matters (Alabama Gas Corporation, USD $) In Millions	3 Months Ended	6 Months Ended
	Jun. 30, 2011	Jun. 30, 2011
Alabama Gas Corporation
Site Contingency [Line Items]
Environmental Remediation Estimated Cost	$ 4.7
Environmental Remediation Expense	2.0	3.0
Accrual for Environmental Loss Contingencies	$ 0.8	$ 0.8

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Acquisition and Dispositions of Oil and Gas Properties (Tables)

6 Months Ended

Jun. 30, 2011

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 December 15, 2010, (including the effects of closing adjustments).

(in thousands)
Consideration given
Cash (net)	$	73,630
Recognized amounts of identifiable assets acquired and liabilities assumed
Proved properties	$	41,066
Unproved leasehold properties	32,500
Accounts receivable	143
Asset retirement obligation	(79		)
Total identifiable net assets	$	73,630

The following table summarizes the consideration paid and the amounts of the assets acquired and liabilities assumed recognized as of September 30, 2010, (including the effects of closing adjustments).

(in thousands)
Consideration given
Cash (net)	$	188,314
Recognized amounts of identifiable assets acquired and liabilities assumed
Proved properties	$	151,747
Unproved leasehold properties	35,360
Accounts receivable	1,461
Asset retirement obligation	(142		)
Accounts payable	(112		)
Total identifiable net assets	$	188,314

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Derivative Commodity Instruments (Details) - Derivative Instruments by Income Statement Location (USD $)	3 Months Ended		6 Months Ended
	Jun. 30, 2011	Jun. 30, 2010	Jun. 30, 2011	Jun. 30, 2010
Derivative Instruments, Gain (Loss) [Line Items]
Gain recognized in OCI on derivative (effective portion), net of tax	$ 49,449,000	$ 42,917,000	$ (47,425,000)	$ 98,385,000
Gain (loss) recognized in OCI on derivative (effective portion), Tax	30,300,000	26,300,000	(29,100,000)	60,300,000
Derivative Instruments, Gain (Loss) Reclassification from Accumulated OCI to Income, Estimated Net Amount to be Transferred	22,600,000
Operating revenues
Derivative Instruments, Gain (Loss) [Line Items]
Gain (loss) reclassified from accumulated OCI into income (effective portion)	(5,770,000)	56,666,000	1,821,000	93,390,000
Gain (loss) recognized in income on derivative (ineffective portion and amount excluded from effectiveness testing)	(740,000)	175,000	(2,391,000)	1,879,000
Loss recongnized in income on derivative	$ (1,000)	$ (1,000)	$ (1,000)	$ (4,000)

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Commitments and Contingencies (Details) - Commitments and Agreements (USD $) In Millions, unless otherwise specified	3 Months Ended	6 Months Ended
	Jun. 30, 2011	Jun. 30, 2011	Jun. 30, 2010
Long-term Purchase Commitment [Line Items]
Recorded Unconditional Purchase Obligation, Time Period	March 2012
Alabama Gas Corporation | Natural Gas [Member]
Long-term Purchase Commitment [Line Items]
Long-term Purchase Commitment, Time Period	August 2020
Long-term Purchase Commitment, Minimum Quantity Required	222
Recorded Unconditional Purchase Obligation	$ 2.0	$ 2.0
Recorded Unconditional Purchase Obligation, Market Value	2.0	2.0
Alabama Gas Corporation | Natural Gas, Delivery and Storage [Member]
Long-term Purchase Commitment [Line Items]
Long-term Purchase Commitment, Amount	126
Long-term Purchase Commitment, Time Period	September 2024
Long Term Commitments Expense Recognized in Statements of Operations		$ 25.8	$ 26.8

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Regulatory Matters (Details) (USD $)	1 Months Ended		3 Months Ended		6 Months Ended		12 Months Ended
	Dec. 31, 2010	Dec. 31, 2009	Jun. 30, 2011	Jun. 30, 2010	Jun. 30, 2011	Jun. 30, 2010	Jun. 30, 2011	Sep. 30, 2010	Dec. 31, 1998
Regulatory Matters [Line Items]
Regulatory Assets, Noncurrent	$ 105,365,000		$ 89,465,000		$ 89,465,000		$ 89,465,000
Alabama Gas Corporation | Enhanced stability reserve
Regulatory Matters [Line Items]
Regulatory Assets, Noncurrent	3,794,000		4,395,000		4,395,000		4,395,000
Alabama Gas Corporation
Regulatory Matters [Line Items]
Enahanced Stability Reserve Extension Period					7 years
Revenue Impact of Rate Adjustments	1,300,000	10,200,000	2,200,000	1,800,000	5,400,000	10,600,000
Adjustment Requirement Threshold for Return on Equity as Percentage of Operations and Maintenance Expenses to Consumer Price Index					0.75
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.
Extraordinary Bad Debt Expense, Excluded from CCM Calculation								2,500,000
Negative Revenue Variance, Large Commercial and Industrial Customer Budget, Minimum Amount, Charged to Enhanced Stability Reserve									250,000
Accretion to Enhanced Stability Reserve, Monthly									40,000
Amortization Expense, Enhanced Stability Reserve, Annual Amount					660,000
Enahanced Stability Reserve Amortization Period							5 years
Enhanced Stability Reserve Refund Period							9 years
Regulatory Assets, Noncurrent	105,365,000		89,465,000		89,465,000		89,465,000
Alabama Gas Corporation | 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
Accretion to Enhanced Stability Reserve, Monthly					55,000
Alabama Gas Corporation | 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
Alabama Gas Corporation | 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
Alabama Gas Corporation | 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
Alabama Gas Corporation | Force Majeure Event Costs
Regulatory Matters [Line Items]
Extraordinary Operating and Maintenance Expenses, Minimum Amount, Charged to Enhanced Stability Reserve									200,000
Alabama Gas Corporation | Minimum
Regulatory Matters [Line Items]
Allowed Return on Average Common Equity					13.15%
Alabama Gas Corporation | 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%
Enhanced Stability Reserve									$ 4,000,000

