Energen (EGN) 10-Q 8 Nov 13 2013 Q3 Quarterly report Financial data

Document_and_Entity_Informatio

Document and Entity Information	9 Months Ended
	Sep. 30, 2013	Nov. 01, 2013
Entity Information	'	'
Document Type	'10-Q	'
Amendment Flag	'false	'
Document Period End Date	30-Sep-13	'
Document Fiscal Year Focus	'2013	'
Document Fiscal Period Focus	'Q3	'
Entity Registrant Name	'ENERGEN CORP	'
Entity Central Index Key	'0000277595	'
Current Fiscal Year End Date	'--12-31	'
Entity Filer Category	'Large Accelerated Filer	'
Entity Common Stock, Shares Outstanding	'	72,685,415
Alabama Gas Corporation	'	'
Entity Information	'	'
Document Type	'10-Q	'
Amendment Flag	'false	'
Document Period End Date	30-Sep-13	'
Document Fiscal Year Focus	'2013	'
Document Fiscal Period Focus	'Q3	'
Entity Registrant Name	'ALABAMA GAS CORP	'
Entity Central Index Key	'0000003146	'
Current Fiscal Year End Date	'--12-31	'
Entity Filer Category	'Non-accelerated Filer	'
Entity Common Stock, Shares Outstanding	'	1,972,052

Consolidated_Condensed_Stateme

Consolidated Condensed Statements of Income (USD $)	3 Months Ended		9 Months Ended
In Thousands, except Per Share data, unless otherwise specified	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
Operating Revenues	'	'	'	'
Oil and gas operations	$272,038	$214,620	$875,350	$799,339
Natural gas distribution	48,368	61,809	390,567	327,183
Total operating revenues	320,406	276,429	1,265,917	1,126,522
Operating Expenses	'	'	'	'
Cost of gas	20,435	20,924	163,448	94,179
Operations and maintenance	141,271	123,730	413,401	336,568
Depreciation, depletion and amortization	136,123	96,634	365,355	276,465
Income taxes	'	'	'	'
Deferred	'	'	51,682	80,724
Taxes, other than income taxes	24,858	19,572	77,955	64,314
Accretion expense	1,771	1,605	5,187	4,691
Total operating expenses	324,458	262,465	1,025,346	776,217
Operating Income (Loss)	-4,052	13,964	240,571	350,305
Other Income (Expense)	'	'	'	'
Interest expense	-17,689	-17,195	-51,751	-48,447
Other income	13,062	1,488	15,578	3,678
Other expense	-434	-84	-631	-305
Total other expense	-5,061	-15,791	-36,804	-45,074
Interest Expense	'	'	'	'
Income (Loss) From Continuing Operations Before Income Taxes	-9,113	-1,827	203,767	305,231
Income tax expense (benefit)	-3,627	-322	73,897	110,508
Income (Loss) From Continuing Operations	-5,486	-1,505	129,870	194,723
Discontinued Operations, net of taxes	'	'	'	'
Income (loss) from discontinued operations	1,866	3,551	6,269	-3,984
Loss on disposal of discontinued operations	-15,678	0	-15,678	0
Total Income (Loss) From Discontinued Operations	-13,812	3,551	-9,409	-3,984
Net Income (Loss)	-19,298	2,046	120,461	190,739
Diluted Earnings Per Average Common Share	'	'	'	'
Continuing Operations (in dollars per share)	($0.08)	($0.02)	$1.80	$2.69
Discontinued operations (in dollars per share)	($0.19)	$0.05	($0.13)	($0.05)
Diluted Earnings Per Average Common Share (in dollars per share)	($0.27)	$0.03	$1.67	$2.64
Basic Earnings Per Average Common Share	'	'	'	'
Continuing Operations (in dollars per share)	($0.08)	($0.02)	$1.80	$2.70
Discontinued operations (in dollars per share)	($0.19)	$0.05	($0.13)	($0.06)
Net Income (Loss) (in dollars per share)	($0.27)	$0.03	$1.67	$2.64
Dividends Per Common Share (in dollars per share)	$0.14	$0.14	$0.44	$0.42
Diluted Average Common Shares Outstanding	72,346	72,316	72,272	72,301
Basic Average Common Shares Outstanding	72,346	72,130	72,220	72,121
Alabama Gas Corporation	'	'	'	'
Operating Revenues	'	'	'	'
Natural gas distribution	48,368	61,809	390,567	327,183
Operating Expenses	'	'	'	'
Cost of gas	20,435	20,924	163,448	94,179
Operations and maintenance	33,650	37,235	107,672	107,470
Depreciation, depletion and amortization	11,063	10,572	32,665	31,551
Income taxes	'	'	'	'
Current	-7,703	-9,242	16,440	13,567
Deferred	2,093	3,264	6,448	9,431
Taxes, other than income taxes	5,764	5,821	27,814	23,718
Total operating expenses	65,302	68,574	354,487	279,916
Operating Income (Loss)	-16,934	-6,765	36,080	47,267
Other Income (Expense)	'	'	'	'
Interest expense	-3,869	-4,164	-11,733	-12,185
Allowance for funds used during construction	184	187	630	452
Other income	12,092	787	13,203	1,925
Other expense	-434	-84	-623	-254
Total other expense	11,842	890	13,210	2,123
Interest Expense	'	'	'	'
Interest on long-term debt	3,377	3,423	10,133	10,270
Other interest expense	492	741	1,600	1,915
Discontinued Operations, net of taxes	'	'	'	'
Net Income (Loss)	($8,961)	($10,039)	$37,557	$37,205

Consolidated_Condensed_Stateme1

Consolidated Condensed Statements of Comprehensive Income (USD $)	3 Months Ended		9 Months Ended
In Thousands, unless otherwise specified	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
Net Income (Loss)	($19,298)	$2,046	$120,461	$190,739
Other comprehensive income (loss):	'	'	'	'
Total cash flow hedges	-5,220	-58,430	-28,831	25,167
Pension and postretirement plans:	'	'	'	'
Amortization of net obligation at transition, net of taxes of $26, $25, $77 and $75	48	47	143	140
Amortization of prior service cost, net of taxes of $28, $30, $82 and $89	51	55	153	166
Amortization of net loss, including settlement charges, net of taxes of $729, $413, $2,383 and $1,238	1,354	766	4,425	2,300
Current period change in fair value of pension and postretirement plans, net of taxes of $2,238, ($4,073), $2,238 and ($4,073)	4,157	-7,564	4,157	-7,564
Total pension and postretirement plans	5,610	-6,696	8,878	-4,958
Comprehensive Income (Loss)	-18,908	-63,080	100,508	210,948
Commodity contracts	'	'	'	'
Other comprehensive income (loss):	'	'	'	'
Current period change in fair value	69	-49,962	-10,882	49,961
Reclassification adjustment for commodity derivative instruments, net of tax	-5,229	-8,034	-18,740	-23,337
Interest rate swap	'	'	'	'
Other comprehensive income (loss):	'	'	'	'
Current period change in fair value	-350	-697	-42	-2,240
Reclassification adjustment for commodity derivative instruments, net of tax	$290	$263	$833	$783

Consolidated_Condensed_Stateme2

Consolidated Condensed Statements of Comprehensive Income (Parenthetical) (USD $)	3 Months Ended		9 Months Ended
In Thousands, unless otherwise specified	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
Amortization of net obligation at transition, tax	$26	$25	$77	$75
Amortization of prior service cost, tax	28	30	82	89
Amortization of net loss, including settlement charges, tax	729	413	2,383	1,238
Current period change in fair value of pension, tax	2,238	-4,073	2,238	-4,073
Commodity contracts	'	'	'	'
Current period change in fair value of interest rate swap, tax	42	-30,622	-6,669	30,621
Reclassification adjustment for derivative instruments, tax	-3,205	-4,924	-11,486	-14,303
Interest rate swap	'	'	'	'
Current period change in fair value of interest rate swap, tax	-188	-375	-23	-1,205
Reclassification adjustment for derivative instruments, tax	$156	$142	$449	$422

Consolidated_Condensed_Balance

Consolidated Condensed Balance Sheets (USD $)	Sep. 30, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified
Current Assets	'	'
Cash and cash equivalents	$12,413	$9,704
Accounts receivable	'	'
Allowance for doubtful accounts	-5,296	-6,549
Accounts receivable, net of allowance for doubtful accounts of $6,070 at September 30, 2013, and $6,549 at December 31, 2012	200,043	277,900
Inventories	'	'
Storage gas inventory	39,507	32,205
Materials and supplies	19,187	28,291
Liquified natural gas in storage	2,990	3,498
Regulatory asset	11,213	45,515
Income tax receivable	7,653	6,664
Assets held for sale	183,862	0
Deferred income taxes	42,722	8,520
Prepayments and other	12,996	12,823
Total current assets	532,586	425,120
Property, Plant and Equipment	'	'
Oil and gas properties, successful efforts method	6,655,343	6,439,127
Less accumulated depreciation, depletion and amortization	1,657,682	1,765,241
Oil and gas properties, net	4,997,661	4,673,886
Utility plant	1,471,174	1,416,590
Less accumulated depreciation	594,604	573,947
Utility plant, net	876,570	842,643
Other property, net	29,733	25,107
Total property, plant and equipment, net	5,903,964	5,541,636
Other Assets	'	'
Regulatory asset	89,004	110,566
Pension and other postretirement assets	17,417	1,404
Long-term derivative instruments	12,786	40,577
Deferred charges and other	59,115	56,587
Total other assets	178,322	209,134
TOTAL ASSETS	6,614,872	6,175,890
Current Liabilities	'	'
Long-term debt due within one year	125,000	50,000
Notes payable to banks	901,000	643,000
Accounts payable	256,109	257,579
Accrued taxes	51,878	30,076
Customers’ deposits	20,531	24,705
Amounts due customers	19,974	19,718
Accrued wages and benefits	25,896	24,984
Regulatory liability	40,168	45,116
Royalty payable	49,976	34,426
Liabilities related to assets held for sale	23,945	0
Other	26,812	30,178
Total current liabilities	1,541,289	1,159,782
Long-term debt	1,028,509	1,103,528
Deferred Credits and Other Liabilities	'	'
Asset retirement obligation	106,604	118,023
Pension and other postretirement liabilities	90,893	110,282
Regulatory liability	81,414	80,404
Long-term derivative instruments	1,961	11,305
Deferred income taxes	979,898	905,601
Other	14,638	10,275
Total deferred credits and other liabilities	1,275,408	1,235,890
Commitments and Contingencies	'	'
Shareholders’ Equity	'	'
Preferred stock, cumulative $0.01 par value	0	0
Common shareholders’ equity	'	'
Common stock, $0.01 par value	755	751
Premium on capital stock	514,784	492,108
Capital surplus	2,802	2,802
Retained earnings	2,403,062	2,314,055
Accumulated other comprehensive income (loss), net of tax	'	'
Unrealized gain on hedges, net	16,730	46,352
Pension and postretirement plans	-43,629	-52,507
Interest rate swap	-1,365	-2,156
Deferred compensation plan	3,319	2,774
Treasury stock, at cost: 2,977,920 shares at September 30, 2013, and 2,998,620 shares at December 31, 2012	-126,792	-127,489
Total shareholders’ equity	2,769,666	2,676,690
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY	6,614,872	6,175,890
Alabama Gas Corporation	'	'
Current Assets	'	'
Cash and cash equivalents	8,541	5,559
Accounts receivable	'	'
Gas	39,962	94,011
Other	4,655	5,117
Affiliated companies	6,579	5,742
Allowance for doubtful accounts	-5,300	-5,700
Inventories	'	'
Storage gas inventory	39,507	32,205
Materials and supplies	5,401	5,528
Liquified natural gas in storage	2,990	3,498
Regulatory asset	11,213	45,515
Income tax receivable	1,601	2,762
Deferred income taxes	22,314	18,799
Prepayments and other	6,595	4,451
Total current assets	144,058	217,487
Property, Plant and Equipment	'	'
Utility plant	1,471,174	1,416,590
Less accumulated depreciation	594,604	573,947
Utility plant, net	876,570	842,643
Other property, net	41	42
Other Assets	'	'
Regulatory asset	89,004	110,566
Pension and other postretirement assets	13,399	848
Deferred charges and other	10,994	11,290
Total other assets	113,397	122,704
TOTAL ASSETS	1,134,066	1,182,876
Current Liabilities	'	'
Notes payable to banks	49,000	77,000
Accounts payable	32,997	51,741
Accrued taxes	28,635	24,186
Customers’ deposits	20,531	24,705
Amounts due customers	19,974	19,718
Accrued wages and benefits	8,154	6,703
Regulatory liability	40,168	45,116
Other	9,293	9,018
Total current liabilities	208,752	258,187
Long-term debt	249,973	250,028
Deferred Credits and Other Liabilities	'	'
Pension and other postretirement liabilities	28,371	43,611
Regulatory liability	81,414	80,404
Deferred income taxes	199,372	189,381
Other	1,446	762
Total deferred credits and other liabilities	310,603	314,158
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	330,234	325,999
Accumulated other comprehensive income (loss), net of tax	'	'
Total shareholders’ equity	364,738	360,503
Total capitalization	614,711	610,531
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY	$1,134,066	$1,182,876

Consolidated_Condensed_Balance1

Consolidated Condensed Balance Sheets (Parenthetical) (USD $)	Sep. 30, 2013	Dec. 31, 2012
In Thousands, except Share data, unless otherwise specified
Current Assets	'	'
Allowance for doubtful accounts	$5,296	$6,549
Shareholders’ Equity	'	'
Preferred stock, par value	$0.01	$0.01
Preferred stock, shares authorized	5,000,000	5,000,000
Common stock, par value	$0.01	$0.01
Common stock, shares authorized	150,000,000	150,000,000
Common stock, shares issued	75,485,159	75,067,760
Treasury stock, shares	2,977,920	2,998,620
Alabama Gas Corporation	'	'
Current Assets	'	'
Allowance for doubtful accounts	$5,300	$5,700
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

Consolidated_Condensed_Stateme3

Consolidated Condensed Statements of Cash Flows (USD $)	9 Months Ended
In Thousands, unless otherwise specified	Sep. 30, 2013	Sep. 30, 2012
Operating Activities	'	'
Net Income (Loss)	$120,461	$190,739
Adjustments to reconcile net income to net cash provided by operating activities:	'	'
Depreciation and amortization	365,355	276,465
Depreciation, depletion and amortization	392,854	300,863
Asset impairment	24,612	21,545
Accretion expense	6,131	5,581
Deferred income taxes	51,682	80,724
Bad debt expense	1,203	370
Exploratory expense	8,759	11,420
Change in derivative fair value	53,581	-34,469
Gain on sale of assets	-10,980	-420
Stock based compensation expense	11,759	6,820
Other, net	25,455	10,779
Net change in:	'	'
Accounts receivable	50,767	57,334
Inventories	1,169	62
Accounts payable	-74,183	-12,562
Amounts due customers, including gas supply pass-through	36,891	-52,466
Income tax receivable	-989	1,817
Pension and other postretirement benefit contributions	-11,332	-5,056
Other current assets and liabilities	40,176	20,038
Net cash provided by operating activities	728,016	603,119
Investing Activities	'	'
Additions to property, plant and equipment	-961,798	-898,202
Acquisitions, net of cash acquired	-21,400	-104,200
Proceeds from sale of assets	16,220	2,420
Other, net	-1,210	-746
Net cash used in investing activities	-968,188	-1,000,728
Financing Activities	'	'
Payment of dividends on common stock	-31,454	-30,292
Issuance of common stock	13,680	1,164
Payment of long-term debt	-55	-1,143
Net change in short-term debt	258,000	465,000
Tax benefit on stock compensation	2,710	514
Other	0	-38
Net cash provided by financing activities	242,881	435,205
Net change in cash and cash equivalents	2,709	37,596
Cash and cash equivalents at beginning of period	9,704	9,541
Cash and Cash Equivalents at End of Period	12,413	47,137
Alabama Gas Corporation	'	'
Operating Activities	'	'
Net Income (Loss)	37,557	37,205
Adjustments to reconcile net income to net cash provided by operating activities:	'	'
Depreciation and amortization	32,665	31,551
Deferred income taxes	6,448	9,431
Bad debt expense	1,120	364
Gain on sale of assets	10,889	0
Other, net	1,524	4,681
Net change in:	'	'
Accounts receivable	19,801	29,539
Inventories	-6,667	5,975
Accounts payable	-16,181	-17,222
Amounts due customers, including gas supply pass-through	36,891	-52,466
Income tax receivable	1,161	6,002
Pension and other postretirement benefit contributions	-5,848	-2,044
Other current assets and liabilities	-112	-9,795
Net cash provided by operating activities	119,248	43,221
Investing Activities	'	'
Additions to property, plant and equipment	-67,085	-49,746
Proceeds from sale of assets	13,838	0
Other, net	-1,642	2,490
Net cash used in investing activities	-54,889	-47,256
Financing Activities	'	'
Payment of dividends on common stock	-33,322	-28,182
Payment of long-term debt	-55	-143
Net increases in advances from affiliates	0	24,867
Net change in short-term debt	-28,000	10,000
Other	0	-38
Net cash provided by financing activities	-61,377	6,504
Net change in cash and cash equivalents	2,982	2,469
Cash and cash equivalents at beginning of period	5,559	7,817
Cash and Cash Equivalents at End of Period	$8,541	$10,286

Basis_of_Presentation

Basis of Presentation	9 Months Ended
	Sep. 30, 2013
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, 2012, 2011 and 2010, included in the 2012 Annual Report of Energen Corporation (the Company) and Alabama Gas Corporation (Alagasco) on Form 10-K. Alagasco has a September 30 fiscal year for rate-setting purposes (rate year) and reports on a calendar year for the Securities and Exchange Commission and all other financial accounting reporting purposes. The accompanying unaudited condensed financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America for interim financial information and with the instructions to Form 10-Q and Rule 10-01 of Regulation S-X. Accordingly, they do not include all of the disclosures required for complete financial statements. The Company’s natural gas distribution business is seasonal in character and influenced by weather conditions. Results of operations for interim periods are not necessarily indicative of the results that may be expected for the year. All adjustments to the unaudited condensed financial statements that are, in the opinion of management, necessary for a fair statement of the results for the interim periods have been recorded. Such adjustments consist of normal recurring items. Certain reclassifications were made to conform prior years’ financial statements to the current-quarter presentation.
	On December 31, 2012, the Company and Alagasco revised the presentation of outstanding checks in its financial statements to reflect outstanding checks as a reduction in cash as of the date the checks were released for payment. The effect of not revising the presentation of cash balances for the nine months ended September 30, 2012 resulted in an increase of $1.9 million and a decrease of $0.8 million to Energen and Alagasco’s operating cash flows, respectively. The Company and Alagasco determined that the amounts were not material to the respective statements of cash flows. This adjustment had no impact on Energen or Alagasco’s statements of income.