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Acquisition and Dispositions of Oil and Gas Properties

6 Months Ended

Jun. 30, 2011

Acquisition and Dispositions of Oil and Gas Properties Abstract

Acquisition and Dispositions of Oil and Gas Properties

ACQUISITION AND DISPOSITIONS OF OIL AND GAS PROPERTIES

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.

On December 15, 2010, Energen completed the purchase of certain properties in the Permian Basin for a cash purchase price of $74 million. This purchase had an effective date of December 1, 2010. Energen acquired proved reserves of approximately 7.6 million barrels of oil equivalents (MMBOE). Of the proved reserves acquired, an estimated 92 percent are undeveloped. Approximately 62 percent of the acquisition’s estimated proved reserves are oil, 24 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 December 15, 2010, (including the effects of closing adjustments).

(in thousands)
Consideration given
Cash (net)	$	73,630
Recognized amounts of identifiable assets acquired and liabilities assumed
Proved properties	$	41,066
Unproved leasehold properties	32,500
Accounts receivable	143
Asset retirement obligation	(79		)
Total identifiable net assets	$	73,630

Included in the Company’s consolidated results of operations for the six months ended June 30, 2011, are $2.0 million of operating revenues and $0.5 million in operating income resulting from the operation of the properties acquired above.

On December 9, 2010, Energen completed the asset purchase of certain liquids-rich properties in the Permian Basin from SandRidge Energy, Inc. for a cash purchase price of $103 million (subject to closing adjustments). This purchase had an effective date of December 9, 2010. Energen acquired no proved reserves related to this acquisition. Energen Resources used its credit facilities and internally generated cash flows to finance the acquisition.

On September 30, 2010, Energen completed the purchase of certain properties in the Permian Basin for a cash price of $188 million. This purchase had an effective date of September 1, 2010. Energen acquired proved reserves of approximately 18 MMBOE. Of the proved reserves acquired, an estimated 89 percent are undeveloped. Approximately 65 percent of the proved reserves are oil, 22 percent are natural gas liquids and natural gas comprises the remaining 13 percent. Energen Resources used its 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 September 30, 2010, (including the effects of closing adjustments).

(in thousands)
Consideration given
Cash (net)	$	188,314
Recognized amounts of identifiable assets acquired and liabilities assumed
Proved properties	$	151,747
Unproved leasehold properties	35,360
Accounts receivable	1,461
Asset retirement obligation	(142		)
Accounts payable	(112		)
Total identifiable net assets	$	188,314

Included in the Company’s consolidated results of operations for the six months ended June 30, 2011, are $19.2 million of operating revenues and $9.6 million in operating income resulting from the operation of the properties acquired above.

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Comprehensive Income (Loss)

6 Months Ended

Jun. 30, 2011

Statement of Income and Comprehensive Income [Abstract]

Comprehensive Income (Loss)

COMPREHENSIVE INCOME (LOSS)

Comprehensive income (loss) consisted of the following:

	Three months ended
	June 30,
(in thousands)	2011		2010
Net income	$	63,325	$	55,543
Other comprehensive income (loss):
Current period change in fair value of derivative instruments, net of tax of $30.3 million and $26.3 million	49,449		42,917
Reclassification adjustment for derivative instruments, net of tax of $2.5 million and ($21.6) million	4,037		(35,241		)
Pension and postretirement plans, net of tax of $0.4 million and $0.3 million	683		630
Comprehensive income	$	117,494	$	63,849

	Six months ended
	June 30,
(in thousands)	2011			2010
Net income	$	157,593		$	172,253
Other comprehensive income (loss):
Current period change in fair value of derivative instruments, net of tax of ($29.1) million and $60.3 million	(47,425		)	98,385
Reclassification adjustment for derivative instruments, net of tax of $0.2 million and ($36.2) million	354			(59,066		)
Pension and postretirement plans, net of tax of $0.7 million and $0.7 million	1,365			1,258
Comprehensive income	$	111,887		$	212,830

(in thousands)	June 30, 2011			December 31, 2010
Unrealized loss on hedges, net of tax of ($55.6) million and ($26.8) million	$	(90,738	)	$	(43,667	)
Pension and postretirement plans, net of tax of ($15.8) million and ($16.5) million	(29,365		)	(30,730		)
Accumulated other comprehensive loss	$	(120,103	)	$	(74,397	)

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Reconciliation of Earnings Per Share (Tables)

6 Months Ended

Jun. 30, 2011

Earnings Per Share [Abstract]

Schedule of Earnings Per Share Reconciliation

	Three months ended					Three months ended
(in thousands, except per share amounts)	June 30, 2011					June 30, 2010
	Net			Per Share		Net			Per Share
	Income		Shares	Amount		Income		Shares	Amount
Basic EPS	$	63,325	72,065	$	0.88	$	55,543	71,844	$	0.77
Effect of dilutive securities
Stock options			347					228
Non-vested restricted stock			8					17
Diluted EPS	$	63,325	72,420	$	0.87	$	55,543	72,089	$	0.77