Regulatory_Matters

Regulatory Matters	9 Months Ended
	Sep. 30, 2013
Regulated Operations [Abstract]	'
Regulatory Matters	'
	REGULATORY MATTERS
	Alagasco is subject to regulation by the Alabama Public Service Commission (APSC) which established the Rate Stabilization and Equalization (RSE) rate-setting process in 1983. The Company’s current RSE order had an original term extending through December 31, 2014. At its meeting on November 5, 2013, the APSC voted to make certain RSE modifications effective January 1, 2014, which are described as follows. The term of the order is extended through September 30, 2018. Alagasco’s allowed range of return on average common equity will be 10.5 percent to 10.95 percent with an adjusting point of 10.8 percent. Alagasco is eligible to receive a performance based adjustment of 5 basis points to the return on equity adjusting point, based on meeting certain customer satisfaction criteria. The equity upon which a return will be permitted will be 56.5 percent with Alagasco allowed to budget at the cap. The inflation-based Cost Control Mechanism (CCM) will be adjusted to allow annual increases to operations and maintenance (O&M) expense using the June Consumer Price Index For All Urban Consumers (Index Range) each rate year plus or minus 1.75 percent and from a 2007 base year, adjusted for inflation using the Index Range.  Alagasco expects these modifications to be included in a final written order in the fourth quarter of 2013.
	Alagasco’s current allowed range of return on average common equity is 13.15 percent to 13.65 percent through December 31, 2013. Under RSE, the APSC conducts quarterly reviews to determine whether Alagasco’s return on average common equity at the end of the rate year will be within the allowed range of return. Reductions in rates can be made quarterly to bring the projected return within the allowed range; increases, however, are allowed only once each rate year, effective December 1, and cannot exceed 4 percent of prior-year revenues. During the three months and nine months ended September 30, 2013, Alagasco had a net $4.3 million pre-tax and a net $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. Additionally, during the three months and nine months ended September 30, 2013, Alagasco had a $10.9 million reduction in revenues related to the sale of its Metro Operations Center in August 2013. During the three months and nine months ended September 30, 2012, Alagasco had a net $1.3 million and a net $6.3 million pre-tax, respectively, reduction in revenues to bring the return on average common equity to midpoint within the allowed range of return. Under the provisions of RSE, a $7.8 million and a $13.0 million annual increase in revenues became effective December 1, 2012 and 2011, respectively.
	RSE currently limits the utility’s equity upon which a return is permitted to 55 percent of total capitalization, subject to certain adjustments. Currently, under the inflation-based CCM established by the APSC, if the percentage change in O&M expense on an aggregate basis falls within a range of 0.75 points above or below the percentage change in the September Index Range on a rate year basis, no adjustment is required. If the change in O&M expense on an aggregate basis exceeds the Index Range, three-quarters of the difference is returned to customers. To the extent the change is less than the Index Range, the utility benefits by one-half of the difference through future rate adjustments. The O&M expense base for measurement purposes will be set at the prior year’s actual O&M expense amount unless the Company exceeds the top of the Index Range in two successive years, in which case the base for the following year will be set at the top of the Index Range. Certain items that fluctuate based on situations demonstrated to be beyond Alagasco’s control may be excluded from the CCM calculation. Alagasco’s O&M expense fell within the Index Range for the rate years ended September 30, 2013 and 2012.
	Alagasco’s rate schedules for natural gas distribution charges contain a Gas Supply Adjustment (GSA) rider, established in 1993, which permits the pass-through to customers of changes in the cost of gas supply. Alagasco’s tariff provides a temperature adjustment mechanism, also included in the GSA, that is designed to moderate the impact of departures from normal temperatures on Alagasco’s earnings. The temperature adjustment applies primarily to residential, small commercial and small industrial customers. Other non-temperature weather related conditions that may affect customer usage are not included in the temperature adjustment.
	The APSC approved an Enhanced Stability Reserve (ESR) in 1998, which was subsequently modified and expanded in 2010. As currently approved, the ESR provides deferred treatment and recovery for the following: (1) extraordinary O&M expenses related to environmental response costs; (2) extraordinary O&M expenses related to self insurance costs that exceed $1 million per occurrence; (3) extraordinary O&M expenses, other than environmental response costs and self insurance costs, resulting from a single force majeure event or multiple force majeure events greater than $275,000 and $412,500, respectively, during a rate year; and (4) negative individual large commercial and industrial customer budget revenue variances that exceed $350,000 during a rate year.
	Charges to the ESR are subject to certain limitations which may disallow deferred treatment and which proscribe the timing of recovery. Funding to the ESR is provided as a reduction to the refundable negative salvage balance over its nine year term beginning December 1, 2010. Subsequent to the nine year period and subject to APSC authorization, Alagasco anticipates recovering underfunded ESR balances over a five year amortization period with an annual limitation of $660,000. Amounts in excess of this limitation are deferred for recovery in future years.

Derivative_Commodity_Instrumen

Derivative Commodity Instruments	9 Months Ended
	Sep. 30, 2013
Derivative Instruments and Hedging Activities Disclosure [Abstract]	'
Derivative Commodity Instruments	'
	DERIVATIVE COMMODITY INSTRUMENTS
	Energen Resources Corporation, Energen’s oil and gas subsidiary, periodically enters into derivative commodity instruments to hedge its exposure to price fluctuations on oil, natural gas and natural gas liquids production. In prior years, Alagasco entered into cash flow derivative commodity instruments to hedge its exposure to price fluctuations on its gas supply. Such instruments may include over-the-counter (OTC) swaps and basis hedges typically with investment and commercial banks and energy-trading firms. Hedge transactions are pursuant to standing authorizations by the Board of Directors, which do not authorize speculative positions. The Company recognizes all derivatives on the balance sheet and measures all derivatives at fair value. All derivative transactions are included in operating activities on the consolidated condensed statements of cash flows.
	The Company is at risk for economic loss based upon the creditworthiness of its counterparties. Energen Resources was in a net gain position with seven of its active counterparties and in a net loss position with the remaining six at September 30, 2013. The largest counterparty net loss position at September 30, 2013, Morgan Stanley Capital Group, constituted approximately $19.8 million of Energen Resources’ total net loss on fair value of derivatives. At September 30, 2013, Energen Resources was in a net gain position with Macquarie Bank Limited for approximately $10.0 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 September 30, 2013, 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.
	Prior to June 30, 2013, the Company utilized cash flow hedge accounting where applicable for its derivative transactions. 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 other derivative transactions not previously qualified for cash flow hedge accounting are still considered by management to represent valid economic hedges and are accounted for as mark-to-market transactions. These derivatives are recorded at fair value with gains or losses recognized in operating revenues in the period of change.
	Effective March 31, 2013 and June 30, 2013, Energen Resources dedesignated 5,078 thousand barrels (MBbl) and 2,353 MBbl, respectively, of various Permian Basin New York Mercantile Exchange (NYMEX) oil contracts due to lack of correlation. Any gains or losses from inception of the hedge to the dedesignation date were frozen and will remain in accumulated other comprehensive income until the forecasted transactions actually occur.  Any subsequent gains or losses will be accounted for as mark-to-market and recognized immediately through operating revenues.
	Effective June 30, 2013, the Company elected to discontinue the use of cash flow hedge accounting and to dedesignate all remaining derivative commodity instruments that were previously designated as cash flow hedges. As a result of discontinuing hedge accounting, any gains or losses from inception of the hedge to June 30, 2013 were frozen and will remain in accumulated other comprehensive income until the forecasted transactions actually occur. Any subsequent gains or losses will be accounted for as mark-to-market and recognized immediately through operating revenues. As a result of the Company’s election to discontinue hedge accounting, all derivative transactions entered into subsequent to June 30, 2013 will be accounted for as mark-to-market transactions with gains or losses recognized in operating revenues in the period of change.
	The following tables detail the fair values of commodity contracts by business segment on the balance sheets:
	(in thousands)	September 30, 2013
		Oil and Gas Operations				Natural Gas Distribution			Total
	Derivative assets or (liabilities) not designated as hedging instruments
	Accounts receivable	$	53,082			$	—		$	53,082
	Long-term asset derivative instruments	18,346				—			18,346
	Total derivative assets	71,428				—			71,428
	Accounts receivable	(40,789		)	*	—			(40,789		)
	Long-term asset derivative instruments	(5,560		)	*	—			(5,560		)
	Accounts payable	(31,928		)		—			(31,928		)
	Long-term liability derivative instruments	(1,379		)		—			(1,379		)
	Total derivative liabilities	(79,656		)		—			(79,656		)
	Total derivatives not designated	$	(8,228	)		$	—		$	(8,228	)
	(in thousands)	December 31, 2012
		Oil and Gas Operations				Natural Gas Distribution			Total
	Derivative assets or (liabilities) designated as hedging instruments
	Accounts receivable	$	87,514			$	—		$	87,514
	Long-term asset derivative instruments	37,954				—			37,954
	Total derivative assets	125,468				—			125,468
	Accounts receivable	(37,326		)	*	—			(37,326		)
	Long-term asset derivative instruments	(6,810		)	*	—			(6,810		)
	Long-term liability derivative instruments	(8,726		)		—			(8,726		)
	Total derivative liabilities	(52,862		)		—			(52,862		)
	Total derivatives designated	72,606				—			72,606
	Derivative assets or (liabilities) not designated as hedging instruments
	Accounts receivable	14,604				—			14,604
	Long-term asset derivative instruments	9,433				—			9,433
	Total derivative assets	24,037				—			24,037
	Accounts payable	—				(2,593		)	(2,593		)
	Long-term liability derivative instruments	(874		)		—			(874		)
	Total derivative liabilities	(874		)		(2,593		)	(3,467		)
	Total derivatives not designated	23,163				(2,593		)	20,570
	Total derivatives	$	95,769			$	(2,593	)	$	93,176
	* 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 $10.3 million and a net $28.4 million deferred tax liability included in current and noncurrent deferred income taxes on the consolidated condensed balance sheets related to derivative items included in OCI as of September 30, 2013, and December 31, 2012, respectively.
	The following table details the effect of derivative commodity instruments in cash flow hedging relationships on the financial statements:
	(in thousands)	Location on Statement of Income	Three months			Three months
			ended			ended
			30-Sep-13			30-Sep-12
	Gain (loss) recognized in OCI on derivatives (effective portion), net of tax of $42 and ($30,622)	—	$	69		$	(49,962	)
	Gain reclassified from accumulated OCI into income (effective portion)	Operating revenues	$	8,455		$	15,998
	Loss recognized in income on derivatives (ineffective portion and amount excluded from effectiveness testing)	Operating revenues	$	(22	)	$	(3,042	)
	(in thousands)	Location on Statement of Income	Nine months			Nine months
			ended			ended
			30-Sep-13			30-Sep-12
	Gain (loss) recognized in OCI on derivatives (effective portion), net of tax of ($6,669) and $30,621	—	$	(10,882	)	$	49,961
	Gain reclassified from accumulated OCI into income (effective portion)	Operating revenues	$	29,391		$	39,012
	Gain (loss) recognized in income on derivatives (ineffective portion and amount excluded from effectiveness testing)	Operating revenues	$	835		$	(1,372	)
	The following table details the effect of open and closed derivative commodity instruments not designated as hedging instruments on the income statement:
	(in thousands)	Location on Statement of Income	Three months			Three months
			ended			ended
			30-Sep-13			30-Sep-12
	Loss recognized in income on derivatives	Operating revenues	$	(92,313	)	$	(45,618	)
	(in thousands)	Location on Statement of Income	Nine months			Nine months
			ended			ended
			30-Sep-13			30-Sep-12
Gain (loss) recognized in income on derivatives	Operating revenues	$	(70,735	)	$	33,825
As of September 30, 2013, $13.1 million, net of tax, of deferred net gains on derivative instruments recorded in accumulated other comprehensive income are expected to be reclassified and reported in earnings as operating revenues during the next twelve-month period. As of September 30, 2013, the Company had 13.5 billion cubic feet (Bcf), 51.8 Bcf and 6.0 Bcf of natural gas hedges which expire during 2013, 2014 and 2015, respectively, that are considered mark-to-market transactions. The Company had 4.4 million barrels (MMBbl), 9.8 MMBbl and 5.8 MMBbl of oil and oil basis hedges which expire during 2013, 2014 and 2015, respectively, that are considered mark-to-market transactions. The Company had 11.9 million gallons (MMgal) and 1.9 MMgal of natural gas liquid hedges which expire during 2013 and 2014, respectively, that are considered mark-to-market transactions. During 2013, the Company discontinued hedge accounting and reclassified gains of $6.7 million after-tax from other comprehensive income into operating revenues when Energen Resources determined it was probable certain forecasted volumes would not occur due to certain properties being held for sale.
Energen Resources entered into the following transactions for the remainder of 2013 and subsequent years:
Production Period	Total Hedged Volumes		Average Contract	Description
			Price
Natural Gas
2013	3	Bcf	$4.82 Mcf	NYMEX Swaps
	8.9	Bcf	$4.51 Mcf	Basin Specific Swaps - San Juan
	1.6	Bcf	$3.64 Mcf	Basin Specific Swaps - Permian
2014	10.6	Bcf	$4.55 Mcf	NYMEX Swaps
	31.4	Bcf	$4.60 Mcf	Basin Specific Swaps - San Juan
	9.7	Bcf	$3.81 Mcf	Basin Specific Swaps - Permian
2015	6	Bcf	$4.07 Mcf	Basin Specific Swaps - San Juan
Oil
2013	2,434	MBbl	$91.44 Bbl	NYMEX Swaps
2014	9,796	MBbl	$92.64 Bbl	NYMEX Swaps
2015	5,760	MBbl	$88.85 Bbl	NYMEX Swaps
Oil Basis Differential
2013	907	MBbl	$(2.99) Bbl	WTS/WTI Basis Swaps*
	1,070	MBbl	$(1.00) Bbl	WTI/WTI Basis Swaps**
Natural Gas Liquids
2013	12	MMGal	$1.02 Gal	Liquids Swaps
*WTS - West Texas Sour/Midland, WTI - West Texas Intermediate/Cushing
**WTI - West Texas Intermediate/Midland, WTI - West Texas Intermediate/Cushing
As of September 30, 2013, the maximum term over which Energen Resources has hedged exposures to the variability of cash flows is through December 31, 2015. Alagasco has not entered into any cash flow derivative transactions on its gas supply since 2010.
The following sets forth derivative assets and liabilities that were measured at fair value on a recurring basis:
	September 30, 2013
(in thousands)	Level 2*			Level 3*			Total
Current assets	$	(12,712	)	$	25,005		$	12,293
Noncurrent assets	6,828			5,958			12,786
Current liabilities	(40,970		)	9,042			(31,928		)
Noncurrent liabilities	(2,580		)	1,201			(1,379		)
Net derivative asset (liability)	$	(49,434	)	$	41,206		$	(8,228	)
	31-Dec-12
(in thousands)	Level 2*			Level 3*			Total
Current assets	$	(3,629	)	$	68,421		$	64,792
Noncurrent assets	18,899			21,678			40,577
Current liabilities	(2,593		)	—			(2,593		)
Noncurrent liabilities	(8,520		)	(1,080		)	(9,600		)
Net derivative asset	$	4,157		$	89,019		$	93,176
* Amounts classified in accordance with accounting guidance which permits offsetting fair value amounts recognized for multiple derivative instruments executed with the same counterparty under a master netting arrangement.
As of September 30, 2013, Alagasco had no derivative instruments. As of December 31, 2012, Alagasco had $2.6 million of derivative instruments which were classified as Level 2 fair values and included in the above table as current liabilities. Alagasco had no derivative instruments classified as Level 3 fair values as of December 31, 2012.
The Company has prepared a sensitivity analysis to evaluate the hypothetical effect that changes in the prices used to estimate fair value would have on the fair value of its derivative instruments. The Company estimates that a 10 percent increase or decrease in commodity prices would result in an approximate $22 million change in the fair value of open Level 3 derivative contracts. The resulting impact upon the results of operations would be an approximate $22 million associated with open Level 3 mark-to-market derivative contracts. Cash flow requirements to meet the obligation would not be significantly impacted as gains and losses on the derivative contracts would be similarly offset by sales at the spot market price.
The tables below set forth a summary of changes in the fair value of the Company’s Level 3 derivative commodity instruments as follows:
	Three months ended			Three months ended
(in thousands)	September 30, 2013			September 30, 2012
Balance at beginning of period	$	51,131		$	103,456
Realized gains	10,852			18,737
Unrealized losses relating to instruments held at the reporting date*	(10,947		)	(46,983		)
Settlements during period	(9,830		)	(17,929		)
Balance at end of period	$	41,206		$	57,281
	Nine months ended			Nine months ended
(in thousands)	September 30, 2013			September 30, 2012
Balance at beginning of period	$	89,019		$	65,801
Realized gains	41,952			51,858
Unrealized losses relating to instruments held at the reporting date*	(48,835		)	(9,328		)
Settlements during period	(40,930		)	(51,050		)
Balance at end of period	$	41,206		$	57,281
*Includes $0.8 million and $4.7 million in mark-to-market gains for the three months and nine months ended September 30, 2013, respectively. Includes $7.9 million and $4.5 million in mark-to-market losses for the three months and nine months ended September 30, 2012, respectively.
The tables below set forth quantitative information about the Company’s Level 3 fair value measurements of derivative commodity instruments as follows:
(in thousands)	Fair Value as of September 30, 2013			Valuation Technique*	Unobservable Input*	Range
Natural Gas Basis - San Juan
2013	$	9,499		Discounted Cash Flow	Forward Basis	($0.12 - $0.14) Mcf
2014	$	27,678		Discounted Cash Flow	Forward Basis	($0.13 - $0.15) Mcf
2015	$	1,201		Discounted Cash Flow	Forward Basis	($0.20) Mcf
Natural Gas Basis - Permian
2013	$	286		Discounted Cash Flow	Forward Basis	($0.14) Mcf
2014	$	825		Discounted Cash Flow	Forward Basis	($0.13 - $0.15) Mcf
Oil Basis - WTS/WTI
2013	$	(1,897	)	Discounted Cash Flow	Forward Basis	($1.06) Bbl
Oil Basis - WTI/WTI
2013	$	(641	)	Discounted Cash Flow	Forward Basis	($0.41 - $0.50) Bbl
Natural Gas Liquids
2013	$	4,255		Discounted Cash Flow	Forward Price	$0.74 - $0.81 Gal
*Discounted cash flow represents an income approach in calculating fair value including the referenced unobservable input and a discount reflecting credit quality of the counterparty.
The tables below set forth information about the offsetting of derivative assets and liabilities as follows:
	September 30, 2013
										Gross Amounts Not Offset in the Balance Sheets
(in thousands)	Gross Amounts Recognized			Gross Amounts Offset in the Balance Sheets			Net Amount Presented in the Balance Sheets			Financial Instruments		Cash Collateral Received		Net Amount
Derivative assets	$	71,428		$	(46,349	)	$	25,079		$	—	$	—	$	25,079
Derivative liabilities	$	79,656		$	(46,349	)	$	33,307		$	—	$	—	$	33,307
	31-Dec-12
										Gross Amounts Not Offset in the Balance Sheets
(in thousands)	Gross Amounts Recognized			Gross Amounts Offset in the Balance Sheets			Net Amount Presented in the Balance Sheets			Financial Instruments		Cash Collateral Received		Net Amount
Derivative assets	$	149,504		$	(44,135	)	$	105,369		$	—	$	—	$	105,369
Derivative liabilities	$	56,328		$	(44,135	)	$	12,193		$	—	$	—	$	12,193