	Six months ended					Six months ended
(in thousands, except per share amounts)	June 30, 2011					June 30, 2010
	Net			Per Share		Net			Per Share
	Income		Shares	Amount		Income		Shares	Amount
Basic EPS	$	157,593	72,033	$	2.19	$	172,253	71,830	$	2.40
Effect of dilutive securities
Stock options			324					223
Non-vested restricted stock			7					16
Diluted EPS	$	157,593	72,364	$	2.18	$	172,253	72,069	$	2.39

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Stock Compensation (Details) (USD $)	6 Months Ended	3 Months Ended		3 Months Ended		6 Months Ended	3 Months Ended	6 Months Ended	3 Months Ended	6 Months Ended
	Jun. 30, 2011	Mar. 31, 2011 Stock Incentive Plan	Apr. 27, 2011 Stock Incentive Plan	Jun. 30, 2011 Stock Appreciation Rights Plan	Mar. 31, 2011 Stock Appreciation Rights Plan	Jun. 30, 2011 Stock Appreciation Rights Plan	Jun. 30, 2011 Petrotech Incentive Plan	Jun. 30, 2011 Petrotech Incentive Plan	Jun. 30, 2011 Deferred Compensation Plan	Jun. 30, 2011 Deferred Compensation Plan
Share-based Compensation Arrangement by Share-based Payment Award
Number of Shares Authorized			3,000,000
Number of Shares Available for Grant			3,794,326
Grants in Period, Options		293,978
Grants in Period, Options, Fair Value		$ 19.65
Grants in Period, Other than Options					189,984			5,076
Grants in Period, Other than Options, Fair Value				$ 20.86			$ 55.17
Vesting Period	vest within three years from date of grant					three year vesting period		three-year vesting period
Expiration Date	P10Y
Noncash Payments for Repurchase of Common Stock									$ 26,000	$ 400,000

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Basis of Presentation (Details) (Alabama Gas Corporation, USD $) In Millions, except Per Share data	3 Months Ended
	Mar. 31, 2010
Overstatement to allowance for doubtful accounts
Quantifying Misstatement in Current Year Financial Statements [Line Items]
Quantifying Misstatement in Current Year Financial Statements, Amount	$ 3.0
Overstatement of net income
Quantifying Misstatement in Current Year Financial Statements [Line Items]
Quantifying Misstatement in Current Year Financial Statements, Amount	$ 0.6
Earnings Per Share, Diluted
Quantifying Misstatement in Current Year Financial Statements [Line Items]
Quantifying Misstatement in Current Year Financial Statements, Per Share	$ 0.01

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Consolidated Condensed Statements of Cash Flows (USD $) In Thousands	6 Months Ended
	Jun. 30, 2011	Jun. 30, 2010
Operating Activities
Net income	$ 157,593	$ 172,253
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization	126,757	124,211
Accretion expense	3,338	3,007
Deferred income taxes	75,409	37,499
Bad debt expense	2,673	(237)
Exploratory expense	216	19,416
Change in derivative fair value	(314)	(1,746)
Gain on sale of assets	(5,926)	(491)
Other, net	8,543	15,241
Net change in:
Accounts receivable	43,066	97,040
Inventories	(6,061)	5,703
Accounts payable	(20,434)	(50,581)
Amounts due customers including gas supply pass-through	8,513	29,311
Income tax receivable	39,225	(13,062)
Pension and other postretirement benefit contributions	(4,061)	(39,737)
Other current assets and liabilities	12,589	2,686
Net cash provided by operating activities	441,126	400,513
Investing Activities
Additions to property, plant and equipment	(378,640)	(171,185)
Acquisitions, net of cash acquired	(60,937)	(5,580)
Proceeds from sale of assets	7,306	549
Purchase of short-term investments	0	(154,880)
Other, net	(413)	(702)
Net cash used in investing activities	(432,684)	(331,798)
Financing Activities
Payment of dividends on common stock	(19,458)	(18,687)
Issuance of common stock	6,202	586
Payment of long-term debt	(293)	(519)
Net change in short-term debt	(3,000)	0
Tax benefit on stock compensation	880	708
Net cash used in financing activities	(15,669)	(17,912)
Net change in cash and cash equivalents	(7,227)	50,803
Cash and cash equivalents at beginning of period	22,659	75,844
Cash and Cash Equivalents at End of Period	15,432	126,647
Alabama Gas Corporation
Operating Activities
Net income	44,437	43,906
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization	19,626	24,929
Deferred income taxes	12,962	7,270
Bad debt expense	2,660	(225)
Other, net	1,620	3,516
Net change in:
Accounts receivable	31,975	50,953
Inventories	1,919	11,468
Accounts payable	(17,284)	(18,070)
Amounts due customers including gas supply pass-through	8,513	29,311
Income tax receivable	8,238	1,513
Pension and other postretirement benefit contributions	(1,406)	(24,286)
Other current assets and liabilities	4,491	9,743
Net cash provided by operating activities	117,751	140,028
Investing Activities
Additions to property, plant and equipment	(34,386)	(36,586)
Other, net	(1,545)	(1,229)
Net cash used in investing activities	(35,931)	(37,815)
Financing Activities
Payment of dividends on common stock	(14,698)	(18,684)
Payment of long-term debt	(293)	(519)
Net decreases in advances from affiliates	0	(24,962)
Net change in short-term debt	(70,000)	0
Net cash used in financing activities	(84,991)	(44,165)
Net change in cash and cash equivalents	(3,171)	58,048
Cash and cash equivalents at beginning of period	16,910	9,460
Cash and Cash Equivalents at End of Period	$ 13,739	$ 67,508