Reconciliation_of_Earnings_Per

Reconciliation of Earnings Per Share (EPS)	9 Months Ended
	Sep. 30, 2013
Earnings Per Share [Abstract]	'
Reconciliation of Earnings Per Share (EPS)	'
	RECONCILIATION OF EARNINGS PER SHARE (EPS)
		Three months ended							Three months ended
	(in thousands, except per share amounts)	September 30, 2013							September 30, 2012
		Net				Per Share			Net			Per Share
		Loss			Shares	Amount			Income		Shares	Amount
	Basic EPS	$	(19,298	)	72,346	$	(0.27	)	$	2,046	72,130	$	0.03
	Effect of dilutive securities
	Stock options				—						183
	Non-vested restricted stock				—						3
	Diluted EPS	$	(19,298	)	72,346	$	(0.27	)	$	2,046	72,316	$	0.03
	In periods of loss, shares that otherwise would have been included in diluted average common shares outstanding are excluded. The Company had 242,560 of excluded shares for the three months ended September 30, 2013.
		Nine months ended							Nine months ended
	(in thousands, except per share amounts)	September 30, 2013							September 30, 2012
		Net				Per Share			Net			Per Share
		Income			Shares	Amount			Income		Shares	Amount
	Basic EPS	$	120,461		72,220	$	1.67		$	190,739	72,121	$	2.64
	Effect of dilutive securities
	Stock options				41						177
	Non-vested restricted stock				10						3
	Performance share awards				1						—
	Diluted EPS	$	120,461		72,272	$	1.67		$	190,739	72,301	$	2.64
	The Company had the following shares that were excluded from the computation of diluted EPS, as their effect was non-dilutive:
		Three months ended				Nine months ended
		September 30,				September 30,
	(in thousands)	2013		2012		2013		2012
	Stock options	—		850		875		850
	Performance share awards	—		—		79		—

Segment_Information

Segment Information	9 Months Ended
	Sep. 30, 2013
Segment Reporting [Abstract]	'
Segment Information	'
	SEGMENT INFORMATION
	The Company principally is engaged in two business segments: the development, acquisition, exploration and production of oil and gas in the continental United States (oil and gas operations) and the purchase, distribution and sale of natural gas in central and north Alabama (natural gas distribution).
		Three months ended						Nine months ended
		September 30,						September 30,
	(in thousands)	2013			2012			2013			2012
	Operating revenues from continuing operations
	Oil and gas operations	$	272,038		$	214,620		$	875,350		$	799,339
	Natural gas distribution	48,368			61,809			390,567			327,183
	Total	$	320,406		$	276,429		$	1,265,917		$	1,126,522
	Operating income (loss) from continuing operations
	Oil and gas operations	$	18,607		$	26,913		$	181,948		$	280,897
	Natural gas distribution	(22,544		)	(12,743		)	58,968			70,265
	Eliminations and corporate expenses	(115		)	(206		)	(345		)	(857		)
	Total	$	(4,052	)	$	13,964		$	240,571		$	350,305
	Other income (expense)
	Oil and gas operations	$	(13,209	)	$	(12,703	)	$	(38,686	)	$	(35,402	)
	Natural gas distribution	7,973			(3,274		)	1,477			(10,062		)
	Eliminations and other	175			186			405			390
	Total	$	(5,061	)	$	(15,791	)	$	(36,804	)	$	(45,074	)
	Income (loss) from continuing operations before income taxes	$	(9,113	)	$	(1,827	)	$	203,767		$	305,231
	(in thousands)	September 30, 2013			December 31, 2012
	Identifiable assets
	Oil and gas operations	$	5,444,672		$	4,975,170
	Natural gas distribution	1,127,487			1,177,134
	Eliminations and other	42,713			23,586
	Total	$	6,614,872		$	6,175,890

Stock_Compensation

Stock Compensation	9 Months Ended
	Sep. 30, 2013
Share-based Compensation [Abstract]	'
Stock Compensation	'
	STOCK COMPENSATION
	Stock Incentive Plan
	Stock Options: The Stock Incentive Plan provides for the grant of incentive stock options, non-qualified stock options, restricted stock, performance shares or a combination thereof to officers and key employees. Options granted under the Stock Incentive Plan provide for the purchase of Company common stock at not less than the fair market value on the date the option is granted. The sale or transfer of the shares is limited during certain periods. All outstanding options vest within three years from date of grant and expire 10 years from the grant date. The Company granted 134,076 non-qualified option shares during the first quarter of 2013 with a grant-date fair value of $16.66.
	Restricted Stock: Additionally, the Stock Incentive Plan provides for the grant of restricted stock. In January 2013, 46,121 shares of restricted stock were awarded with a grant date fair value of $48.36. These awards were valued based on the quoted market price of the Company’s common stock at the date of grant and have a three year vesting period.
	Performance Share Awards: The Stock Incentive Plan also provides for the grant of performance share awards, with each unit equal to the market value of one share of common stock, to eligible employees based on predetermined Company performance criteria at the end of an award period. The Stock Incentive Plan provides that payment of earned performance share awards be made in the form of Company common stock. Performance share awards are valued in a Monte Carlo model which uses historical volatility and other variables to estimate the probability of satisfying the market condition of the award. The Company granted 84,311 performance share awards during the first quarter of 2013 with a two year vesting period and a grant-date fair value of $59.19. The Company also granted 80,395 performance share awards during the first quarter of 2013 with a three year award period and a grant-date fair value of $60.81.
	Stock Appreciation Rights Plan
	The Energen 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 88,000 awards during the first quarter of 2013. These awards had a fair value of $39.10 as of September 30, 2013.
	Petrotech Incentive Plan
	The Energen Resources’ Petrotech Incentive Plan provides for the grant of stock equivalent units. These awards are liability awards which settle in cash and are re-measured each reporting period until settlement. During the first quarter of 2013, Energen Resources awarded 33,796 Petrotech units with a fair value of $75.67 as of September 30, 2013, none of which included a market condition. Also awarded were 52,768 Petrotech units which included a market condition and had a fair value of $133.58 as of September 30, 2013. These awards have a three-year vesting period. During the third quarter of 2013, Energen Resources awarded 5,854 Petrotech units with a three-year vesting period and a fair value of $75.67 as of September 30, 2013, and 2,952 Petrotech units with a seventeen-month vesting period and a fair value of $75.88 as of September 30, 2013, none of which included a market condition.
	Stock Repurchase Program
	During the three months and nine months ended September 30, 2013, the Company had noncash purchases of approximately $0.8 million and $0.9 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.

Employee_Benefit_Plans

Employee Benefit Plans	9 Months Ended
	Sep. 30, 2013
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						Nine months ended
		September 30,						September 30,
	(in thousands)	2013			2012			2013			2012
	Components of net periodic benefit cost:
	Service cost	$	3,602		$	2,632		$	10,806		$	7,895
	Interest cost	2,725			2,700			8,161			8,101
	Expected long-term return on assets	(3,713		)	(3,563		)	(11,139		)	(10,689		)
	Actuarial loss	3,597			2,099			10,962			6,297
	Prior service cost amortization	123			129			367			388
	Settlement charge	17			—			161			—
	Net periodic expense	$	6,351		$	3,997		$	19,318		$	11,992
	There are no required contributions to the qualified pension plans during 2013. Additionally, it is not anticipated that the funded status of the qualified pension plans will fall below statutory thresholds requiring accelerated funding or constraints on benefit levels or plan administration. The Company made a discretionary contribution of $9.0 million to the qualified pension plans in January 2013. No additional discretionary contributions are expected to be made to the pension plans during 2013. During 2014, the Company may make discretionary contributions to the qualified pension plans depending on the amount and timing of employee retirements and market conditions. For the three months and nine months ending September 30, 2013, the Company made benefit payments aggregating $0.2 million and $1.1 million, respectively, to retirees from the nonqualified supplemental retirement plans and expects to make additional benefit payments of approximately $36,000 through the remainder of 2013. In the first quarter of 2013, the Company incurred a settlement charge of $0.5 million for the payment of lump sums from the nonqualified supplemental retirement plans, of which $0.1 million was expensed and $0.4 million was recognized as a pension and postretirement asset in regulatory assets at Alagasco. In the third quarter of 2013, the Company incurred a settlement charge of $64,000 for the payment of lump sums from the nonqualified supplemental retirement plans, of which $18,000 was expensed and $46,000 was recognized as a pension and postretirement asset in regulatory assets at Alagasco.
	The components of net periodic postretirement benefit expense for the Company’s postretirement benefit plans were:
		Three months ended						Nine months ended
		September 30,						September 30,
	(in thousands)	2013			2012			2013			2012
	Components of net periodic benefit cost:
	Service cost	$	444		$	463		$	1,333		$	1,390
	Interest cost	869			1,062			2,605			3,186
	Expected long-term return on assets	(1,242		)	(1,109		)	(3,727		)	(3,328		)
	Actuarial loss	—			9			—			27
	Transition amortization	324			479			973			1,438
	Net periodic expense	$	395		$	904		$	1,184		$	2,713
	For the three months and nine months ended September 30, 2013, the Company made contributions aggregating $0.4 million and $1.2 million to the postretirement benefit plans. The Company expects to make additional discretionary contributions of approximately $0.4 million to the postretirement benefit plans through the remainder of 2013.

Commitments_and_Contingencies

Commitments and Contingencies	9 Months Ended
	Sep. 30, 2013
Commitments and Contingencies Disclosure [Abstract]	'
Commitments and Contingencies	'
	COMMITMENTS AND CONTINGENCIES
	Commitments and Agreements: Under various agreements for third party gathering, treatment, transportation or other services, Energen Resources is committed to deliver minimum production volumes or to pay certain costs in the event the minimum quantities are not delivered. These delivery commitments are approximately 7.5 million barrels of oil equivalent (MMBOE) through September 2017.
	Energen Resources entered into three agreements which commenced at various dates from November 15, 2011 to January 15, 2012 and expire at various dates through January 2015 to secure drilling rigs necessary to execute a portion of its drilling plans. In the unlikely event that Energen Resources discontinues use of these drilling rigs, Energen Resources’ total resulting exposure could be as much as $14 million depending on the contractor’s ability to remarket the drilling rig.
	Certain of Alagasco’s long-term contracts associated with the delivery and storage of natural gas include fixed charges of approximately $185 million through September 2024. During both the nine months ending September 30, 2013 and 2012, Alagasco recognized approximately $36.8 million of long-term commitments through expense and its regulatory accounts in the accompanying financial statements. Alagasco also is committed to purchase minimum quantities of gas at market-related prices or to pay certain costs in the event the minimum quantities are not taken. These purchase commitments are approximately 146 Bcf through August 2020.
	Alagasco purchases gas as an agent for certain of its large commercial and industrial customers. Alagasco has, in certain instances, provided commodity-related guarantees to the counterparties in order to facilitate these agency purchases. Liabilities existing for gas delivered to customers subject to these guarantees are included in the balance sheets. In the event the customer for whom the guarantee was entered fails to take delivery of the gas, Alagasco can sell such gas for the customer, with the customer liable for any resulting loss. Although the substantial majority of purchases under these guarantees are for the customers’ current monthly consumption and are at current market prices, in some instances, the purchases are for an extended term at a fixed price. At September 30, 2013, the fixed price purchases under these guarantees had a maximum term outstanding through October 2014 and an aggregate purchase price of $0.8 million with a market value of $0.8 million.
	Income Taxes: The Company uses the liability method of accounting for income taxes. Under this method, a deferred tax asset or liability is recognized for the estimated future tax effects attributable to temporary differences between the financial statement basis and the tax basis of assets and liabilities as well as tax credit carryforwards.  In accordance with Accounting Standards Codification 740-30-25-7, the Company has not recognized a deferred tax liability for the difference between the book basis and the tax basis in the stock of its subsidiaries. The unrecorded gross outside basis difference for Alagasco exceeds the recorded inside asset basis difference by approximately $35 million and would result in an additional deferred tax liability of $13 million.
	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.
	Energen Resources previously disclosed an adverse judgment relating to the ownership of the company operated Cadenhead 25-1 Well (the Cadenhead Well) in Ward County, Texas.  Upon a Motion to Reconsider, the adverse judgment was vacated by the District Court in Ward County, Texas and a Summary Judgment Order dated July 30, 2013 was entered confirming Energen Resources’ superior title to the Cadenhead Well and its associated oil and gas leases.  The Summary Judgment Order has been appealed by the other party.
	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.
	Under oversight of the Site Remediation Section of the Railroad Commission of Texas, the Company is currently in the process of cleanup and remediation of oil and gas wastes in nine reserve pits in Mitchell County, Texas. The Company estimates that the cleanup, remediation and related costs will approximate $1.8 million of which $1.6 million has been incurred and $0.2 million has been reserved.
	Alagasco is in the chain of title of nine former manufactured gas plant sites, four of which it still owns, and five former manufactured gas distribution sites, one of which it still owns. Management expects that, should future remediation of the sites be required, Alagasco’s share of the remediation costs will not materially affect the financial position of Alagasco. During 2011, a removal action was completed at the Huntsville, Alabama manufactured gas plant site pursuant to an Administrative Settlement Agreement and Order on Consent among the United States Environmental Protection Agency (EPA), Alagasco and the current site owner. In 2012, Alagasco responded to an EPA Request for Information Pursuant to Section 104 of CERCLA relating to the EPA’s investigation of a site which it refers to as the 35th Avenue Superfund Site located in Birmingham, Jefferson County, Alabama.  The Request related to a former site of a manufactured gas distribution facility owned by Alagasco and located in the vicinity of the 35th Avenue Superfund Site. In September 2013, Alagasco received from EPA a General Notice Letter and Invitation to Conduct a Removal Action at the 35th Avenue Superfund Site.  The letter identifies Alagasco as a potentially responsible party (PRP) under CERCLA for the cleanup of the Site or costs the EPA incurs in cleaning up the Site.  The EPA also offered the PRP group the opportunity to conduct Phase I of the proposed removal action which involved removal activities at approximately 50 residences that purportedly exceed certain risk levels for contamination.  Alagasco has requested additional information from EPA regarding its designation as a PRP, and an opportunity to discuss this designation further with EPA. Alagasco is unable to determine the extent, if any, of its potential liability with respect to the proposed removal action and no amount has been accrued as of September 30, 2013.
	New Mexico Audits: During the third quarter of 2010, Energen Resources received preliminary findings from the Taxation and Revenue Department (the Department) of the State of New Mexico relating to its audit, conducted on behalf of the Office of Natural Resources Revenue (ONRR), of federal oil and gas leases in New Mexico. The audit covered periods from January 2004 through December 2008 and included a review of the computation and payment of royalties due on minerals removed from specified U.S. federal leases. The ONRR has proposed certain changes in the method of determining allowable deductions of transportation, fuel and processing costs from royalties due under the terms of the related leases.
	As a result of the audit, Energen Resources has been ordered by the ONRR to pay additional royalties on the specified U.S. federal leases in the amount of $142,000 and restructure its accounting for all federal leases in two counties in New Mexico from March 1, 2004, forward. The Company preliminarily estimates that application of the Order to all of the Company’s New Mexico federal leases would result in ONRR claims for up to approximately $23 million of additional royalties plus interest and penalties for the period from March 1, 2004, forward. The preliminary findings and subsequent Order (issued April 25, 2011) are contrary to deductions allowed under previous audits, retroactive in application and inconsistent with the Company’s understanding of industry practice. The Company is vigorously contesting the Order and has requested additional information from the ONRR and the Department to assist the Company in evaluating the ONRR Order and the Department’s findings. Management is unable, at this time, to determine a range of reasonably possible losses as a result of this Order, and no amount has been accrued as of September 30, 2013.

Financial_Instruments

Financial Instruments	9 Months Ended
	Sep. 30, 2013
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, was approximately $1,188.2 million and $1,255.8 million and both had a carrying value of $1,154.0 million at September 30, 2013 and December 31, 2012, respectively. The fair value of Alagasco’s fixed-rate long-term debt, including the current portion, was approximately $262.8 million and $284.7 million and both had a carrying value of $250.0 million at September 30, 2013 and December 31, 2012, respectively. The fair values are based on market prices of similar debt issues having the same remaining maturities, redemption terms and credit rating. Short-term debt is classified as Level 1 fair value and long-term debt is classified as Level 2 fair value.
	In December 2011, the Company entered into interest rate swap agreements for $200 million of the Senior Term Loans. The swap agreements exchange a variable interest rate for a fixed interest rate of 2.4175 percent on $200 million of the principal amount outstanding. The fair value of the Company’s interest rate swap was a $2.1 million and a $3.3 million liability at September 30, 2013 and December 31, 2012, respectively, and is classified as Level 2 fair value liability. The fair value of the Company’s interest rate swap is recognized on a gross basis on the consolidated balance sheet.
	Finance Receivables: Alagasco finances third-party contractor sales of merchandise including gas furnaces and appliances. At September 30, 2013 and December 31, 2012, Alagasco’s finance receivable totaled $10.8 million and $10.7 million, respectively. These finance receivables currently have an average balance of approximately $3,000 with terms of up to 84 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. Uncollected finance receivables are written off approximately 15 months after the account has been final billed. Alagasco had finance receivables past due 90 days or more of $0.7 million and $0.5 million as of September 30, 2013 and December 31, 2012, respectively.
	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, 2012	$	470
	Provision	191
	Allowance for credit losses as of September 30, 2013	$	661

Regulatory_Assets_and_Liabilit

Regulatory Assets and Liabilities	9 Months Ended
	Sep. 30, 2013
Regulatory Assets and Liabilities Disclosure [Abstract]	'
Regulatory Assets and Liabilities	'
	REGULATORY ASSETS AND LIABILITIES
	The following table details regulatory assets and liabilities on the balance sheets:
	(in thousands)	September 30, 2013				31-Dec-12
		Current		Noncurrent		Current		Noncurrent
	Regulatory assets:
	Pension assets	$	263	$	69,249	$	170	$	90,708
	Accretion and depreciation for asset retirement obligation	—		17,579		—		16,536
	Risk management activities	—		—		2,593		—
	Rate recovery of asset removal costs, net	—		2,176		—		3,322
	Gas supply adjustment	10,925		—		42,726		—
	Other	25		—		26		—
	Total regulatory assets	$	11,213	$	89,004	$	45,515	$	110,566
	Regulatory liabilities:
	RSE adjustment	$	6,573	$	—	$	1,740	$	—
	Unbilled service margin	6,351		—		25,078		—
	Postretirement liabilities	—		13,951		—		1,237
	Refundable negative salvage	16,321		40,946		18,265		53,467
	Gain on sale of property	10,890		—		—		—
	Asset retirement obligation	—		25,772		—		24,930
	Other	33		745		33		770
	Total regulatory liabilities	$	40,168	$	81,414	$	45,116	$	80,404

Asset_Retirement_Obligations

Asset Retirement Obligations	9 Months Ended
	Sep. 30, 2013
Asset Retirement Obligation Disclosure [Abstract]	'
Asset Retirement Obligations	'
	ASSET RETIREMENT OBLIGATIONS
	The Company recognizes a liability for the fair value of asset retirement obligations (ARO) in the periods incurred. Subsequent to initial measurement, liabilities are accreted to their present value and capitalized costs are depreciated over the estimated useful life of the related assets. Upon settlement of the liability, the Company may recognize a gain or loss for differences between estimated and actual settlement costs. The ARO fair value liability is recognized on a discounted basis incorporating an estimate of performance risk specific to the Company.
	During the nine months ended September 30, 2013, 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 as of December 31, 2012	$	118,023
	Liabilities incurred	2,466
	Liabilities settled	(542		)
	Accretion expense (including discontinued operations of $944)	6,131
	Reclassification associated with held for sale properties*	(19,474		)
	Balance as of September 30, 2013	$	106,604
	* Asset retirement obligation associated with Black Warrior Basin and North Louisiana/East Texas properties are included as liabilities related to assets held for sale in current liabilities on the balance sheet.
	The Company recognizes conditional obligations if such obligations can be reasonably estimated and a legal requirement to perform an asset retirement activity exists. 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. Alagasco recorded a conditional asset retirement obligation, on a discounted basis, of $25.8 million and $24.9 million to purge and cap its gas pipelines upon abandonment as a regulatory liability as of September 30, 2013 and December 31, 2012, respectively. Regulatory assets for rate recovery of accumulated asset removal costs of $2.2 million and $3.3 million as of September 30, 2013 and December 31, 2012, are included as regulatory assets in noncurrent assets on the balance sheets. The costs associated with asset retirement obligations are either currently being recovered in rates or are probable of recovery in future rates.