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Segment Information (Tables)

6 Months Ended

Jun. 30, 2011

Segment Reporting [Abstract]

Schedule of Segment Reporting Information, by Segment

	Three months ended						Six months ended
	June 30,						June 30,
(in thousands)	2011			2010			2011			2010
Operating revenues
Oil and gas operations	$	244,090		$	234,586		$	460,882		$	472,200
Natural gas distribution	86,309			99,139			355,881			436,439
Total	$	330,399		$	333,725		$	816,763		$	908,639
Operating income (loss)
Oil and gas operations	$	105,418		$	95,456		$	190,477		$	212,741
Natural gas distribution	1,163			3,138			76,222			78,393
Eliminations and corporate expenses	(246		)	(301		)	(483		)	(643		)
Total	$	106,335		$	98,293		$	266,216		$	290,491
Other income (expense)
Oil and gas operations	$	(5,822	)	$	(6,555	)	$	(11,269	)	$	(12,426	)
Natural gas distribution	(3,040		)	(3,702		)	(5,953		)	(6,763		)
Eliminations and other	65			(548		)	88			(762		)
Total	$	(8,797	)	$	(10,805	)	$	(17,134	)	$	(19,951	)
Income before income taxes	$	97,538		$	87,488		$	249,082		$	270,540

(in thousands)	June 30, 2011		December 31, 2010
Identifiable assets
Oil and gas operations	$	3,404,189	$	3,160,601
Natural gas distribution	1,070,831		1,166,899
Eliminations and other	36,374		36,060
Total	$	4,511,394	$	4,363,560

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Commitments and Contingencies (Details) - Income Taxes (USD $) In Millions	3 Months Ended
	Jun. 30, 2011
Income Tax Contingency [Line Items]
Unrecognized Tax Benefits, Increases Resulting from Settlements with Taxing Authorities	$ 1.5
Unrecognized Tax Benefits, Period Increase (Decrease)	1.9
State and Local Jurisdiction
Income Tax Contingency [Line Items]
Income Tax Reconciliation, Change in Enacted Tax Rate	$ (2.1)

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Employee Benefit Plans (Tables)

6 Months Ended

Jun. 30, 2011

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 June 30,						Six months ended June 30,
(in thousands)	2011			2010			2011			2010
Components of net periodic benefit cost:
Service cost	$	2,293		$	2,144		$	4,586		$	4,287
Interest cost	2,740			2,841			5,480			5,683
Expected long-term return on assets	(3,868		)	(3,229		)	(7,736		)	(6,458		)
Actuarial loss	1,609			1,443			3,218			2,887
Prior service cost amortization	124			124			248			248
Net periodic expense	$	2,898		$	3,323		$	5,796		$	6,647

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 June 30,						Six months ended June 30,
(in thousands)	2011			2010			2011			2010
Components of net periodic benefit cost:
Service cost	$	442		$	516		$	885		$	1,032
Interest cost	1,111			1,208			2,222			2,417
Expected long-term return on assets	(1,104		)	(996		)	(2,209		)	(1,993		)
Transition amortization	479			479			958			958
Net periodic expense	$	928		$	1,207		$	1,856		$	2,414

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Regulatory Matters

6 Months Ended

Jun. 30, 2011

Regulated Operations [Abstract]

Regulatory Matters

REGULATORY MATTERS

Alagasco is subject to regulation by the APSC which established the Rate Stabilization and Equalization (RSE) rate-setting process in 1983. RSE’s current extension is for a seven-year period ended 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 remains 13.15 percent to 13.65 percent throughout the term of the RSE order. Under RSE the APSC conducts quarterly reviews to determine, based on Alagasco's projections and year-to-date performance, 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 six months ended June 30, 2011, Alagasco had a net $2.2 million pre-tax and a net $5.4 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 six months ended June 30, 2010, Alagasco had a $1.8 million pre-tax and a $10.6 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 $1.3 million annual decrease and a $10.2 million annual increase in revenues became effective December 1, 2010 and 2009, 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. In the rate year ended September 30, 2010, $2.5 million of extraordinary bad debt expense was excluded from the CCM calculation. Alagasco’s O&M expense fell within the Index Range for the rate years ended September 30, 2010 and 2009.

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.

In 1998, the APSC approved an Enhanced Stability Reserve, with a maximum funding level of $4 million, to which Alagasco could charge the full amount of: (1) extraordinary O&M expenses resulting from force majeure events when one or a combination of two such events results in more than $200,000 of additional O&M expense during a rate year; or (2) negative individual large commercial and industrial customer budget revenue variances that exceed $250,000 during the rate year, if such losses caused Alagasco's year-end return on average common equity (RCE) to fall below the bottom of the APSC-approved return on equity range currently at 13.15 percent. Prior to June 28, 2010, the APSC provided for accretions to the ESR of no more than $40,000 monthly until the maximum funding level was achieved, following a year in which a charge against the ESR was made. The APSC’s June 28, 2010, order approved Alagasco’s lower depreciation rates and approved standing authority for Alagasco to charge items to the ESR in excess of its funded balance and to allocate each year from the refundable negative salvage costs that are being refunded to customers over the nine year period the amount necessary to clear the debit balance in the ESR each September 30, subject to APSC-approved guidelines. The APSC also approved the amortization of the ESR into rates over a five year period in cases where the ESR is unfunded or underfunded, subject to APSC-approved guidelines. As a result of these changes in the funding mechanism for the ESR, the APSC suspended the $40,000 per month accruals to the ESR during the nine year period when the refundable negative salvage costs are being refunded to customers.

Following a vote on September 7, 2010, the APSC, by order dated November 1, 2010, approved expansion of the ESR to include extraordinary O&M charges related to environmental response costs and to self insurance costs that exceed $1 million per occurrence. In addition, the APSC raised the thresholds on items that may be charged to the ESR as follows: (1) extraordinary O&M expenses, other than environmental response costs and self insurance costs, resulting from a single event that results in more than $275,000 of increased O&M; (2) extraordinary O&M expenses, other than environmental response costs and self insurance costs, resulting from a combination of extraordinary O&M events that result in more than $412,500 of increased O&M; and (3) negative individual large commercial and industrial customer budget variances that exceed $350,000. Charges to the ESR relating to extraordinary O&M expenses can only be made when the Company’s year-end return on average common equity for RSE, not including the ESR charge, is below the midpoint of the APSC-approved return on equity range and only to the extent necessary to bring the RCE to the midpoint of the range. Charges to the ESR relating to negative individual large commercial and industrial customer revenue variances can only be made if such losses cause the RCE to fall below the bottom of the APSC-approved return on equity range currently at 13.15 percent, and then only to the extent necessary to bring the RCE up to the midpoint of the range. In the event that Alagasco’s RCE at September 30 of the related year is above the midpoint, any debit balance in the ESR shall remain in the ESR for recovery in subsequent years subject to the established guidelines. Additionally, the APSC, while confirming the five year amortization period established in the June 28, 2010, order for charges to the ESR in cases where the ESR is unfunded or underfunded, limited the amortization expense to $660,000 annually, with any excess amortization expense over $660,000 in any rate year being carried over and amortized in future rate years until full amortization of the ESR debit balance is complete. The APSC also raised the $40,000 per month accruals to $55,000 per month, but suspended the accruals pending further order of the APSC. Finally, the APSC established guidelines for the documentation, reporting and approval of rate recovery of items charged to the ESR.In connection with the above, Alagasco expects to recover certain manufactured gas plant site remediation costs through future rates and has recorded a corresponding amount to its Enhanced Stability Reserve regulatory account of $4.4 million and $3.8 million as of June 30, 2011 and December 31, 2010, respectively, as more fully described in Note 9, Commitments and Contingencies.

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Regulatory Assets and Liabilities

6 Months Ended

Jun. 30, 2011

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)	June 30, 2011				December 31, 2010
	Current		Noncurrent		Current		Noncurrent
Regulatory assets:
Pension and postretirement assets	$	170	$	58,469	$	132	$	60,284
Accretion and depreciation for asset retirement obligation	—		8,898		—		8,681
Risk management activities	32,159		17,657		27,906		32,461
RSE adjustment	25		—		25		—
Enhanced stability reserve	—		4,395		—		3,794
Other	209		46		223		145
Total regulatory assets	$	32,563	$	89,465	$	28,286	$	105,365
Regulatory liabilities:
RSE adjustment	$	7,696	$	—	$	4,147	$	—
Unbilled service margin	6,957		—		34,197		—
Postretirement liabilities	—		959		—		754
Gas supply adjustment	29,695		—		14,990		—
Asset removal costs, net	—		7,665		—		6,913
Refundable negative salvage	20,643		71,896		22,336		90,504
Asset retirement obligation	—		11,611		—		11,439
Other	33		820		33		837
Total regulatory liabilities	$	65,024	$	92,951	$	75,703	$	110,447

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Derivative Commodity Instruments (Details) - Derivative Instruments Change in Fair Value (Derivative Commodity Instruments, USD $) In Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2011	Jun. 30, 2010	Jun. 30, 2011	Jun. 30, 2010
Derivative Commodity Instruments
Fair Value, Assets and Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Balance at beginning of period	$ 16,927	$ 114,440	$ 42,755	$ 64,517
Realized (gains) losses	1,204	(303)	1,204	(303)
Unrealized gains (losses) relating to instruments held at the reporting date	7,720	9,215	(3,554)	75,886
Settlements during period	(12,405)	(31,535)	(26,959)	(48,283)
Balance at end of period	$ 13,446	$ 91,817	$ 13,446	$ 91,817

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Derivative Commodity Instruments (Tables)

6 Months Ended

Jun. 30, 2011

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)	June 30, 2011
	Oil and Gas Operations				Natural Gas Distribution			Total
Derivative assets or (liabilities) designated as hedging instruments
Accounts receivable	$	49,182			$	—		$	49,182
Long-term asset derivative instruments	10,427			*	—			10,427
Total derivative assets	59,609				—			59,609
Accounts receivable	(37,177		)	*	—			(37,177		)
Accounts payable	(54,926		)		—			(54,926		)
Long-term liability derivative instruments	(120,273		)		—			(120,273		)
Total derivative liabilities	(212,376		)		—			(212,376		)
Total derivatives designated	(152,767		)		—			(152,767		)
Derivative assets or (liabilities) not designated as hedging instruments
Accounts payable	(68		)		(32,159		)	(32,227		)
Long-term liability derivative instruments	—				(17,657		)	(17,657		)
Total derivative liabilities	(68		)		(49,816		)	(49,884		)
Total derivatives not designated	(68		)		(49,816		)	(49,884		)
Total derivatives	$	(152,835	)		$	(49,816	)	$	(202,651	)