Dispositions_of_Properties

Dispositions of Properties	9 Months Ended
	Sep. 30, 2013
Extractive Industries [Abstract]	'
Dispositions of Properties	'
	DISPOSITION OF PROPERTIES
	In August 2013, Alagasco recorded a pre-tax gain of $10.9 million on the sale of its Metro Operations Center which is located in Birmingham, Alabama, and has been in service since the 1940’s. The Company received approximately $13.8 million pre-tax in cash from the sale of this property. The gain on the sale was recognized in other income and a related reduction in revenues was recognized to defer the gain as a regulatory liability pending review by the APSC. Based upon the November 5, 2013 review by the APSC, Alagasco will recognize the deferred revenues from the sale in the fourth quarter of 2013. Effective upon the sale of the Metro Operations Center, Alagasco leased the facility from the purchaser for a period of approximately 20 months.

Accumulated_Other_Comprehensiv

Accumulated Other Comprehensive Income (Loss)	9 Months Ended
	Sep. 30, 2013
Equity [Abstract]	'
Accumulated Other Comprehensive Income (Loss)	'
	ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)
	The following table provides changes in the components of accumulated other comprehensive income (loss), net of the related income tax effects.
	(in thousands)	Cash Flow Hedges			Pension and Postretirement Plans			Total
	Balance as of December 31, 2012	$	44,196		$	(52,507	)	$	(8,311	)
	Other comprehensive income (loss) before reclassifications	(10,924		)	4,157			(6,767		)
	Amounts reclassified from accumulated other comprehensive income (loss)	(17,907		)	4,721			(13,186		)
	Change in accumulated other comprehensive income (loss)	(28,831		)	8,878			(19,953		)
	Balance as of September 30, 2013	$	15,365		$	(43,629	)	$	(28,264	)
	The following table provides details of the reclassifications out of accumulated other comprehensive income (loss).
		Three months ended			Nine months ended
		30-Sep-13			September 30, 2013
	(in thousands)	Amounts Reclassified						Line Item Where Presented
	Gains and (losses) on cash flow hedges:
	Commodity contracts	$	8,433		$	30,226		Operating revenues
	Interest rate swap	(446		)	(1,282		)	Interest expense
	Total cash flow hedges	7,987			28,944
	Income tax expense	(3,048		)	(11,037		)
	Net of tax	4,939			17,907
	Pension and postretirement plans:
	Transition obligation	(74		)	(220		)	Operations and maintenance
	Prior service cost	(78		)	(235		)	Operations and maintenance
	Actuarial losses*	(2,036		)	(6,387		)	Operations and maintenance
	Actuarial losses on settlement charges*	(46		)	(421		)	Regulatory asset
	Total pension and postretirement plans	(2,234		)	(7,263		)
	Income tax expense	783			2,542
	Net of tax	(1,451		)	(4,721		)
	Total reclassifications for the period	$	3,488		$	13,186
	* In the first quarter of 2013, the Company incurred a settlement charge of $0.5 million for the payment of lump sums from the nonqualified supplemental retirement plans, of which $0.1 million is recognized in actuarial losses above and $0.4 million is recognized as a regulatory asset at Alagasco and reported in actuarial losses on settlement charges above. In the third quarter of 2013, the Company incurred a settlement charge of $64,000 for the payment of lump sums from the nonqualified supplemental retirement plans, of which $18,000 is recognized in actuarial losses above and $46,000 is recognized as a regulatory asset at Alagasco and reported in actuarial losses on settlement charges above.

Recently_Issued_Accounting_Sta

Recently Issued Accounting Standards	9 Months Ended
	Sep. 30, 2013
New Accounting Pronouncements and Changes in Accounting Principles [Abstract]	'
Recently Issued Accounting Standards	'
	RECENTLY ISSUED ACCOUNTING STANDARDS
	In December 2011, the FASB issued Accounting Standard Update (ASU) No. 2011-11, Disclosures about Offsetting Assets and Liabilities. The amendments in this update require an entity to disclose information about offsetting and related arrangements to enable users of its financial statements to understand the effect of those arrangements on its financial position. The amendment is effective for annual reporting periods beginning on or after January 1, 2013, and interim periods within those annual periods. In January 2013, the FASB issued ASU No. 2013-01, Clarifying the Scope of Disclosures about Offsetting Assets and Liabilities. The effective date and transition of the disclosure requirement in ASU No. 2011-11 remained unchanged. The adoption of this standard did not have a material impact on the consolidated financial statements of the Company. The additional disclosures are included in Note 3, Derivative Commodity Instruments.
	In February 2013, the FASB issued ASU No. 2013-02, Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income. This update requires companies to include reclassification adjustments for items that are reclassified from other comprehensive income to net income in a single note or on the face of the financial statements. The amendment was effective for annual and interim reporting periods beginning after December 15, 2012. The adoption of this standard did not have a material impact on the consolidated financial statements of the Company. The additional disclosures are included in Note 13, Accumulated Other Comprehensive Income (Loss).

Discontinued_Operations

Discontinued Operations	9 Months Ended
	Sep. 30, 2013
Discontinued Operations and Disposal Groups [Abstract]	'
Discontinued Operations	'
	DISCONTINUED OPERATIONS
	In October 2013, Energen Resources completed the sale of its Black Warrior Basin coalbed methane properties in Alabama for $160 million (subject to closing adjustments). The Company will record a pre-tax gain on the sale of approximately $35 million in the fourth quarter of 2013. The sale had an effective date of July 1, 2013 and the proceeds from the sale were used to repay short-term obligations. The property was classified as held-for sale and reflected in discontinued operations during the third quarter of 2013. At December 31, 2012, proved reserves associated with Energen’s Black Warrior Basin properties totaled 97 Bcf of natural gas.
	During the third quarter of 2013, Energen Resources classified its North Louisiana/East Texas natural gas and oil properties as held-for-sale and reflected the associated operating results in discontinued operations and began marketing these assets. Energen Resources recognized a non-cash impairment writedown on these properties in the third quarter of 2013 of $24.6 million pre-tax to adjust the carrying amount of these properties to their fair value based on expected future discounted cash flows. This non-cash impairment writedown is reflected in loss on disposal of discontinued operations in the three months and nine months ended September 30, 2013. Significant assumptions in valuing the proved reserves included the reserve quantities, anticipated operating costs, anticipated production taxes, future expected natural gas prices and basis differentials, anticipated production declines, and a discount rate of 10 percent commensurate with the risk of the underlying cash flow estimates. This nonrecurring impairment writedown is classified as Level 3 fair value. The Company anticipates the sale being completed within the next twelve months and using the proceeds from the sale to repay short-term obligations. At December 31, 2012, proved reserves associated with Energen’s North Louisiana/East Texas properties totaled 20 Bcf of natural gas and 51 MBbl of oil.
	The following table details held-for-sale properties by major classes of assets and liabilities:
	(in thousands)	30-Sep-13
		Black Warrior Basin			North Louisiana/East Texas			Total
	Accounts receivable	$	3,704		$	1,418		$	5,122
	Inventories	1,078			63			1,141
	Oil and gas properties	304,012			348,380			652,392
	Less accumulated depreciation, depletion and amortization	(183,011		)	(293,935		)	(476,946		)
	Other property, net	1,970			183			2,153
	Total assets held-for-sale	127,753			56,109			183,862
	Accounts payable	(1,713		)	(2		)	(1,715		)
	Royalty payable	(792		)	(936		)	(1,728		)
	Other current liabilities	(358		)	(35		)	(393		)
	Other long-term liabilities	(5,377		)	(14,732		)	(20,109		)
	Total liabilities held-for-sale	(8,240		)	(15,705		)	(23,945		)
	Total held-for-sale properties	$	119,513		$	40,404		$	159,917
	During the first quarter of 2012, Energen Resources recognized a non-cash impairment writedown on certain properties in East Texas of $21.5 million pre-tax to adjust the carrying amount of these properties to their fair value based on expected future discounted cash flows. This non-cash impairment writedown is reflected in loss from discontinued operations in the nine months ended September 30, 2012. The impairment was caused by the impact of lower future natural gas prices. This nonrecurring impairment writedown is classified as Level 3 fair value.
	Gains and losses on the sale of certain oil and gas properties and any impairments of properties held-for-sale are reported as discontinued operations, with income or loss from operations of the associated properties reported as income or loss from discontinued operations. Accordingly, the results of operations for certain held-for-sale properties were reclassified and reported as discontinued operations for all prior periods presented. Energen Resources may, in the ordinary course of business, be involved in the sale of developed or undeveloped properties. All assets held-for-sale are reported at the lower of the carrying amount or fair value.
		Three months ended						Nine months ended
		September 30,						September 30,
	(in thousands, except per share data)	2013			2012			2013			2012
	Oil and gas revenues	$	18,258		$	18,895		$	55,483		$	57,601
	Pretax income (loss) from discontinued operations	$	2,971		$	5,526		$	9,980		$	(6,028	)
	Income tax expense (benefit)	1,105			1,975			3,711			(2,044		)
	Income (Loss) From Discontinued Operations	$	1,866		$	3,551		$	6,269		$	(3,984	)
	Loss on disposal of discontinued operations	$	(24,612	)	$	—		$	(24,612	)	$	—
	Income tax benefit	(8,934		)	—			(8,934		)	—
	Loss on Disposal of Discontinued Operations	$	(15,678	)	$	—		$	(15,678	)	$	—
	Total Income (Loss) From Discontinued Operations	$	(13,812	)	$	3,551		$	(9,409	)	$	(3,984	)
	Diluted Earnings Per Average Common Share
	Income (Loss) from Discontinued Operations	$	0.03		$	0.05		$	0.09		$	(0.05	)
	Loss on Disposal of Discontinued Operations	(0.22		)	—			(0.22		)	—
	Total Income (Loss) From Discontinued Operations	$	(0.19	)	$	0.05		$	(0.13	)	$	(0.05	)
	Basic Earnings Per Average Common Share
	Income (Loss) from Discontinued Operations	$	0.03		$	0.05		$	0.09		$	(0.06	)
	Loss on Disposal of Discontinued Operations	(0.22		)	—			(0.22		)	—
	Total Income (Loss) From Discontinued Operations	$	(0.19	)	$	0.05		$	(0.13	)	$	(0.06	)

Basis_of_Presentation_Policies

Basis of Presentation (Policies)	9 Months Ended
	Sep. 30, 2013
Organization, Consolidation and Presentation of Financial Statements [Abstract]	'
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, 2012, 2011 and 2010, included in the 2012 Annual Report of Energen Corporation (the Company) and Alabama Gas Corporation (Alagasco) on Form 10-K. Alagasco has a September 30 fiscal year for rate-setting purposes (rate year) and reports on a calendar year for the Securities and Exchange Commission and all other financial accounting reporting purposes. The accompanying unaudited condensed financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America for interim financial information and with the instructions to Form 10-Q and Rule 10-01 of Regulation S-X. Accordingly, they do not include all of the disclosures required for complete financial statements. The Company’s natural gas distribution business is seasonal in character and influenced by weather conditions. Results of operations for interim periods are not necessarily indicative of the results that may be expected for the year. All adjustments to the unaudited condensed financial statements that are, in the opinion of management, necessary for a fair statement of the results for the interim periods have been recorded. Such adjustments consist of normal recurring items.
Derivatives	'
	Energen Resources Corporation, Energen’s oil and gas subsidiary, periodically enters into derivative commodity instruments to hedge its exposure to price fluctuations on oil, natural gas and natural gas liquids production. In prior years, Alagasco entered into cash flow derivative commodity instruments to hedge its exposure to price fluctuations on its gas supply. Such instruments may include over-the-counter (OTC) swaps and basis hedges typically with investment and commercial banks and energy-trading firms. Hedge transactions are pursuant to standing authorizations by the Board of Directors, which do not authorize speculative positions. The Company recognizes all derivatives on the balance sheet and measures all derivatives at fair value. All derivative transactions are included in operating activities on the consolidated condensed statements of cash flows.
	The Company is at risk for economic loss based upon the creditworthiness of its counterparties. Energen Resources was in a net gain position with seven of its active counterparties and in a net loss position with the remaining six at September 30, 2013. The largest counterparty net loss position at September 30, 2013, Morgan Stanley Capital Group, constituted approximately $19.8 million of Energen Resources’ total net loss on fair value of derivatives. At September 30, 2013, Energen Resources was in a net gain position with Macquarie Bank Limited for approximately $10.0 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 September 30, 2013, 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.
	Prior to June 30, 2013, the Company utilized cash flow hedge accounting where applicable for its derivative transactions. 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 other derivative transactions not previously qualified for cash flow hedge accounting are still considered by management to represent valid economic hedges and are accounted for as mark-to-market transactions. These derivatives are recorded at fair value with gains or losses recognized in operating revenues in the period of change.
	Effective March 31, 2013 and June 30, 2013, Energen Resources dedesignated 5,078 thousand barrels (MBbl) and 2,353 MBbl, respectively, of various Permian Basin New York Mercantile Exchange (NYMEX) oil contracts due to lack of correlation. Any gains or losses from inception of the hedge to the dedesignation date were frozen and will remain in accumulated other comprehensive income until the forecasted transactions actually occur.  Any subsequent gains or losses will be accounted for as mark-to-market and recognized immediately through operating revenues.
	Effective June 30, 2013, the Company elected to discontinue the use of cash flow hedge accounting and to dedesignate all remaining derivative commodity instruments that were previously designated as cash flow hedges. As a result of discontinuing hedge accounting, any gains or losses from inception of the hedge to June 30, 2013 were frozen and will remain in accumulated other comprehensive income until the forecasted transactions actually occur. Any subsequent gains or losses will be accounted for as mark-to-market and recognized immediately through operating revenues. As a result of the Company’s election to discontinue hedge accounting, all derivative transactions entered into subsequent to June 30, 2013 will be accounted for as mark-to-market transactions with gains or losses recognized in operating revenues in the period of change.
Recently Issued Accounting Standards	'
	In December 2011, the FASB issued Accounting Standard Update (ASU) No. 2011-11, Disclosures about Offsetting Assets and Liabilities. The amendments in this update require an entity to disclose information about offsetting and related arrangements to enable users of its financial statements to understand the effect of those arrangements on its financial position. The amendment is effective for annual reporting periods beginning on or after January 1, 2013, and interim periods within those annual periods. In January 2013, the FASB issued ASU No. 2013-01, Clarifying the Scope of Disclosures about Offsetting Assets and Liabilities. The effective date and transition of the disclosure requirement in ASU No. 2011-11 remained unchanged. The adoption of this standard did not have a material impact on the consolidated financial statements of the Company. The additional disclosures are included in Note 3, Derivative Commodity Instruments.
	In February 2013, the FASB issued ASU No. 2013-02, Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income. This update requires companies to include reclassification adjustments for items that are reclassified from other comprehensive income to net income in a single note or on the face of the financial statements. The amendment was effective for annual and interim reporting periods beginning after December 15, 2012. The adoption of this standard did not have a material impact on the consolidated financial statements of the Company. The additional disclosures are included in Note 13, Accumulated Other Comprehensive Income (Loss).