(in thousands)	December 31, 2010
	Oil and Gas Operations				Natural Gas Distribution			Total
Derivative assets or (liabilities) designated as hedging instruments
Accounts receivable	$	85,867			$	—		$	85,867
Long-term asset derivative instruments	3,156			*	—			3,156
Total derivative assets	89,023				—			89,023
Accounts receivable	(25,315		)	*	—			(25,315		)
Accounts payable	(50,508		)		—			(50,508		)
Long-term liability derivative instruments	(83,631		)		—			(83,631		)
Total derivative liabilities	(159,454		)		—			(159,454		)
Total derivatives designated	(70,431		)		—			(70,431		)
Derivative assets or (liabilities) not designated as hedging instruments
Accounts payable	(110		)		(27,906		)	(28,016		)
Long-term liability derivative instruments	—				(32,461		)	(32,461		)
Total derivative liabilities	(110		)		(60,367		)	(60,477		)
Total derivatives not designated	(110		)		(60,367		)	(60,477		)
Total derivatives	$	(70,541	)		$	(60,367	)	$	(130,908	)

* 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 June 30, 2011			Three months ended June 30, 2010
Gain recognized in OCI on derivative (effective portion), net of tax of $30.3 million and $26.3 million	—	$	49,449		$	42,917
Gain (loss) reclassified from accumulated OCI into income (effective portion)	Operating revenues	$	(5,770	)	$	56,666
Gain (loss) recognized in income on derivative (ineffective portion and amount excluded from effectiveness testing)	Operating revenues	$	(740	)	$	175

(in thousands)	Location on Income Statement	Six months ended June 30, 2011			Six months ended June 30, 2010
Gain (loss) recognized in OCI on derivative (effective portion), net of tax of ($29.1) million and $60.3 million	—	$	(47,425	)	$	98,385
Gain reclassified from accumulated OCI into income (effective portion)	Operating revenues	$	1,821		$	93,390
Gain (loss) recognized in income on derivative (ineffective portion and amount excluded from effectiveness testing)	Operating revenues	$	(2,391	)	$	1,879

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 June 30, 2011			Three months ended June 30, 2010
Loss recognized in income on derivative	Operating revenues	$	(1	)	$	(1	)
(in thousands)	Location on Income Statement	Six months ended June 30, 2011			Six months ended June 30, 2010
Loss recognized in income on derivative	Operating revenues	$	(1	)	$	(4	)

Schedule of Hedging Transactions

Energen Resources entered into the following transactions for the remainder of 2011 and subsequent years:

Production Period	Total Hedged Volumes	Average Contract Price	Description
Natural Gas
2011	7.1 Bcf	$6.47 Mcf	NYMEX Swaps
	19.4 Bcf	$5.65 Mcf	Basin Specific Swaps
2012	11.0 Bcf	$5.07 Mcf	NYMEX Swaps
	29.5 Bcf	$4.60 Mcf	Basin Specific Swaps
2013	8.8 Bcf	$5.30 Mcf	NYMEX Swaps
	25.1 Bcf	$4.88 Mcf	Basin Specific Swaps
2014	3.0 Bcf	$5.72 Mcf	NYMEX Swaps
	6.0 Bcf	$5.34 Mcf	Basin Specific Swaps
Oil
2011	2,242 MBbl	$80.47 Bbl	NYMEX Swaps
2012	3,881 MBbl	$83.53 Bbl	NYMEX Swaps
2013	3,296 MBbl	$85.97 Bbl	NYMEX Swaps
2014	2,818 MBbl	$87.92 Bbl	NYMEX Swaps
Oil Basis Differential
2011	1,103 MBbl	*	Basis Swaps
2012	753 MBbl	*	Basis Swaps
Natural Gas Liquids
2011	21.1 MMGal	$0.90 Gal	Liquids Swaps
2012	39.9 MMGal	$0.86 Gal	Liquids Swaps
2013	35.2 MMGal	$1.02 Gal	Liquids Swaps
* Average contract prices are not meaningful due to the varying nature of each contract.

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:

	June 30, 2011
(in thousands)	Level 2*			Level 3*			Total
Current assets	$	(7,773	)	$	19,778		$	12,005
Noncurrent assets	78			$	924		$	1,002
Current liabilities	(81,752		)	(5,401		)	(87,153		)
Noncurrent liabilities	(126,650		)	(1,855		)	(128,505		)
Net derivative asset (liability)	$	(216,097	)	$	13,446		$	(202,651	)

	December 31, 2010
(in thousands)	Level 2*			Level 3*			Total
Current assets	$	10,316		$	50,236		$	60,552
Current liabilities	(76,527		)	(1,997		)	(78,524		)
Noncurrent liabilities	(107,452		)	(5,484		)	(112,936		)
Net derivative asset (liability)	$	(173,663	)	$	42,755		$	(130,908	)