Derivative_Commodity_Instrumen1

Derivative Commodity Instruments (Tables)	9 Months Ended
	Sep. 30, 2013
Derivative Instruments and Hedging Activities Disclosure [Abstract]	'
Schedule of Fair Values of Commodity Contracts by business Segment on Balance Sheet	'
	The following tables detail the fair values of commodity contracts by business segment on the balance sheets:
	(in thousands)	September 30, 2013
		Oil and Gas Operations				Natural Gas Distribution			Total
	Derivative assets or (liabilities) not designated as hedging instruments
	Accounts receivable	$	53,082			$	—		$	53,082
	Long-term asset derivative instruments	18,346				—			18,346
	Total derivative assets	71,428				—			71,428
	Accounts receivable	(40,789		)	*	—			(40,789		)
	Long-term asset derivative instruments	(5,560		)	*	—			(5,560		)
	Accounts payable	(31,928		)		—			(31,928		)
	Long-term liability derivative instruments	(1,379		)		—			(1,379		)
	Total derivative liabilities	(79,656		)		—			(79,656		)
	Total derivatives not designated	$	(8,228	)		$	—		$	(8,228	)
	(in thousands)	December 31, 2012
		Oil and Gas Operations				Natural Gas Distribution			Total
	Derivative assets or (liabilities) designated as hedging instruments
	Accounts receivable	$	87,514			$	—		$	87,514
	Long-term asset derivative instruments	37,954				—			37,954
	Total derivative assets	125,468				—			125,468
	Accounts receivable	(37,326		)	*	—			(37,326		)
	Long-term asset derivative instruments	(6,810		)	*	—			(6,810		)
	Long-term liability derivative instruments	(8,726		)		—			(8,726		)
	Total derivative liabilities	(52,862		)		—			(52,862		)
	Total derivatives designated	72,606				—			72,606
	Derivative assets or (liabilities) not designated as hedging instruments
	Accounts receivable	14,604				—			14,604
	Long-term asset derivative instruments	9,433				—			9,433
	Total derivative assets	24,037				—			24,037
	Accounts payable	—				(2,593		)	(2,593		)
	Long-term liability derivative instruments	(874		)		—			(874		)
	Total derivative liabilities	(874		)		(2,593		)	(3,467		)
	Total derivatives not designated	23,163				(2,593		)	20,570
	Total derivatives	$	95,769			$	(2,593	)	$	93,176
	* 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 Statement of Income	Three months			Three months
			ended			ended
			30-Sep-13			30-Sep-12
	Gain (loss) recognized in OCI on derivatives (effective portion), net of tax of $42 and ($30,622)	—	$	69		$	(49,962	)
	Gain reclassified from accumulated OCI into income (effective portion)	Operating revenues	$	8,455		$	15,998
	Loss recognized in income on derivatives (ineffective portion and amount excluded from effectiveness testing)	Operating revenues	$	(22	)	$	(3,042	)
	(in thousands)	Location on Statement of Income	Nine months			Nine months
			ended			ended
			30-Sep-13			30-Sep-12
	Gain (loss) recognized in OCI on derivatives (effective portion), net of tax of ($6,669) and $30,621	—	$	(10,882	)	$	49,961
	Gain reclassified from accumulated OCI into income (effective portion)	Operating revenues	$	29,391		$	39,012
	Gain (loss) recognized in income on derivatives (ineffective portion and amount excluded from effectiveness testing)	Operating revenues	$	835		$	(1,372	)
Schedule of Derivatives Not Designated as Hedging Instruments on Income Statements	'
	The following table details the effect of open and closed derivative commodity instruments not designated as hedging instruments on the income statement:
	(in thousands)	Location on Statement of Income	Three months			Three months
			ended			ended
			30-Sep-13			30-Sep-12
	Loss recognized in income on derivatives	Operating revenues	$	(92,313	)	$	(45,618	)
	(in thousands)	Location on Statement of Income	Nine months			Nine months
			ended			ended
			30-Sep-13			30-Sep-12
	Gain (loss) recognized in income on derivatives	Operating revenues	$	(70,735	)	$	33,825
Schedule of Hedging Transactions	'
	Energen Resources entered into the following transactions for the remainder of 2013 and subsequent years:
	Production Period	Total Hedged Volumes		Average Contract	Description
				Price
	Natural Gas
	2013	3	Bcf	$4.82 Mcf	NYMEX Swaps
		8.9	Bcf	$4.51 Mcf	Basin Specific Swaps - San Juan
		1.6	Bcf	$3.64 Mcf	Basin Specific Swaps - Permian
	2014	10.6	Bcf	$4.55 Mcf	NYMEX Swaps
		31.4	Bcf	$4.60 Mcf	Basin Specific Swaps - San Juan
		9.7	Bcf	$3.81 Mcf	Basin Specific Swaps - Permian
	2015	6	Bcf	$4.07 Mcf	Basin Specific Swaps - San Juan
	Oil
	2013	2,434	MBbl	$91.44 Bbl	NYMEX Swaps
	2014	9,796	MBbl	$92.64 Bbl	NYMEX Swaps
	2015	5,760	MBbl	$88.85 Bbl	NYMEX Swaps
	Oil Basis Differential
	2013	907	MBbl	$(2.99) Bbl	WTS/WTI Basis Swaps*
		1,070	MBbl	$(1.00) Bbl	WTI/WTI Basis Swaps**
	Natural Gas Liquids
	2013	12	MMGal	$1.02 Gal	Liquids Swaps
	*WTS - West Texas Sour/Midland, WTI - West Texas Intermediate/Cushing
	**WTI - West Texas Intermediate/Midland, WTI - West Texas Intermediate/Cushing
Schedule of Fair Value, Assets and Liabilities Measured on Recurring Basis	'
	The following sets forth derivative assets and liabilities that were measured at fair value on a recurring basis:
		September 30, 2013
	(in thousands)	Level 2*			Level 3*			Total
	Current assets	$	(12,712	)	$	25,005		$	12,293
	Noncurrent assets	6,828			5,958			12,786
	Current liabilities	(40,970		)	9,042			(31,928		)
	Noncurrent liabilities	(2,580		)	1,201			(1,379		)
	Net derivative asset (liability)	$	(49,434	)	$	41,206		$	(8,228	)
		31-Dec-12
	(in thousands)	Level 2*			Level 3*			Total
	Current assets	$	(3,629	)	$	68,421		$	64,792
	Noncurrent assets	18,899			21,678			40,577
	Current liabilities	(2,593		)	—			(2,593		)
	Noncurrent liabilities	(8,520		)	(1,080		)	(9,600		)
	Net derivative asset	$	4,157		$	89,019		$	93,176
	* Amounts classified in accordance with accounting guidance which permits offsetting fair value amounts recognized for multiple derivative instruments executed with the same counterparty under a master netting arrangement.
Schedule of Changes in Fair Value of Derivative Instruments Classified as Level 3	'
	The tables below set forth a summary of changes in the fair value of the Company’s Level 3 derivative commodity instruments as follows:
		Three months ended			Three months ended
	(in thousands)	September 30, 2013			September 30, 2012
	Balance at beginning of period	$	51,131		$	103,456
	Realized gains	10,852			18,737
	Unrealized losses relating to instruments held at the reporting date*	(10,947		)	(46,983		)
	Settlements during period	(9,830		)	(17,929		)
	Balance at end of period	$	41,206		$	57,281
		Nine months ended			Nine months ended
	(in thousands)	September 30, 2013			September 30, 2012
	Balance at beginning of period	$	89,019		$	65,801
	Realized gains	41,952			51,858
	Unrealized losses relating to instruments held at the reporting date*	(48,835		)	(9,328		)
	Settlements during period	(40,930		)	(51,050		)
	Balance at end of period	$	41,206		$	57,281
Schedule of Fair Value Inputs, Derivatives, Quantitative Information	'
	The tables below set forth quantitative information about the Company’s Level 3 fair value measurements of derivative commodity instruments as follows:
	(in thousands)	Fair Value as of September 30, 2013			Valuation Technique*	Unobservable Input*	Range
	Natural Gas Basis - San Juan
	2013	$	9,499		Discounted Cash Flow	Forward Basis	($0.12 - $0.14) Mcf
	2014	$	27,678		Discounted Cash Flow	Forward Basis	($0.13 - $0.15) Mcf
	2015	$	1,201		Discounted Cash Flow	Forward Basis	($0.20) Mcf
	Natural Gas Basis - Permian
	2013	$	286		Discounted Cash Flow	Forward Basis	($0.14) Mcf
	2014	$	825		Discounted Cash Flow	Forward Basis	($0.13 - $0.15) Mcf
	Oil Basis - WTS/WTI
	2013	$	(1,897	)	Discounted Cash Flow	Forward Basis	($1.06) Bbl
	Oil Basis - WTI/WTI
	2013	$	(641	)	Discounted Cash Flow	Forward Basis	($0.41 - $0.50) Bbl
	Natural Gas Liquids
	2013	$	4,255		Discounted Cash Flow	Forward Price	$0.74 - $0.81 Gal
	*Discounted cash flow represents an income approach in calculating fair value including the referenced unobservable input and a discount reflecting credit quality of the counterparty.
Offsetting Assets and Liabilities	'
	The tables below set forth information about the offsetting of derivative assets and liabilities as follows:
		September 30, 2013
											Gross Amounts Not Offset in the Balance Sheets
	(in thousands)	Gross Amounts Recognized			Gross Amounts Offset in the Balance Sheets			Net Amount Presented in the Balance Sheets			Financial Instruments		Cash Collateral Received		Net Amount
	Derivative assets	$	71,428		$	(46,349	)	$	25,079		$	—	$	—	$	25,079
	Derivative liabilities	$	79,656		$	(46,349	)	$	33,307		$	—	$	—	$	33,307
		31-Dec-12
											Gross Amounts Not Offset in the Balance Sheets
	(in thousands)	Gross Amounts Recognized			Gross Amounts Offset in the Balance Sheets			Net Amount Presented in the Balance Sheets			Financial Instruments		Cash Collateral Received		Net Amount
	Derivative assets	$	149,504		$	(44,135	)	$	105,369		$	—	$	—	$	105,369
	Derivative liabilities	$	56,328		$	(44,135	)	$	12,193		$	—	$	—	$	12,193

Reconciliation_of_Earnings_Per1

Reconciliation of Earnings Per Share (EPS) Reconciliation of Earnings Per Share (EPS) (Tables)	9 Months Ended
	Sep. 30, 2013
Earnings Per Share [Abstract]	'
Schedule of Earnings Per Share Reconciliation	'
		Three months ended							Three months ended
	(in thousands, except per share amounts)	September 30, 2013							September 30, 2012
		Net				Per Share			Net			Per Share
		Loss			Shares	Amount			Income		Shares	Amount
	Basic EPS	$	(19,298	)	72,346	$	(0.27	)	$	2,046	72,130	$	0.03
	Effect of dilutive securities
	Stock options				—						183
	Non-vested restricted stock				—						3
	Diluted EPS	$	(19,298	)	72,346	$	(0.27	)	$	2,046	72,316	$	0.03
	In periods of loss, shares that otherwise would have been included in diluted average common shares outstanding are excluded. The Company had 242,560 of excluded shares for the three months ended September 30, 2013.
		Nine months ended							Nine months ended
	(in thousands, except per share amounts)	September 30, 2013							September 30, 2012
		Net				Per Share			Net			Per Share
		Income			Shares	Amount			Income		Shares	Amount
	Basic EPS	$	120,461		72,220	$	1.67		$	190,739	72,121	$	2.64
	Effect of dilutive securities
	Stock options				41						177
	Non-vested restricted stock				10						3
	Performance share awards				1						—
	Diluted EPS	$	120,461		72,272	$	1.67		$	190,739	72,301	$	2.64

Segment_Information_Tables

Segment Information (Tables)	9 Months Ended
	Sep. 30, 2013
Segment Reporting [Abstract]	'
Schedule of Segment Reporting Information, by Segment	'
		Three months ended						Nine months ended
		September 30,						September 30,
	(in thousands)	2013			2012			2013			2012
	Operating revenues from continuing operations
	Oil and gas operations	$	272,038		$	214,620		$	875,350		$	799,339
	Natural gas distribution	48,368			61,809			390,567			327,183
	Total	$	320,406		$	276,429		$	1,265,917		$	1,126,522
	Operating income (loss) from continuing operations
	Oil and gas operations	$	18,607		$	26,913		$	181,948		$	280,897
	Natural gas distribution	(22,544		)	(12,743		)	58,968			70,265
	Eliminations and corporate expenses	(115		)	(206		)	(345		)	(857		)
	Total	$	(4,052	)	$	13,964		$	240,571		$	350,305
	Other income (expense)
	Oil and gas operations	$	(13,209	)	$	(12,703	)	$	(38,686	)	$	(35,402	)
	Natural gas distribution	7,973			(3,274		)	1,477			(10,062		)
	Eliminations and other	175			186			405			390
	Total	$	(5,061	)	$	(15,791	)	$	(36,804	)	$	(45,074	)
	Income (loss) from continuing operations before income taxes	$	(9,113	)	$	(1,827	)	$	203,767		$	305,231
	(in thousands)	September 30, 2013			December 31, 2012
	Identifiable assets
	Oil and gas operations	$	5,444,672		$	4,975,170
	Natural gas distribution	1,127,487			1,177,134
	Eliminations and other	42,713			23,586
	Total	$	6,614,872		$	6,175,890

Employee_Benefit_Plans_Tables

Employee Benefit Plans (Tables)	9 Months Ended
	Sep. 30, 2013
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						Nine months ended
		September 30,						September 30,
	(in thousands)	2013			2012			2013			2012
	Components of net periodic benefit cost:
	Service cost	$	3,602		$	2,632		$	10,806		$	7,895
	Interest cost	2,725			2,700			8,161			8,101
	Expected long-term return on assets	(3,713		)	(3,563		)	(11,139		)	(10,689		)
	Actuarial loss	3,597			2,099			10,962			6,297
	Prior service cost amortization	123			129			367			388
	Settlement charge	17			—			161			—
	Net periodic expense	$	6,351		$	3,997		$	19,318		$	11,992
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						Nine months ended
		September 30,						September 30,
	(in thousands)	2013			2012			2013			2012
	Components of net periodic benefit cost:
	Service cost	$	444		$	463		$	1,333		$	1,390
	Interest cost	869			1,062			2,605			3,186
	Expected long-term return on assets	(1,242		)	(1,109		)	(3,727		)	(3,328		)
	Actuarial loss	—			9			—			27
	Transition amortization	324			479			973			1,438
	Net periodic expense	$	395		$	904		$	1,184		$	2,713

Financial_Instruments_Tables

Financial Instruments (Tables)	9 Months Ended
	Sep. 30, 2013
Fair Value Disclosures [Abstract]	'
Allowance for Credit Losses on Financing Receivables	'
	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, 2012	$	470
	Provision	191
	Allowance for credit losses as of September 30, 2013	$	661

Regulatory_Assets_and_Liabilit1

Regulatory Assets and Liabilities (Tables) (Alabama Gas Corporation)	9 Months Ended
	Sep. 30, 2013
Alabama Gas Corporation	'
Regulatory Assets and Liabilities [Line Items]	'
Schedule of Regulatory Assets and Liabilities	'
	The following table details regulatory assets and liabilities on the balance sheets:
	(in thousands)	September 30, 2013				31-Dec-12
		Current		Noncurrent		Current		Noncurrent
	Regulatory assets:
	Pension assets	$	263	$	69,249	$	170	$	90,708
	Accretion and depreciation for asset retirement obligation	—		17,579		—		16,536
	Risk management activities	—		—		2,593		—
	Rate recovery of asset removal costs, net	—		2,176		—		3,322
	Gas supply adjustment	10,925		—		42,726		—
	Other	25		—		26		—
	Total regulatory assets	$	11,213	$	89,004	$	45,515	$	110,566
	Regulatory liabilities:
	RSE adjustment	$	6,573	$	—	$	1,740	$	—
	Unbilled service margin	6,351		—		25,078		—
	Postretirement liabilities	—		13,951		—		1,237
	Refundable negative salvage	16,321		40,946		18,265		53,467
	Gain on sale of property	10,890		—		—		—
	Asset retirement obligation	—		25,772		—		24,930
	Other	33		745		33		770
	Total regulatory liabilities	$	40,168	$	81,414	$	45,116	$	80,404

Asset_Retirement_Obligations_T

Asset Retirement Obligations (Tables)	9 Months Ended
	Sep. 30, 2013
Asset Retirement Obligation Disclosure [Abstract]	'
Schedule of Change in Asset Retirement Obligation	'
	During the nine months ended September 30, 2013, 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 as of December 31, 2012	$	118,023
	Liabilities incurred	2,466
	Liabilities settled	(542		)
	Accretion expense (including discontinued operations of $944)	6,131
	Reclassification associated with held for sale properties*	(19,474		)
	Balance as of September 30, 2013	$	106,604

Accumulated_Other_Comprehensiv1

Accumulated Other Comprehensive Income (Loss) (Tables)	9 Months Ended
	Sep. 30, 2013
Equity [Abstract]	'
Schedule of Accumulated Other Comprehensive Income (Loss)	'
	The following table provides changes in the components of accumulated other comprehensive income (loss), net of the related income tax effects.
	(in thousands)	Cash Flow Hedges			Pension and Postretirement Plans			Total
	Balance as of December 31, 2012	$	44,196		$	(52,507	)	$	(8,311	)
	Other comprehensive income (loss) before reclassifications	(10,924		)	4,157			(6,767		)
	Amounts reclassified from accumulated other comprehensive income (loss)	(17,907		)	4,721			(13,186		)
	Change in accumulated other comprehensive income (loss)	(28,831		)	8,878			(19,953		)
	Balance as of September 30, 2013	$	15,365		$	(43,629	)	$	(28,264	)
Reclassification out of Accumulated Other Comprehensive Income	'
	The following table provides details of the reclassifications out of accumulated other comprehensive income (loss).
		Three months ended			Nine months ended
		30-Sep-13			September 30, 2013
	(in thousands)	Amounts Reclassified						Line Item Where Presented
	Gains and (losses) on cash flow hedges:
	Commodity contracts	$	8,433		$	30,226		Operating revenues
	Interest rate swap	(446		)	(1,282		)	Interest expense
	Total cash flow hedges	7,987			28,944
	Income tax expense	(3,048		)	(11,037		)
	Net of tax	4,939			17,907
	Pension and postretirement plans:
	Transition obligation	(74		)	(220		)	Operations and maintenance
	Prior service cost	(78		)	(235		)	Operations and maintenance
	Actuarial losses*	(2,036		)	(6,387		)	Operations and maintenance
	Actuarial losses on settlement charges*	(46		)	(421		)	Regulatory asset
	Total pension and postretirement plans	(2,234		)	(7,263		)
	Income tax expense	783			2,542
	Net of tax	(1,451		)	(4,721		)
	Total reclassifications for the period	$	3,488		$	13,186
	* In the first quarter of 2013, the Company incurred a settlement charge of $0.5 million for the payment of lump sums from the nonqualified supplemental retirement plans, of which $0.1 million is recognized in actuarial losses above and $0.4 million is recognized as a regulatory asset at Alagasco and reported in actuarial losses on settlement charges above.