* 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)	June 30, 2011			June 30, 2010
Balance at beginning of period	$	16,927		$	114,440
Realized (gains) losses	1,204			(303		)
Unrealized gains (losses) relating to instruments held at the reporting date	7,720			9,215
Settlements during period	(12,405		)	(31,535		)
Balance at end of period	$	13,446		$	91,817

	Six months ended			Six months ended
(in thousands)	June 30, 2011			June 30, 2010
Balance at beginning of period	$	42,755		$	64,517
Realized (gains) losses	1,204			(303		)
Unrealized gains (losses) relating to instruments held at the reporting date	(3,554		)	75,886
Settlements during period	(26,959		)	(48,283		)
Balance at end of period	$	13,446		$	91,817

Alabama Gas Corporation

Derivative [Line Items]

Schedule of Hedging Transactions

Alagasco entered into the following natural gas transactions for the remainder of 2011 and subsequent years:

Production Period	Total Hedged Volumes	Description
2011	6.0 Bcf	NYMEX Swaps
2012	17.2 Bcf	NYMEX Swaps
2013	1.5 Bcf	NYMEX Swaps

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Consolidated Condensed Statements of Income (USD $) In Thousands, except Per Share data	3 Months Ended		6 Months Ended
	Jun. 30, 2011	Jun. 30, 2010	Jun. 30, 2011	Jun. 30, 2010
Operating Revenues
Oil and gas operations	$ 244,090	$ 234,586	$ 460,882	$ 472,200
Natural gas distribution	86,309	99,139	355,881	436,439
Total operating revenues	330,399	333,725	816,763	908,639
Operating Expenses
Cost of gas	32,419	43,234	164,168	240,390
Operations and maintenance	103,232	109,945	207,014	201,647
Depreciation, depletion and amortization	65,629	62,476	126,757	124,211
Income taxes
Deferred			75,409	37,499
Taxes, other than income taxes	21,095	18,256	49,270	48,893
Accretion expense	1,689	1,521	3,338	3,007
Total operating expenses	224,064	235,432	550,547	618,148
Operating Income	106,335	98,293	266,216	290,491
Other Income (Expense)
Interest expense	9,463	9,844	18,867	19,804
Other income	779	385	2,009	723
Other expense	(113)	(1,346)	(276)	(870)
Total other expense	(8,797)	(10,805)	(17,134)	(19,951)
Interest Charges
Income Before Income Taxes	97,538	87,488	249,082	270,540
Income tax expense	34,213	31,945	91,489	98,287
Net Income	63,325	55,543	157,593	172,253
Diluted Earnings Per Average Common Share (dollars per share)	$ 0.87	$ 0.77	$ 2.18	$ 2.39
Basic Earnings Per Average Common Share (dollars per share)	$ 0.88	$ 0.77	$ 2.19	$ 2.40
Dividends Per Common Share (dollars per share)	$ 0.135	$ 0.130	$ 0.270	$ 0.260
Diluted Average Common Shares Outstanding	72,420	72,089	72,364	72,069
Basic Average Common Shares Outstanding	72,065	71,844	72,033	71,830
Alabama Gas Corporation
Operating Revenues
Natural gas distribution	86,309	99,139	355,881	436,439
Operating Expenses
Cost of gas	32,419	43,234	164,168	240,390
Operations and maintenance	36,212	33,501	73,534	64,904
Depreciation, depletion and amortization	9,846	11,890	19,626	24,929
Income taxes
Current	(8,701)	(4,201)	12,870	20,454
Deferred	6,562	3,977	12,962	7,270
Taxes, other than income taxes	6,669	7,376	22,331	27,823
Total operating expenses	83,007	95,777	305,491	385,770
Operating Income	3,302	3,362	50,390	50,669
Other Income (Expense)
Interest expense	3,536	3,496	7,153	6,990
Allowance for funds used during construction	234	148	392	270
Other income	374	241	993	452
Other expense	(112)	(595)	(185)	(495)
Total other expense	496	(206)	1,200	227
Interest Charges
Interest on long-term debt	3,039	2,964	6,081	5,932
Other interest expense	497	532	1,072	1,058
Net Income	$ 262	$ (340)	$ 44,437	$ 43,906

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Reconciliation of Earnings Per Share (Details) - Antidilutive Securities	3 Months Ended		6 Months Ended
	Jun. 30, 2011	Jun. 30, 2010	Jun. 30, 2011	Jun. 30, 2010
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)	0	472,560	0	472,560
Non-vested restricted stock
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Antidilutive Securities Excluded from Computation of Earnings Per Share (in options or shares)	0	0	0	0

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Financial Instruments (Details) (USD $)	6 Months Ended
	Jun. 30, 2011	Jun. 30, 2011 Alabama Gas Corporation	Dec. 31, 2010 Alabama Gas Corporation	Jun. 30, 2011 Alabama Gas Corporation Long-term Debt, Including Current Portion, Fair Value, Fair Value Disclosure	Jun. 30, 2011 Alabama Gas Corporation Long-term Debt, Including Current Portion, Carrying Value, Fair Value Disclosure	Jun. 30, 2011 Long-term Debt, Including Current Portion, Fair Value, Fair Value Disclosure	Jun. 30, 2011 Long-term Debt, Including Current Portion, Carrying Value, Fair Value Disclosure
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term Debt, Fair Value				$ 213,900,000	$ 205,500,000	$ 443,400,000	$ 410,500,000
Financing Receivable		9,600,000	8,800,000
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		361,000
Financing Receivable, Allowance for Credit Losses [Roll Forward]
Allowance for credit losses, beginning balance	447,000
Provision	80,000
Allowance for credit losses, ending balance	$ 527,000

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Regulatory Assets and Liabilities (Details) (USD $) In Thousands	Jun. 30, 2011	Dec. 31, 2010
Regulatory Assets and Liabilities [Line Items]
Regulatory Assets, Current	$ 32,563	$ 28,286
Regulatory Assets, Noncurrent	89,465	105,365
Regulatory Liability, Current	65,024	75,703
Regulatory Liability, Noncurrent	92,951	110,447
Alabama Gas Corporation
Regulatory Assets and Liabilities [Line Items]
Regulatory Assets, Current	32,563	28,286
Regulatory Assets, Noncurrent	89,465	105,365
Regulatory Liability, Current	65,024	75,703
Regulatory Liability, Noncurrent	92,951	110,447
Alabama Gas Corporation | Enhanced stability reserve
Regulatory Assets and Liabilities [Line Items]
Regulatory Assets, Current	0	0
Regulatory Assets, Noncurrent	4,395	3,794
Alabama Gas Corporation | Pension and postretirement assets
Regulatory Assets and Liabilities [Line Items]
Regulatory Assets, Current	170	132
Regulatory Assets, Noncurrent	58,469	60,284
Alabama Gas Corporation | Accretion and depreciation for asset retirement obligation
Regulatory Assets and Liabilities [Line Items]
Regulatory Assets, Current	0	0
Regulatory Assets, Noncurrent	8,898	8,681
Alabama Gas Corporation | Risk management activities
Regulatory Assets and Liabilities [Line Items]
Regulatory Assets, Current	32,159	27,906
Regulatory Assets, Noncurrent	17,657	32,461
Alabama Gas Corporation | RSE adjustment
Regulatory Assets and Liabilities [Line Items]
Regulatory Assets, Current	25	25
Regulatory Assets, Noncurrent	0	0
Alabama Gas Corporation | Other
Regulatory Assets and Liabilities [Line Items]
Regulatory Assets, Current	209	223
Regulatory Assets, Noncurrent	46	145
Alabama Gas Corporation | RSE adjustment
Regulatory Assets and Liabilities [Line Items]
Regulatory Liability, Current	7,696	4,147
Regulatory Liability, Noncurrent	0	0
Alabama Gas Corporation | Unbilled service margin
Regulatory Assets and Liabilities [Line Items]
Regulatory Liability, Current	6,957	34,197
Regulatory Liability, Noncurrent	0	0
Alabama Gas Corporation | Postretirement liabilities
Regulatory Assets and Liabilities [Line Items]
Regulatory Liability, Current	0	0
Regulatory Liability, Noncurrent	959	754
Alabama Gas Corporation | Gas supply adjustment
Regulatory Assets and Liabilities [Line Items]
Regulatory Liability, Current	29,695	14,990
Regulatory Liability, Noncurrent	0	0
Alabama Gas Corporation | Asset removal costs, net
Regulatory Assets and Liabilities [Line Items]
Regulatory Liability, Current	0	0
Regulatory Liability, Noncurrent	7,665	6,913
Alabama Gas Corporation | Asset retirement obligation
Regulatory Assets and Liabilities [Line Items]
Regulatory Liability, Current	0	0
Regulatory Liability, Noncurrent	11,611	11,439
Alabama Gas Corporation | Refundable negative salvage
Regulatory Assets and Liabilities [Line Items]
Regulatory Liability, Current	20,643	22,336
Regulatory Liability, Noncurrent	71,896	90,504
Alabama Gas Corporation | Other
Regulatory Assets and Liabilities [Line Items]
Regulatory Liability, Current	33	33
Regulatory Liability, Noncurrent	820	837
Refundable negative salvage
Regulatory Assets and Liabilities [Line Items]
Regulatory Liability, Current	20,643
Regulatory Liability, Noncurrent	$ 71,896

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Segment Information (Details) (USD $) In Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2011	Jun. 30, 2010	Jun. 30, 2011	Jun. 30, 2010	Dec. 31, 2010
Segment Reporting Information, Profit (Loss)
Operating revenues	$ 330,399	$ 333,725	$ 816,763	$ 908,639
Operating income (loss)	106,335	98,293	266,216	290,491
Other income (expense)	(8,797)	(10,805)	(17,134)	(19,951)
Income before income taxes	97,538	87,488	249,082	270,540
Identifiable assets	4,511,394		4,511,394		4,363,560
Oil and Gas Operations
Segment Reporting Information, Profit (Loss)
Operating revenues	244,090	234,586	460,882	472,200
Operating income (loss)	105,418	95,456	190,477	212,741
Other income (expense)	(5,822)	(6,555)	(11,269)	(12,426)
Identifiable assets	3,404,189		3,404,189		3,160,601
Natural Gas Distribution
Segment Reporting Information, Profit (Loss)
Operating revenues	86,309	99,139	355,881	436,439
Operating income (loss)	1,163	3,138	76,222	78,393
Other income (expense)	(3,040)	(3,702)	(5,953)	(6,763)
Identifiable assets	1,070,831		1,070,831		1,166,899
Eliminations and other
Segment Reporting Information, Profit (Loss)
Operating income (loss)	(246)	(301)	(483)	(643)
Other income (expense)	65	(548)	88	(762)
Identifiable assets	$ 36,374		$ 36,374		$ 36,060