Discontinued_Operations_Tables

Discontinued Operations (Tables)	9 Months Ended
	Sep. 30, 2013
Discontinued Operations and Disposal Groups [Abstract]	'
Schedule of Disposal Groups, Including Discontinued Operations, Income Statement, Balance Sheet and Additional Disclosures	'
	The following table details held-for-sale properties by major classes of assets and liabilities:
	(in thousands)	30-Sep-13
		Black Warrior Basin			North Louisiana/East Texas			Total
	Accounts receivable	$	3,704		$	1,418		$	5,122
	Inventories	1,078			63			1,141
	Oil and gas properties	304,012			348,380			652,392
	Less accumulated depreciation, depletion and amortization	(183,011		)	(293,935		)	(476,946		)
	Other property, net	1,970			183			2,153
	Total assets held-for-sale	127,753			56,109			183,862
	Accounts payable	(1,713		)	(2		)	(1,715		)
	Royalty payable	(792		)	(936		)	(1,728		)
	Other current liabilities	(358		)	(35		)	(393		)
	Other long-term liabilities	(5,377		)	(14,732		)	(20,109		)
	Total liabilities held-for-sale	(8,240		)	(15,705		)	(23,945		)
	Total held-for-sale properties	$	119,513		$	40,404		$	159,917
		Three months ended						Nine months ended
		September 30,						September 30,
	(in thousands, except per share data)	2013			2012			2013			2012
	Oil and gas revenues	$	18,258		$	18,895		$	55,483		$	57,601
	Pretax income (loss) from discontinued operations	$	2,971		$	5,526		$	9,980		$	(6,028	)
	Income tax expense (benefit)	1,105			1,975			3,711			(2,044		)
	Income (Loss) From Discontinued Operations	$	1,866		$	3,551		$	6,269		$	(3,984	)
	Loss on disposal of discontinued operations	$	(24,612	)	$	—		$	(24,612	)	$	—
	Income tax benefit	(8,934		)	—			(8,934		)	—
	Loss on Disposal of Discontinued Operations	$	(15,678	)	$	—		$	(15,678	)	$	—
	Total Income (Loss) From Discontinued Operations	$	(13,812	)	$	3,551		$	(9,409	)	$	(3,984	)
	Diluted Earnings Per Average Common Share
	Income (Loss) from Discontinued Operations	$	0.03		$	0.05		$	0.09		$	(0.05	)
	Loss on Disposal of Discontinued Operations	(0.22		)	—			(0.22		)	—
	Total Income (Loss) From Discontinued Operations	$	(0.19	)	$	0.05		$	(0.13	)	$	(0.05	)
	Basic Earnings Per Average Common Share
	Income (Loss) from Discontinued Operations	$	0.03		$	0.05		$	0.09		$	(0.06	)
	Loss on Disposal of Discontinued Operations	(0.22		)	—			(0.22		)	—
	Total Income (Loss) From Discontinued Operations	$	(0.19	)	$	0.05		$	(0.13	)	$	(0.06	)

Basis_of_Presentation_Details

Basis of Presentation (Details) (USD $)	9 Months Ended
In Millions, unless otherwise specified	Sep. 30, 2013
Schedule of Quantifying Prior Year Misstatement Not Corrected Due to Materiality [Line Items]	'
Increase (decrease) in operating cash flow due to uncorrected error due to materiality	$1.90
Alabama Gas Corporation	'
Schedule of Quantifying Prior Year Misstatement Not Corrected Due to Materiality [Line Items]	'
Increase (decrease) in operating cash flow due to uncorrected error due to materiality	($0.80)

Regulatory_Matters_Details

Regulatory Matters (Details) (Alabama Gas Corporation, USD $)

0 Months Ended

1 Months Ended

3 Months Ended

9 Months Ended

3 Months Ended

0 Months Ended

Dec. 01, 2012

Dec. 01, 2011

Aug. 31, 2013

Sep. 30, 2013

Sep. 30, 2012

Sep. 30, 2013

Sep. 30, 2012

Sep. 30, 2013

Sep. 30, 2013

Sep. 30, 2013

Sep. 30, 2013

Sep. 30, 2013

Sep. 30, 2013

Nov. 05, 2013

Nov. 05, 2013

Nov. 05, 2013

Nov. 05, 2013

APSC Approved Expension of ESR, November 1, 2010

Force Majeure Event Costs

Force Majeure Events Costs

Environmental Response and Self Insurance Costs

Minimum

Maximum

Subsequent Event

Subsequent Event

Subsequent Event

Subsequent Event

APSC Approved Expension of ESR, November 1, 2010

APSC Approved Expension of ESR, November 1, 2010

APSC Approved Expension of ESR, November 1, 2010

APSC

APSC

APSC

Minimum

Maximum

Regulatory Matters [Line Items]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Approved return on equity

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

10.50%

10.95%

Adjusting point

'

'

'

'

'

'

'

'

'

'

'

'

'

'

10.80%

'

'

Performance based adjustment on adjusting point

'

'

'

'

'

'

'

'

'

'

'

'

'

0.05%

'

'

'

Equity upon which a return will be permitted

'

'

'

'

'

'

'

'

'

'

'

'

'

56.50%

'

'

'

Approved increase

'

'

'

'

'

'

'

'

'

'

'

'

'

1.75%

'

'

'

Allowed return on average common equity

'

'

'

'

'

'

'

'

'

'

'

13.15%

13.65%

'

'

'

'

Rate increases as percentage of prior year revenues

'

'

'

'

'

'

'

'

'

'

'

'

4.00%

'

'

'

'

Revenue reductions (increase) of rate adjustments

($7,800,000)

($13,000,000)

$10,900,000

$4,300,000

$1,300,000

$10,600,000

$6,300,000

'

'

'

'

'

'

'

'

'

'

Limitation on return on equity as percentage of total capitalization

'

'

'

'

'

'

'

'

'

'

'

'

55.00%

'

'

'

'

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.

'

'

'

'

'

'

'

'

'

'

'

Adjustment requirement threshold for return on equity as percentage of operations and maintenance expenses to Consumer Price Index

'

'

'

0.75

'

'

'

'

'

'

'

'

'

'

'

'

'

Extraordinary operating and maintenance expenses minimum amount charged to Enhanced Stability Reserve

'

'

'

'

'

'

'

'

275,000

412,500

1,000,000

'

'

'

'

'

'

Large commercial and industrial customer budget minimum amount charged to Enhanced Stability Reserve

'

'

'

'

'

'

'

350,000

'

'

'

'

'

'

'

'

'

Enhanced Stability Reserve refund period

'

'

'

'9 years

'

'

'

'

'

'

'

'

'

'

'

'

'

Enhanced Stability Reserve amortization period

'

'

'

'5 years

'

'

'

'

'

'

'

'

'

'

'

'

'

Enhanced Stability Reserve, amortization expense

'

'

'

'

'

$660,000

'

'

'

'

'

'

'

'

'

'

'

Derivative_Commodity_Instrumen2

Derivative Commodity Instruments - Commodity Contracts by Business Segment (Details) (USD $)	Sep. 30, 2013		Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2012
			bbl	bbl
Derivative [Line Items]	'		'	'	'
Derivative assets	$25,079,000		'	'	$105,369,000
Fair Value as of September 30, 2013	33,307,000		'	'	12,193,000
Barrels dedesignated	'		2,353,000	5,078,000	'
Gross Amounts Recognized	71,428,000		'	'	149,504,000
Derivative liability	-79,656,000		'	'	-56,328,000
Total derivatives	-8,228,000		'	'	93,176,000
Deferred tax assets (liabilities), net	-10,300,000		'	'	-28,400,000
Oil and gas operations	'		'	'	'
Derivative [Line Items]	'		'	'	'
Total derivatives	-8,228,000		'	'	95,769,000
Natural gas distribution	'		'	'	'
Derivative [Line Items]	'		'	'	'
Total derivatives	0		'	'	-2,593,000
Designated as Hedging Instrument	'		'	'	'
Derivative [Line Items]	'		'	'	'
Gross Amounts Recognized	'		'	'	125,468,000
Total derivative liabilities	'		'	'	-52,862,000
Total derivatives	'		'	'	72,606,000
Designated as Hedging Instrument | Oil and gas operations	'		'	'	'
Derivative [Line Items]	'		'	'	'
Gross Amounts Recognized	'		'	'	125,468,000
Total derivative liabilities	'		'	'	-52,862,000
Total derivatives	'		'	'	72,606,000
Designated as Hedging Instrument | Natural gas distribution	'		'	'	'
Derivative [Line Items]	'		'	'	'
Gross Amounts Recognized	'		'	'	0
Total derivative liabilities	'		'	'	0
Total derivatives	'		'	'	0
Not Designated as Hedging Instrument	'		'	'	'
Derivative [Line Items]	'		'	'	'
Gross Amounts Recognized	71,428,000		'	'	24,037,000
Derivative liability	-79,656,000		'	'	-3,467,000
Total derivatives	'		'	'	20,570,000
Not Designated as Hedging Instrument | Oil and gas operations	'		'	'	'
Derivative [Line Items]	'		'	'	'
Gross Amounts Recognized	71,428,000		'	'	24,037,000
Derivative liability	-79,656,000		'	'	-874,000
Total derivatives	'		'	'	23,163,000
Not Designated as Hedging Instrument | Natural gas distribution	'		'	'	'
Derivative [Line Items]	'		'	'	'
Gross Amounts Recognized	0		'	'	0
Derivative liability	0		'	'	-2,593,000
Total derivatives	'		'	'	-2,593,000
Accounts receivable | Designated as Hedging Instrument	'		'	'	'
Derivative [Line Items]	'		'	'	'
Gross Amounts Recognized	'		'	'	87,514,000
Derivative liability	'		'	'	-37,326,000
Accounts receivable | Designated as Hedging Instrument | Oil and gas operations	'		'	'	'
Derivative [Line Items]	'		'	'	'
Gross Amounts Recognized	'		'	'	87,514,000
Derivative liability	'		'	'	-37,326,000	[1]
Accounts receivable | Designated as Hedging Instrument | Natural gas distribution	'		'	'	'
Derivative [Line Items]	'		'	'	'
Gross Amounts Recognized	'		'	'	0
Derivative liability	'		'	'	0
Accounts receivable | Not Designated as Hedging Instrument	'		'	'	'
Derivative [Line Items]	'		'	'	'
Gross Amounts Recognized	53,082,000		'	'	14,604,000
Derivative liability	-40,789,000		'	'	'
Accounts receivable | Not Designated as Hedging Instrument | Oil and gas operations	'		'	'	'
Derivative [Line Items]	'		'	'	'
Gross Amounts Recognized	53,082,000	[1]	'	'	14,604,000	[1]
Derivative liability	-40,789,000	[1]	'	'	'
Accounts receivable | Not Designated as Hedging Instrument | Natural gas distribution	'		'	'	'
Derivative [Line Items]	'		'	'	'
Gross Amounts Recognized	0		'	'	0
Derivative liability	0		'	'	'
Long-term asset derivative instruments | Designated as Hedging Instrument	'		'	'	'
Derivative [Line Items]	'		'	'	'
Gross Amounts Recognized	'		'	'	37,954,000
Derivative liability	'		'	'	-6,810,000
Long-term asset derivative instruments | Designated as Hedging Instrument | Oil and gas operations	'		'	'	'
Derivative [Line Items]	'		'	'	'
Gross Amounts Recognized	'		'	'	37,954,000
Derivative liability	'		'	'	-6,810,000	[1]
Long-term asset derivative instruments | Designated as Hedging Instrument | Natural gas distribution	'		'	'	'
Derivative [Line Items]	'		'	'	'
Gross Amounts Recognized	'		'	'	0
Derivative liability	'		'	'	0
Long-term asset derivative instruments | Not Designated as Hedging Instrument	'		'	'	'
Derivative [Line Items]	'		'	'	'
Gross Amounts Recognized	18,346,000		'	'	9,433,000
Derivative liability	-5,560,000		'	'	'
Long-term asset derivative instruments | Not Designated as Hedging Instrument | Oil and gas operations	'		'	'	'
Derivative [Line Items]	'		'	'	'
Gross Amounts Recognized	18,346,000		'	'	9,433,000	[1]
Derivative liability	-5,560,000	[1]	'	'	'
Long-term asset derivative instruments | Not Designated as Hedging Instrument | Natural gas distribution	'		'	'	'
Derivative [Line Items]	'		'	'	'
Gross Amounts Recognized	0		'	'	0
Derivative liability	0		'	'	'
Accounts payable | Not Designated as Hedging Instrument	'		'	'	'
Derivative [Line Items]	'		'	'	'
Derivative liability	-31,928,000		'	'	-2,593,000
Accounts payable | Not Designated as Hedging Instrument | Oil and gas operations	'		'	'	'
Derivative [Line Items]	'		'	'	'
Derivative liability	-31,928,000		'	'	0
Accounts payable | Not Designated as Hedging Instrument | Natural gas distribution	'		'	'	'
Derivative [Line Items]	'		'	'	'
Derivative liability	0		'	'	-2,593,000
Long-term liability derivative instruments | Designated as Hedging Instrument	'		'	'	'
Derivative [Line Items]	'		'	'	'
Derivative liability	'		'	'	-8,726,000
Long-term liability derivative instruments | Designated as Hedging Instrument | Oil and gas operations	'		'	'	'
Derivative [Line Items]	'		'	'	'
Derivative liability	'		'	'	-8,726,000
Long-term liability derivative instruments | Designated as Hedging Instrument | Natural gas distribution	'		'	'	'
Derivative [Line Items]	'		'	'	'
Derivative liability	'		'	'	0
Long-term liability derivative instruments | Not Designated as Hedging Instrument	'		'	'	'
Derivative [Line Items]	'		'	'	'
Derivative liability	-1,379,000		'	'	-874,000
Long-term liability derivative instruments | Not Designated as Hedging Instrument | Oil and gas operations	'		'	'	'
Derivative [Line Items]	'		'	'	'
Derivative liability	-1,379,000		'	'	-874,000
Long-term liability derivative instruments | Not Designated as Hedging Instrument | Natural gas distribution	'		'	'	'
Derivative [Line Items]	'		'	'	'
Derivative liability	0		'	'	0
Cash Flow Hedging | Macquarie Bank Limited	'		'	'	'
Derivative [Line Items]	'		'	'	'
Derivative assets	10,000,000		'	'	'
Cash Flow Hedging | Morgan Stanley Capital Group, Inc.	'		'	'	'
Derivative [Line Items]	'		'	'	'
Fair Value as of September 30, 2013	$19,800,000		'	'	'
[1]	Amounts classified in accordance with accounting guidance which permits offsetting fair value amounts recognized for multiple derivative instruments executed with the same counterparty under a master netting arrangement.

Derivative_Commodity_Instrumen3

Derivative Commodity Instruments - Derivative Instruments by Income Statement Location (Details) (USD $)	3 Months Ended		9 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
Derivative Instruments, Gain (Loss) [Line Items]	'	'	'	'
Gain (loss) recognized in OCI on derivatives (effective portion), net of tax	$69,000	($49,962,000)	($10,882,000)	$49,961,000
Gain (loss) reclassification from AOCI to income estimated net amount to be transferred	13,100,000	'	'	'
Operating revenues	320,406,000	276,429,000	1,265,917,000	1,126,522,000
Reclassification out of Accumulated Other Comprehensive Income | Accumulated Net Gain from Discontinued Hedge Accounting	'	'	'	'
Derivative Instruments, Gain (Loss) [Line Items]	'	'	'	'
Operating revenues	'	'	6,700,000	'
Fair Value Hedging | Natural Gas | 2013	'	'	'	'
Derivative Instruments, Gain (Loss) [Line Items]	'	'	'	'
Nonmonetary notional amount	13,500,000	'	13,500,000	'
Fair Value Hedging | Natural Gas | 2014	'	'	'	'
Derivative Instruments, Gain (Loss) [Line Items]	'	'	'	'
Nonmonetary notional amount	51,800,000	'	51,800,000	'
Fair Value Hedging | Natural Gas | 2015	'	'	'	'
Derivative Instruments, Gain (Loss) [Line Items]	'	'	'	'
Nonmonetary notional amount	6,000,000	'	6,000,000	'
Fair Value Hedging | Crude Oil | 2013	'	'	'	'
Derivative Instruments, Gain (Loss) [Line Items]	'	'	'	'
Nonmonetary notional amount	4,400,000	'	4,400,000	'
Fair Value Hedging | Crude Oil | 2014	'	'	'	'
Derivative Instruments, Gain (Loss) [Line Items]	'	'	'	'
Nonmonetary notional amount	9,800,000	'	9,800,000	'
Fair Value Hedging | Crude Oil | 2015	'	'	'	'
Derivative Instruments, Gain (Loss) [Line Items]	'	'	'	'
Nonmonetary notional amount	5,800,000	'	5,800,000	'
Fair Value Hedging | Natural Gas Liquids | 2013	'	'	'	'
Derivative Instruments, Gain (Loss) [Line Items]	'	'	'	'
Nonmonetary notional amount	11,900,000	'	11,900,000	'
Fair Value Hedging | Natural Gas Liquids | 2014	'	'	'	'
Derivative Instruments, Gain (Loss) [Line Items]	'	'	'	'
Nonmonetary notional amount	0	'	0	'
Operating revenues	'	'	'	'
Derivative Instruments, Gain (Loss) [Line Items]	'	'	'	'
Gain reclassified from accumulated OCI into income (effective portion)	8,455,000	15,998,000	29,391,000	39,012,000
Loss recognized in income on derivatives (ineffective portion and amount excluded from effectiveness testing)	-22,000	-3,042,000	835,000	-1,372,000
Gain (loss) recognized in income on derivatives	-92,313,000	-45,618,000	-70,735,000	33,825,000
Commodity contracts	'	'	'	'
Derivative Instruments, Gain (Loss) [Line Items]	'	'	'	'
Current period change in fair value of interest rate swap, tax	$42,000	($30,622,000)	($6,669,000)	$30,621,000

Derivative_Commodity_Instrumen4

Derivative Commodity Instruments - Hedging Transactions (Details) (Cash Flow Hedging)	9 Months Ended
	Sep. 30, 2013
	Mcf
Natural Gas | 2013 | NYMEX Swaps	'
Derivative [Line Items]	'
Total Hedged Volumes	3,000,000
Average Contract Price, per Mcf	4.82
Natural Gas | 2013 | Basin Specific Swaps - San Juan	'
Derivative [Line Items]	'
Total Hedged Volumes	8,900,000
Average Contract Price, per Mcf	4.51
Natural Gas | 2013 | Basin Specific Swaps - Permian	'
Derivative [Line Items]	'
Total Hedged Volumes	1,600,000
Average Contract Price, per Mcf	3.64
Natural Gas | 2014 | NYMEX Swaps	'
Derivative [Line Items]	'
Total Hedged Volumes	10,600,000
Average Contract Price, per Mcf	4.55
Natural Gas | 2014 | Basin Specific Swaps - San Juan	'
Derivative [Line Items]	'
Total Hedged Volumes	31,400,000
Average Contract Price, per Mcf	4.6
Natural Gas | 2014 | Basin Specific Swaps - Permian	'
Derivative [Line Items]	'
Total Hedged Volumes	9,700,000
Average Contract Price, per Mcf	3.81
Natural Gas | 2015 | Basin Specific Swaps - San Juan	'
Derivative [Line Items]	'
Total Hedged Volumes	6,000,000
Average Contract Price, per Mcf	4.07
Crude Oil | 2013 | NYMEX Swaps	'
Derivative [Line Items]	'
Total Hedged Volumes	2,434,000
Average Contract Price, per Bbl	91.44
Crude Oil | 2013 | WTS/WTI Basis Swaps	'
Derivative [Line Items]	'
Total Hedged Volumes	907,000	[1]
Average Contract Price, per Bbl	-2.99	[1]
Crude Oil | 2013 | WTI/WTI Basis Swaps	'
Derivative [Line Items]	'
Total Hedged Volumes	1,070,000	[2]
Average Contract Price, per Bbl	-1	[2]
Crude Oil | 2014 | NYMEX Swaps	'
Derivative [Line Items]	'
Total Hedged Volumes	9,796,000
Average Contract Price, per Bbl	92.64
Crude Oil | 2015 | NYMEX Swaps	'
Derivative [Line Items]	'
Total Hedged Volumes	5,760,000
Average Contract Price, per Bbl	88.85
Natural Gas Liquids | 2013 | Liquids Swaps	'
Derivative [Line Items]	'
Total Hedged Volumes	12,000,000
Average Contract Price, per Bbl	1.02
[1]	WTS - West Texas Sour/Midland, WTI - West Texas Intermediate/Cushing
[2]	WTI - West Texas Intermediate/Midland, WTI - West Texas Intermediate/Cushing

Derivative_Commodity_Instrumen5

Derivative Commodity Instruments - Derivatives Measured at Fair Value on a Recurring Basis (Details) (USD $)

Sep. 30, 2013

Dec. 31, 2012

Sep. 30, 2013

Dec. 31, 2012

Sep. 30, 2013

Sep. 30, 2013

Dec. 31, 2012

Sep. 30, 2013

Dec. 31, 2012

Sep. 30, 2013

Dec. 31, 2012

Dec. 31, 2012

Level 2

Level 2

Level 3

Level 3

Level 3

Total

Total

Alabama Gas Corporation

Alabama Gas Corporation

Alabama Gas Corporation

Fair Value, Measurements, Recurring

Fair Value, Measurements, Recurring

Fair Value, Measurements, Recurring

Fair Value, Measurements, Recurring

Fair Value, Measurements, Recurring

Fair Value, Measurements, Recurring

Fair Value, Measurements, Recurring

Level 2

Level 3

Fair Value, Measurements, Recurring

Fair Value, Measurements, Recurring

Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]

'

'

'

'

'

'

'

'

'

'

'

'

Current assets

'

'

($12,712,000)

[1]

($3,629,000)

'

$25,005,000

[1]

$68,421,000

$12,293,000

$64,792,000

'

'

'

Noncurrent assets

12,786,000

40,577,000

6,828,000

[1]

18,899,000

'

5,958,000

[1]

21,678,000

12,786,000

40,577,000

'

'

'

Current liabilities

'

'

-40,970,000

[1]

-2,593,000

'

9,042,000

[1]

0

-31,928,000

-2,593,000

0

-2,600,000

0

Noncurrent liabilities

-1,961,000

-11,305,000

-2,580,000

-8,520,000

'

1,201,000

-1,080,000

-1,379,000

-9,600,000

'

'

'

Net derivative asset (liability)

'

'

-49,434,000

[1]

4,157,000

[1]

'

41,206,000

[1]

89,019,000

[1]

-8,228,000

93,176,000

'

'

'

Impact on fair value of a 10 percent increase or decrease in commodity prices

'

'

'

'

22,000,000

'

'

'

'

'

'

'

Impact on results of operations of a 10 percent increase or decrease in commodity prices

'

'

'

'

$22,000,000

'

'

'

'

'

'

'

[1]

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

Derivative_Commodity_Instrumen6

Derivative Commodity Instruments - Derivative Instruments Change in Fair Value (Details) (Derivative Commodity Instruments, USD $)	3 Months Ended				9 Months Ended
	Sep. 30, 2013		Sep. 30, 2012		Sep. 30, 2013	Sep. 30, 2012
Derivative Commodity Instruments	'		'		'	'
Fair Value, Assets and Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]	'		'		'	'
Balance at beginning of period	$51,131,000		$103,456,000		$89,019,000	$65,801,000
Realized gains	10,852,000		18,737,000		41,952,000	51,858,000
Unrealized losses relating to instruments held at the reporting date	-10,947,000	[1]	-46,983,000	[1]	-48,835,000	-9,328,000	[1]
Settlements during period	-9,830,000		-17,929,000		-40,930,000	-51,050,000
Balance at end of period	41,206,000		57,281,000		41,206,000	57,281,000
Mark-to-market gain included in earnings, unrealized	800,000		'		4,700,000	'
Mark-to-market loss included in earnings, unrealized	'		$7,900,000		'	$4,500,000
[1]	Includes $0.8 million and $4.7 million in mark-to-market gains for the three months and nine months ended September 30, 2013, respectively.

Derivative_Commodity_Instrumen7

Derivative Commodity Instruments - Quantitative Disclosures About Fair Value (Details) (USD $)

Sep. 30, 2013

Dec. 31, 2012

Sep. 30, 2013

Sep. 30, 2013

Sep. 30, 2013

Sep. 30, 2013

Sep. 30, 2013

Sep. 30, 2013

Sep. 30, 2013

Sep. 30, 2013

Sep. 30, 2013

Sep. 30, 2013

Sep. 30, 2013

Sep. 30, 2013

Sep. 30, 2013

Sep. 30, 2013

Sep. 30, 2013

Sep. 30, 2013

Sep. 30, 2013

Sep. 30, 2013

In Thousands, unless otherwise specified

Income Approach Valuation Technique

Income Approach Valuation Technique

Income Approach Valuation Technique

Income Approach Valuation Technique

Income Approach Valuation Technique

Income Approach Valuation Technique

Income Approach Valuation Technique

Income Approach Valuation Technique

Income Approach Valuation Technique

Income Approach Valuation Technique

Income Approach Valuation Technique

Income Approach Valuation Technique

Income Approach Valuation Technique

Income Approach Valuation Technique

Income Approach Valuation Technique

Income Approach Valuation Technique

Income Approach Valuation Technique

Income Approach Valuation Technique

Level 3

Level 3

Level 3

Level 3

Level 3

Level 3

Level 3

Level 3

Level 3

Level 3

Level 3

Level 3

Level 3

Level 3

Level 3

Level 3

Level 3

Level 3

Natural Gas Basis - San Juan

Natural Gas Basis - San Juan

Natural Gas Basis - San Juan

Natural Gas Basis - San Juan

Natural Gas Basis - San Juan

Natural Gas Basis - San Juan

Natural Gas Basis - San Juan

Natural Gas Basis - Permian

Natural Gas Basis - Permian

Natural Gas Basis - Permian

Natural Gas Basis - Permian

Oil Basis - WTS/WTI

Oil Basis - WTI/WTI

Oil Basis - WTI/WTI

Oil Basis - WTI/WTI

Natural Gas Liquids

Natural Gas Liquids

Natural Gas Liquids

2013

2013

2013

2014

2014

2014

2015

2013

2014

2014

2014

2013

2013

2013

2013

2013

2013

2013

Minimum

Maximum

Minimum

Maximum

Minimum

Maximum

Minimum

Maximum

Minimum

Maximum

Fair Value Inputs, Derivatives, Quantitative Information [Line Items]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Fair Value as of September 30, 2013

$25,079

$105,369

$9,499

'

'

$27,678

'

'

$1,201

$286

$825

'

'

'

'

'

'

$4,255

'

'

Fair Value as of September 30, 2013

$33,307

$12,193

'

'

'

'

'

'

'

'

'

'

'

($1,897)

($641)

'

'

'

'

'

Fair Value Inputs, Price Per Cubic Foot

'

'

'

0.12

0.14

'

0.13

0.15

0.2

0.14

'

0.13

0.15

'

'

'

'

'

'

'

Fair Value Inputs, Price Per Barrel

'

'

'

'

'

'

'

'

'

'

'

'

'

1.06

'

0.41

0.5

'

'

'

Fair Value Inputs, Price Per Gallon

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

0.74

0.81

Derivative_Commodity_Instrumen8

Derivative Commodity Instruments - Offsetting Assets and Liabilities (Details) (USD $)	Sep. 30, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified
Derivative assets	'	'
Gross Amounts Recognized	$71,428	$149,504
Gross Amounts Offset in the Balance Sheets	-46,349	-44,135
Net Amount Presented in the Balance Sheets	25,079	105,369
Financial Instruments	0	0
Cash Collateral Received	0	0
Net Amount	25,079	105,369
Derivative assets	'	'
Gross Amounts Recognized	79,656	56,328
Gross Amounts Offset in the Balance Sheets	-46,349	-44,135
Net Amount Presented in the Balance Sheets	33,307	12,193
Financial Instruments	0	0
Cash Collateral Received	0	0
Net Amount	$33,307	$12,193

Reconciliation_of_Earnings_Per2

Reconciliation of Earnings Per Share (EPS) - Earnings Per Share Reconciliation (Details) (USD $)	3 Months Ended		9 Months Ended
In Thousands, except Per Share data, unless otherwise specified	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
Earnings Per Share Reconciliation	'	'	'	'
Net Income, Basic EPS	($19,298)	$2,046	$120,461	$190,739
Basic Shares Outstanding (in shares)	72,346	72,130	72,220	72,121
Earnings Per Share, Basic (in dollars per share)	($0.27)	$0.03	$1.67	$2.64
Effect of dilutive securities	'	'	'	'
Net Income, Diluted EPS	($19,298)	$2,046	$120,461	$190,739
Diluted Shares Outstanding (in shares)	72,346	72,316	72,272	72,301
Earnings Per Share, Diluted (dollars per share)	($0.27)	$0.03	$1.67	$2.64
Stock options	'	'	'	'
Effect of dilutive securities	'	'	'	'
Incremental common shares attributable to share-based payment arrangements	0	183	41	177
Non-vested restricted stock	'	'	'	'
Effect of dilutive securities	'	'	'	'
Incremental common shares attributable to share-based payment arrangements	0	3	10	3
Performance share awards	'	'	'	'
Effect of dilutive securities	'	'	'	'
Incremental common shares attributable to share-based payment arrangements	'	'	1	0

Reconciliation_of_Earnings_Per3

Reconciliation of Earnings Per Share (EPS) - Antidilutive Securities (Details)	3 Months Ended		9 Months Ended
In Thousands, unless otherwise specified	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
Stock options	'	'	'	'
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]	'	'	'	'
Antidilutive securities excluded from computation of earnings per share, amount	0	850	875	850
Non-vested restricted stock	'	'	'	'
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]	'	'	'	'
Antidilutive securities excluded from computation of earnings per share, amount	0	'	'	'
Performance share awards	'	'	'	'
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]	'	'	'	'
Antidilutive securities excluded from computation of earnings per share, amount	'	0	79	0

Segment_Information_Details

Segment Information (Details) (USD $)	3 Months Ended		9 Months Ended
In Thousands, unless otherwise specified	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012	Dec. 31, 2012
	segment
Segment Reporting Information	'	'	'	'	'
Number of business segments	2	'	'	'	'
Segment Reporting Information, Profit (Loss)	'	'	'	'	'
Operating revenues from continuing operations	$320,406	$276,429	$1,265,917	$1,126,522	'
Operating income (loss) from continuing operations	-4,052	13,964	240,571	350,305	'
Other income (expense)	-5,061	-15,791	-36,804	-45,074	'
Income (Loss) From Continuing Operations Before Income Taxes	-9,113	-1,827	203,767	305,231	'
Identifiable assets	6,614,872	'	6,614,872	'	6,175,890
Oil and gas operations	'	'	'	'	'
Segment Reporting Information, Profit (Loss)	'	'	'	'	'
Operating revenues from continuing operations	272,038	214,620	875,350	799,339	'
Operating income (loss) from continuing operations	18,607	26,913	181,948	280,897	'
Other income (expense)	-13,209	-12,703	-38,686	-35,402	'
Identifiable assets	5,444,672	'	5,444,672	'	4,975,170
Natural gas distribution	'	'	'	'	'
Segment Reporting Information, Profit (Loss)	'	'	'	'	'
Operating revenues from continuing operations	48,368	61,809	390,567	327,183	'
Operating income (loss) from continuing operations	-22,544	-12,743	58,968	70,265	'
Other income (expense)	7,973	-3,274	1,477	-10,062	'
Identifiable assets	1,127,487	'	1,127,487	'	1,177,134
Eliminations and corporate expenses	'	'	'	'	'
Segment Reporting Information, Profit (Loss)	'	'	'	'	'
Operating income (loss) from continuing operations	-115	-206	-345	-857	'
Other income (expense)	175	186	405	390	'
Identifiable assets	$42,713	'	$42,713	'	$23,586

Stock_Compensation_Details

Stock Compensation (Details) (USD $)

3 Months Ended

9 Months Ended

1 Months Ended

3 Months Ended

9 Months Ended

3 Months Ended

9 Months Ended

3 Months Ended

9 Months Ended

3 Months Ended

9 Months Ended

In Millions, except Share data, unless otherwise specified

Sep. 30, 2013

Sep. 30, 2013

Jan. 31, 2013

Sep. 30, 2013

Sep. 30, 2013

Sep. 30, 2013

Sep. 30, 2013

Sep. 30, 2013

Mar. 31, 2013

Sep. 30, 2013

Sep. 30, 2013

Sep. 30, 2013

Sep. 30, 2013

Sep. 30, 2013

Sep. 30, 2013

Sep. 30, 2013

Stock options

Stock options

Restricted Stock

Restricted Stock

Performance share awards

Performance share awards

Performance share awards

Stock Appreciation Rights (SARs)

Restricted Stock Units (RSUs)

Restricted Stock Units (RSUs)

Restricted Stock Units (RSUs)

Restricted Stock Units (RSUs)

Restricted Stock Units (RSUs)

Restricted Stock Units (RSUs)

Deferred Compensation

Deferred Compensation

2 year vesting period

3 year vesting period

Petrotech Incentive Plan

Petrotech Incentive Plan

Petrotech Incentive Plan

Petrotech Incentive Plan

Petrotech Incentive Plan

Petrotech Incentive Plan

Petrotech Incentive Plan

3 year vesting period

3 year vesting period

3 year vesting period

17 month vesting period

17 month vesting period

Share-based Compensation Arrangement by Share-based Payment Award

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Vesting period

'

'3 years

'

'3 years

'2 years

'3 years

'3 years

'3 years

'

'

'

'3 years

'

'17 months

'

'

Expiration period

'10 years

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Grants in period, options

'

134,076

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Grants in period, options, fair value

'

$16.66

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Grants in period (in shares)

'

'

46,121

'

84,311

80,395

52,768

88,000

33,796

'

5,854

'

2,952

'

'

'

Grants in period, fair value (in dollars per share)

'

'

$48.36

'

$59.19

$60.81

$133.58

$39.10

'

$75.67

'

'

'

$75.88

'

'

Noncash payments for repurchase of common stock

'

'

'

'

'

'

'

'

'

'

'

'

'

'

$0.80

$0.90

Employee_Benefit_Plans_Details

Employee Benefit Plans (Details) (USD $)

3 Months Ended

1 Months Ended

3 Months Ended

9 Months Ended

3 Months Ended

9 Months Ended

3 Months Ended

Sep. 30, 2013

Mar. 31, 2013

Jan. 31, 2013

Sep. 30, 2013

Sep. 30, 2012

Sep. 30, 2013

Sep. 30, 2012

Sep. 30, 2013

Sep. 30, 2012

Sep. 30, 2013

Sep. 30, 2012

Sep. 30, 2013

pension_plan

Pension Plans

Pension Plans

Pension Plans

Pension Plans

Pension Plans

Postretirement Benefit Plans

Postretirement Benefit Plans

Postretirement Benefit Plans

Postretirement Benefit Plans

Alabama Gas Corporation

Defined Benefit Plan Disclosure

'

'

'

'

'

'

'

'

'

'

'

'

Number of defined benefit non-contributory pension plans and certain nonqualified supplemental pension plans

2

'

'

'

'

'

'

'

'

'

'

'

Components of net periodic benefit cost:

'

'

'

'

'

'

'

'

'

'

'

'

Service cost

'

'

'

$3,602,000

$2,632,000

$10,806,000

$7,895,000

$444,000

$463,000

$1,333,000

$1,390,000

'

Interest cost

'

'

'

2,725,000

2,700,000

8,161,000

8,101,000

869,000

1,062,000

2,605,000

3,186,000

'

Expected long-term return on assets

'

'

'

-3,713,000

-3,563,000

-11,139,000

-10,689,000

-1,242,000

-1,109,000

-3,727,000

-3,328,000

'

Actuarial loss

'

'

'

3,597,000

2,099,000

10,962,000

6,297,000

0

9,000

0

27,000

'

Prior service cost amortization

'

'

'

123,000

129,000

367,000

388,000

'

'

'

'

'

Settlement charge

'

'

'

17,000

0

161,000

0

'

'

'

'

'

Transition amortization

'

'

'

'

'

'

'

324,000

479,000

973,000

1,438,000

'

Net periodic expense

'

'

'

6,351,000

3,997,000

19,318,000

11,992,000

395,000

904,000

1,184,000

2,713,000

'

Estimated required future employer contributions in current fiscal year

'

'

'

0

'

0

'

'

'

'

'

'

Contributions by employer in current fiscal year

'

'

9,000,000

'

'

'

'

400,000

'

1,200,000

'

'

Benefit payments made in current fiscal year

'

'

'

200,000

'

1,100,000

'

'

'

'

'

'

Estimated future benefit payments in current fiscal year

'

'

'

'

'

0

'

'

'

'

'

'

Settlement charges

64,000

500,000

'

'

'

'

'

'

'

'

'

'

Settlement charges expensed

100,000

'

'

'

'

'

'

'

'

'

'

'

Settlements recognized as a pension asset

'

'

'

'

'

'

'

'

'

'

'

400,000

Estimated future employer contributions in current fiscal year

'

'

'

'

'

'

'

'

'

400,000

'

'

Settlement charge expensed

18,000

'

'

'

'

'

'

'

'

'

'

'

Recognized as regulatory asset

'

'

'

'

'

'

'

'

'

'

'

$46,000

Commitments_and_Contingencies_

Commitments and Contingencies - Commitments and Agreements (Details) (USD $)	2 Months Ended		9 Months Ended		9 Months Ended
In Millions, unless otherwise specified	Jan. 15, 2012	Sep. 30, 2013	Sep. 30, 2013	Sep. 30, 2013	Sep. 30, 2013	Sep. 30, 2013	Sep. 30, 2013
	agreement	Contract Termination	Alabama Gas Corporation	Crude Oil and Natural Gas	Natural Gas, Delivery and Storage	Natural Gas	Wholly Owned Properties
			site	MBoe	Alabama Gas Corporation	Alabama Gas Corporation	Alabama Gas Corporation
						Mcf	site
Long-term Purchase Commitment [Line Items]	'	'	'	'	'	'	'
Remaining contractual volume	'	'	'	7,500	'	'	'
Number of agreements to secure drilling rigs	3	'	'	'	'	'	'
Maximum loss contingency range of possible loss	'	$14	'	'	'	'	'
Long-term purchase commitment	'	'	'	'	185	'	'
Long-term purchase commitment, time period	'	'	'	'	'September 2024	'August 2020	'
Long-term commitments expense recognized in statement of operations	'	'	'	'	36.8	'	'
Long-term purchase commitment minimum quantity required	'	'	'	'	'	146,000,000	'
Recorded unconditional purchase obligation, time period	'	'	'	'	'	'October 2014	'
Recorded unconditional purchase obligation	'	'	'	'	'	0.8	'
Recorded unconditional purchase obligation, market value	'	'	'	'	'	$0.80	'
Chain of title, manufactured gas plant sites	'	'	9	'	'	'	4
Chain of title, manufactured gas distribution sites	'	'	5	'	'	'	1
Number of sites with removal activities	'	'	50	'	'	'	'

Commitments_and_Contingencies_1

Commitments and Contingencies - Environmental Matters (Details) (Mitchell County, Texas, USD $)	9 Months Ended
In Millions, unless otherwise specified	Sep. 30, 2013
	pit
Mitchell County, Texas	'
Environmental Exit Cost [Line Items]	'
Number of sites	9
Anticipated cost	$1.80
Costs incurred	1.6
Accrual for environmental loss contingencies	$0.20

Commitments_and_Contingencies_2

Commitments and Contingencies - New Mexico Audits (Details) (USD $)	9 Months Ended
	Sep. 30, 2013
Unfavorable Regulatory Action	'
Loss Contingencies [Line Items]	'
Minimum loss contingency range of loss	$142,000
Maximum loss contingency range of possible loss	$23,000,000
Inestimable loss	'The preliminary findings and subsequent Order (issued April 25, 2011) are contrary to deductions allowed under previous audits, retroactive in application and inconsistent with the Company’s understanding of industry practice. The Company is vigorously contesting the Order and has requested additional information from the ONRR and the Department to assist the Company in evaluating the ONRR Order and the Department’s findings. Management is unable, at this time, to determine a range of reasonably possible losses as a result of this Order, and no amount has been accrued as of March 31, 2013.
New Mexico	'
Loss Contingencies [Line Items]	'
Number of counties ONRR has ordered to restructure accounting on federal leases	2

Financial_Instruments_Details

Financial Instruments (Details) (USD $)

3 Months Ended

9 Months Ended

9 Months Ended

Sep. 30, 2013

Sep. 30, 2013

Dec. 31, 2011

Sep. 30, 2013

Dec. 31, 2012

Dec. 31, 2011

Sep. 30, 2013

Dec. 31, 2012

Sep. 30, 2013

Dec. 31, 2012

Sep. 30, 2013

Dec. 31, 2012

Sep. 30, 2013

Sep. 30, 2013

Swap

Swap

Swap

Senior Term Loans, Due March 31, 2014 to November 29, 2016

Alabama Gas Corporation

Alabama Gas Corporation

Long-term Debt, Including Current Portion, Fair Value, Fair Value Disclosure

Long-term Debt, Including Current Portion, Fair Value, Fair Value Disclosure

Long-term Debt, Including Current Portion, Fair Value, Fair Value Disclosure

Long-term Debt, Including Current Portion, Fair Value, Fair Value Disclosure

Long-term Debt, Including Current Portion, Carrying Value, Fair Value Disclosure

Long-term Debt, Including Current Portion, Carrying Value, Fair Value Disclosure

Senior Loans

Senior Loans

Senior Loans

Swap

Alabama Gas Corporation

Alabama Gas Corporation

Alabama Gas Corporation

Level 1

Level 1

Senior Loans

Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Long-term debt fair value

'

'

'

'

'

'

'

'

$1,188,200,000

$1,255,800,000

$262,800,000

$284,700,000

$1,154,000,000

$250,000,000

Face amount

'

'

'

'

'

200,000,000

'

'

'

'

'

'

'

'

Interest rate

'

'

2.42%

'

'

'

'

'

'

'

'

'

'

'

Interest rate cash flow hedge liability at fair value

'

'

'

2,100,000

3,300,000

'

'

'

'

'

'

'

'

'

Financing receivable

'

'

'

'

'

'

10,800,000

10,700,000

'

'

'

'

'

'

Financing receivable recorded investment average balance 0 to 60 days past due

'

'

'

'

'

'

3,000

'

'

'

'

'

'

'

Average finance receivable term

'

'

'

'

'

'

'84 months

'

'

'

'

'

'

'

Time after which delinquent accounts are evaluated

'90 days

'

'

'

'

'

'

'

'

'

'

'

'

'

Financing receivable recorded investment, equal to greater than 90 days past due

'

'

'

'

'

'

700,000

500,000

'

'

'

'

'

'

Financing Receivable, Allowance for Credit Losses [Roll Forward]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Allowance for credit losses as of December 31, 2012

'

470,000

'

'

'

'

'

'

'

'

'

'

'

'

Provision

'

191,000

'

'

'

'

'

'

'

'

'

'

'

'

Allowance for credit losses as of September 30, 2013

$661,000

$661,000

'

'

'

'

'

'

'

'

'

'

'

'

Regulatory_Assets_and_Liabilit2

Regulatory Assets and Liabilities (Details) (USD $)	Sep. 30, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified
Regulatory Assets and Liabilities [Line Items]	'	'
Regulatory Assets, Current	$11,213	$45,515
Regulatory assets, noncurrent	89,004	110,566
Regulatory Liability, Current	40,168	45,116
Regulatory Liability, Noncurrent	81,414	80,404
Alabama Gas Corporation	'	'
Regulatory Assets and Liabilities [Line Items]	'	'
Regulatory Assets, Current	11,213	45,515
Regulatory assets, noncurrent	89,004	110,566
Regulatory Liability, Current	40,168	45,116
Regulatory Liability, Noncurrent	81,414	80,404
Alabama Gas Corporation | RSE adjustment	'	'
Regulatory Assets and Liabilities [Line Items]	'	'
Regulatory Liability, Current	6,573	1,740
Regulatory Liability, Noncurrent	0	0
Alabama Gas Corporation | Unbilled service margin	'	'
Regulatory Assets and Liabilities [Line Items]	'	'
Regulatory Liability, Current	6,351	25,078
Regulatory Liability, Noncurrent	0	0
Alabama Gas Corporation | Postretirement liabilities	'	'
Regulatory Assets and Liabilities [Line Items]	'	'
Regulatory Liability, Current	0	0
Regulatory Liability, Noncurrent	13,951	1,237
Alabama Gas Corporation | Refundable negative salvage	'	'
Regulatory Assets and Liabilities [Line Items]	'	'
Regulatory Liability, Current	16,321	18,265
Regulatory Liability, Noncurrent	40,946	53,467
Alabama Gas Corporation | Gain on sale of property	'	'
Regulatory Assets and Liabilities [Line Items]	'	'
Regulatory Liability, Current	10,890	0
Regulatory Liability, Noncurrent	0	0
Alabama Gas Corporation | Accretion and depreciation for asset retirement obligation	'	'
Regulatory Assets and Liabilities [Line Items]	'	'
Regulatory Liability, Current	0	0
Regulatory Liability, Noncurrent	25,772	24,930
Alabama Gas Corporation | Other	'	'
Regulatory Assets and Liabilities [Line Items]	'	'
Regulatory Liability, Current	33	33
Regulatory Liability, Noncurrent	745	770
Alabama Gas Corporation | Pension and postretirement assets	'	'
Regulatory Assets and Liabilities [Line Items]	'	'
Regulatory Assets, Current	263	170
Regulatory assets, noncurrent	69,249	90,708
Alabama Gas Corporation | Accretion and depreciation for asset retirement obligation	'	'
Regulatory Assets and Liabilities [Line Items]	'	'
Regulatory Assets, Current	0	0
Regulatory assets, noncurrent	17,579	16,536
Alabama Gas Corporation | Risk management activities	'	'
Regulatory Assets and Liabilities [Line Items]	'	'
Regulatory Assets, Current	0	2,593
Regulatory assets, noncurrent	0	0
Alabama Gas Corporation | Rate recovery of asset removal costs, net	'	'
Regulatory Assets and Liabilities [Line Items]	'	'
Regulatory Assets, Current	0	0
Regulatory assets, noncurrent	2,176	3,322
Alabama Gas Corporation | Gas supply adjustment	'	'
Regulatory Assets and Liabilities [Line Items]	'	'
Regulatory Assets, Current	10,925	42,726
Regulatory assets, noncurrent	0	0
Alabama Gas Corporation | Other	'	'
Regulatory Assets and Liabilities [Line Items]	'	'
Regulatory Assets, Current	25	26
Regulatory assets, noncurrent	$0	$0

Asset_Retirement_Obligations_D

Asset Retirement Obligations (Details) (USD $)	9 Months Ended
In Thousands, unless otherwise specified	Sep. 30, 2013	Sep. 30, 2012	Dec. 31, 2012
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]	'	'	'
Balance as of December 31, 2012	$118,023	'	'
Liabilities incurred	2,466	'	'
Liabilities settled	-542	'	'
Accretion expense	6,131	5,581	'
Reclassification associated with held for sale properties	-19,474	'	'
Balance as of September 30, 2013	106,604	'	'
Regulatory assets, noncurrent	89,004	'	110,566
Accretion expense, discontinued operations	944	'	'
Alabama Gas Corporation	'	'	'
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]	'	'	'
Balance as of December 31, 2012	'	'	24,900
Balance as of September 30, 2013	25,800	'	24,900
Regulatory assets, noncurrent	89,004	'	110,566
Asset removal costs | Alabama Gas Corporation	'	'	'
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]	'	'	'
Regulatory assets, noncurrent	$2,176	'	$3,322

Dispositions_of_Properties_Det

Dispositions of Properties (Details) (Alabama Gas Corporation, USD $)	9 Months Ended		1 Months Ended	3 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Aug. 31, 2013	Sep. 30, 2013
			Birmingham Metro Operations Center	Birmingham Metro Operations Center
Gas and Oil Acreage [Line Items]	'	'	'	'
Gain on disposition of property, plant and equipment	($10,889,000)	$0	$10,900,000	'
Real Estate, Sales Price	'	'	'	$13,800,000
Lease back period after sale	'	'	'	'20 months

Rollforward_of_Accumulated_Oth

Rollforward of Accumulated Other Comprehensive Income (Loss) (Details) (USD $)	9 Months Ended
In Thousands, unless otherwise specified	Sep. 30, 2013
Accumulated Other Comprehensive Income (Loss) [Roll Forward]	'
Balance as of December 31, 2012	($8,311)
Other comprehensive income (loss) before reclassifications	-6,767
Amounts reclassified from accumulated other comprehensive income (loss)	-13,186
Change in accumulated other comprehensive income (loss)	-19,953
Balance as of September 30, 2013	-28,264
Cash Flow Hedges	'
Accumulated Other Comprehensive Income (Loss) [Roll Forward]	'
Balance as of December 31, 2012	44,196
Other comprehensive income (loss) before reclassifications	-10,924
Amounts reclassified from accumulated other comprehensive income (loss)	-17,907
Change in accumulated other comprehensive income (loss)	-28,831
Balance as of September 30, 2013	15,365
Pension and Postretirement Plans	'
Accumulated Other Comprehensive Income (Loss) [Roll Forward]	'
Balance as of December 31, 2012	-52,507
Other comprehensive income (loss) before reclassifications	4,157
Amounts reclassified from accumulated other comprehensive income (loss)	4,721
Change in accumulated other comprehensive income (loss)	8,878
Balance as of September 30, 2013	($43,629)

Reclassifications_of_Accumulat

Reclassifications of Accumulated Other Comprehensive Income (Details) (USD $)	3 Months Ended				9 Months Ended
	Sep. 30, 2013		Mar. 31, 2013	Sep. 30, 2012	Sep. 30, 2013		Sep. 30, 2012
Gains and (losses) on cash flow hedges:	'		'	'	'		'
Operating revenues from continuing operations	$320,406,000		'	$276,429,000	$1,265,917,000		$1,126,522,000
Interest expense	-17,689,000		'	-17,195,000	-51,751,000		-48,447,000
Income tax expense	3,627,000		'	322,000	-73,897,000		-110,508,000
Pension and postretirement plans:	'		'	'	'		'
Settlement charges	64,000		500,000	'	'		'
Settlement charges expensed	100,000		'	'	'		'
Settlement charge expensed	18,000		'	'	'		'
Alabama Gas Corporation	'		'	'	'		'
Gains and (losses) on cash flow hedges:	'		'	'	'		'
Interest expense	-3,869,000		'	-4,164,000	-11,733,000		-12,185,000
Pension and postretirement plans:	'		'	'	'		'
Settlements recognized as a pension asset	400,000		'	'	'		'
Recognized as regulatory asset	46,000		'	'	46,000		'
Reclassification out of Accumulated Other Comprehensive Income	'		'	'	'		'
Gains and (losses) on cash flow hedges:	'		'	'	'		'
Net of tax	3,488,000		'	'	13,186,000		'
Cash Flow Hedges | Reclassification out of Accumulated Other Comprehensive Income	'		'	'	'		'
Gains and (losses) on cash flow hedges:	'		'	'	'		'
Total	7,987,000		'	'	28,944,000		'
Income tax expense	-3,048,000		'	'	-11,037,000		'
Net of tax	4,939,000		'	'	17,907,000		'
Pension and Postretirement Plans | Reclassification out of Accumulated Other Comprehensive Income	'		'	'	'		'
Gains and (losses) on cash flow hedges:	'		'	'	'		'
Total	-2,234,000		'	'	-7,263,000		'
Income tax expense	783,000		'	'	2,542,000		'
Net of tax	-1,451,000		'	'	-4,721,000		'
Pension and postretirement plans:	'		'	'	'		'
Transition obligation	-74,000		'	'	-220,000		'
Prior service cost	-78,000		'	'	-235,000		'
Actuarial losses	-2,036,000	[1]	'	'	-6,387,000	[1]	'
Actuarial losses on settlement charges	-46,000	[1]	'	'	-421,000	[1]	'
Commodity contracts | Cash Flow Hedges | Reclassification out of Accumulated Other Comprehensive Income	'		'	'	'		'
Gains and (losses) on cash flow hedges:	'		'	'	'		'
Operating revenues from continuing operations	8,433,000		'	'	30,226,000		'
Interest rate swap | Cash Flow Hedges | Reclassification out of Accumulated Other Comprehensive Income	'		'	'	'		'
Gains and (losses) on cash flow hedges:	'		'	'	'		'
Interest expense	($446,000)		'	'	($1,282,000)		'
[1]	In the first quarter of 2013, the Company incurred a settlement charge of $0.5 million for the payment of lump sums from the nonqualified supplemental retirement plans, of which $0.1 million is recognized in actuarial losses above and $0.4 million is recognized as a regulatory asset at Alagasco and reported in actuarial losses on settlement charges above.

Discontinued_Operations_Narrat

Discontinued Operations Narrative (Details) (USD $)	3 Months Ended	9 Months Ended			1 Months Ended	3 Months Ended
	Mar. 31, 2012	Sep. 30, 2013	Sep. 30, 2012	Dec. 31, 2012	Oct. 31, 2013	Sep. 30, 2013	Dec. 31, 2012	Dec. 31, 2012
				Black Warrior Basin Properties	Black Warrior Basin Properties	North Louisiana and East Texas Natural Gas and Oil Properties	North Louisiana and East Texas Natural Gas and Oil Properties	North Louisiana and East Texas Natural Gas and Oil Properties
				Natural Gas	Alabama		Natural Gas	Oil
				Mcf	Subsequent Event		Mcf	bbl
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]	'	'	'	'	'	'	'	'
Proceeds from the sale of oil and gas property	'	'	'	'	$160,000,000	'	'	'
Gain on disposition of oil and gas property	'	'	'	'	35,000,000	'	'	'
Proved Developed Reserves (Volume)	'	'	'	97,000,000	'	'	20,000,000	0
Impairment of oil and gas properties held-for-sale	'	'	'	'	'	24,600,000	'	'
Asset impairment	$21,500,000	$24,612,000	$21,545,000	'	'	'	'	'
Discount rate	'	10.00%	'	'	'	'	'	'

Discontinued_Operations_Balanc

Discontinued Operations Balance Sheet and Income Statement (Details) (USD $)	3 Months Ended		9 Months Ended
In Thousands, except Per Share data, unless otherwise specified	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
Assets of Disposal Group, Including Discontinued Operation [Abstract]	'	'	'	'
Accounts receivable	$5,122	'	$5,122	'
Inventories	1,141	'	1,141	'
Oil and gas properties	652,392	'	652,392	'
Less accumulated depreciation, depletion and amortization	-476,946	'	-476,946	'
Other property, net	2,153	'	2,153	'
Total assets held-for-sale	183,862	'	183,862	'
Liabilities of Disposal Group, Including Discontinued Operation [Abstract]	'	'	'	'
Accounts payable	-1,715	'	-1,715	'
Royalty payable	-1,728	'	-1,728	'
Other current liabilities	-393	'	-393	'
Other long-term liabilities	-20,109	'	-20,109	'
Total liabilities held-for-sale	-23,945	'	-23,945	'
Total held-for-sale properties	159,917	'	159,917	'
Disposal Group, Including Discontinued Operation, Income Statement Disclosures [Abstract]	'	'	'	'
Oil and gas revenues	18,258	18,895	55,483	57,601
Pretax income (loss) from discontinued operations	2,971	5,526	9,980	-6,028
Income tax expense (benefit)	1,105	1,975	3,711	-2,044
Income (Loss) From Discontinued Operations	1,866	3,551	6,269	-3,984
Loss on disposal of discontinued operations	-24,612	0	-24,612	0
Income tax benefit	-8,934	0	-8,934	0
Loss on Disposal of Discontinued Operations	-15,678	0	-15,678	0
Total Income (Loss) From Discontinued Operations	-13,812	3,551	-9,409	-3,984
Diluted Earnings Per Average Common Share	'	'	'	'
Income (Loss) from Discontinued Operations (in dollars per share)	$0.03	$0.05	$0.09	($0.05)
Loss on Disposal of Discontinued Operations (in dollars per share)	($0.22)	$0	($0.22)	$0
Total Income (Loss) From Discontinued Operations (in dollars per share)	($0.19)	$0.05	($0.13)	($0.05)
Basic Earnings Per Average Common Share	'	'	'	'
Income (Loss) from Discontinued Operations (in dollars per share)	$0.03	$0.05	$0.09	($0.06)
Loss on Disposal of Discontinued Operations (in dollars per share)	($0.22)	$0	($0.22)	$0
Total Income (Loss) From Discontinued Operations (in dollars per share)	($0.19)	$0.05	($0.13)	($0.06)
Black Warrior Basin	'	'	'	'
Assets of Disposal Group, Including Discontinued Operation [Abstract]	'	'	'	'
Accounts receivable	3,704	'	3,704	'
Inventories	1,078	'	1,078	'
Oil and gas properties	304,012	'	304,012	'
Less accumulated depreciation, depletion and amortization	-183,011	'	-183,011	'
Other property, net	1,970	'	1,970	'
Total assets held-for-sale	127,753	'	127,753	'
Liabilities of Disposal Group, Including Discontinued Operation [Abstract]	'	'	'	'
Accounts payable	-1,713	'	-1,713	'
Royalty payable	-792	'	-792	'
Other current liabilities	-358	'	-358	'
Other long-term liabilities	-5,377	'	-5,377	'
Total liabilities held-for-sale	-8,240	'	-8,240	'
Total held-for-sale properties	119,513	'	119,513	'
North Louisiana/East Texas	'	'	'	'
Assets of Disposal Group, Including Discontinued Operation [Abstract]	'	'	'	'
Accounts receivable	1,418	'	1,418	'
Inventories	63	'	63	'
Oil and gas properties	348,380	'	348,380	'
Less accumulated depreciation, depletion and amortization	-293,935	'	-293,935	'
Other property, net	183	'	183	'
Total assets held-for-sale	56,109	'	56,109	'
Liabilities of Disposal Group, Including Discontinued Operation [Abstract]	'	'	'	'
Accounts payable	-2	'	-2	'
Royalty payable	-936	'	-936	'
Other current liabilities	-35	'	-35	'
Other long-term liabilities	-14,732	'	-14,732	'
Total liabilities held-for-sale	-15,705	'	-15,705	'
Total held-for-sale properties	$40,404	'	$40,404	'