Energen (EGN) 10-Q 9 May 14 2014 Q1 Quarterly report Financial data

Document_and_Entity_Informatio

Document and Entity Information	3 Months Ended
	Mar. 31, 2014	1-May-14
Entity Information	'	'
Document Type	'10-Q	'
Amendment Flag	'false	'
Document Period End Date	31-Mar-14	'
Document Fiscal Year Focus	'2014	'
Document Fiscal Period Focus	'Q1	'
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	'	72,781,704
Alabama Gas Corporation	'	'
Entity Information	'	'
Document Type	'10-Q	'
Amendment Flag	'false	'
Document Period End Date	31-Mar-14	'
Document Fiscal Year Focus	'2014	'
Document Fiscal Period Focus	'Q1	'
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
In Thousands, except Per Share data, unless otherwise specified	Mar. 31, 2014	Mar. 31, 2013
Operating Revenues	'	'
Oil and gas operations	$297,278	$236,331
Natural gas distribution	263,900	237,685
Total operating revenues	561,178	474,016
Operating Expenses	'	'
Cost of gas	128,114	95,442
Operations and maintenance	155,072	140,712
Depreciation, depletion and amortization	135,697	105,828
Income taxes	'	'
Deferred	10,531	29,028
Taxes, other than income taxes	35,853	28,157
Accretion expense	1,843	1,687
Total operating expenses	456,579	371,826
Operating Income	104,599	102,190
Other Income (Expense)	'	'
Interest expense	-17,640	-16,752
Other income	1,384	1,734
Other expense	-54	-69
Total other expense	-16,310	-15,087
Interest Expense	'	'
Income From Continuing Operations Before Income Taxes	88,289	87,103
Income tax expense	32,797	32,409
Income From Continuing Operations	55,492	54,694
Discontinued Operations, net of tax	'	'
Income (loss) from discontinued operations	-1,126	1,998
Loss on disposal of discontinued operations	-1,050	0
Total Income (Loss) From Discontinued Operations	-2,176	1,998
Net Income	53,316	56,692
Diluted Earnings Per Average Common Share	'	'
Continuing Operations (in dollars per share)	$0.76	$0.75
Discontinued operations (in dollars per share)	($0.03)	$0.03
Diluted Earnings Per Average Common Share (in dollars per share)	$0.73	$0.78
Basic Earnings Per Average Common Share	'	'
Continuing Operations (in dollars per share)	$0.76	$0.76
Discontinued operations (in dollars per share)	($0.03)	$0.03
Net Income (Loss) (in dollars per share)	$0.73	$0.79
Dividends Per Common Share (in dollars per share)	$0.15	$0.14
Diluted Average Common Shares Outstanding	73,045	72,288
Basic Average Common Shares Outstanding	72,629	72,143
Alabama Gas Corporation	'	'
Operating Revenues	'	'
Natural gas distribution	263,900	237,685
Operating Expenses	'	'
Cost of gas	128,114	95,442
Operations and maintenance	36,224	38,017
Depreciation, depletion and amortization	11,325	10,729
Income taxes	'	'
Current	25,217	25,921
Deferred	1,267	3,020
Taxes, other than income taxes	15,886	14,204
Total operating expenses	218,033	187,333
Operating Income	45,867	50,352
Other Income (Expense)	'	'
Interest expense	-3,965	-4,030
Allowance for funds used during construction	73	219
Other income	1,508	750
Other expense	-455	-69
Total other expense	1,126	900
Interest Expense	'	'
Interest on long-term debt	3,376	3,378
Other interest expense	589	652
Discontinued Operations, net of tax	'	'
Net Income	$43,028	$47,222

Consolidated_Condensed_Stateme1

Consolidated Condensed Statements of Comprehensive Income (USD $)	3 Months Ended
In Thousands, unless otherwise specified	Mar. 31, 2014	Mar. 31, 2013
Net Income	$53,316	$56,692
Other comprehensive income (loss):	'	'
Total cash flow hedges	-2,337	-37,272
Pension and postretirement plans:	'	'
Amortization of net obligation at transition, net of tax of $3 and $26, respectively	6	48
Amortization of prior service cost, net of tax of $26 and $27, respectively	48	51
Amortization of net loss, including settlement charges, net of tax of $2,994 and $920, respectively	5,559	1,709
Total pension and postretirement plans	5,613	1,808
Comprehensive Income	56,592	21,228
Derivative commodity instruments	'	'
Other comprehensive income (loss):	'	'
Current period change in fair value	2	-26,798
Reclassification adjustment for commodity derivative instruments, net of tax	-2,513	-10,720
Interest rate swap	'	'
Other comprehensive income (loss):	'	'
Current period change in fair value	-115	-20
Reclassification adjustment for commodity derivative instruments, net of tax	$289	$266

Consolidated_Condensed_Stateme2

Consolidated Condensed Statements of Comprehensive Income (Parenthetical) (USD $)	3 Months Ended
In Thousands, unless otherwise specified	Mar. 31, 2014	Mar. 31, 2013
Amortization of net obligation at transition, tax	$3	$26
Amortization of prior service cost, tax	26	27
Amortization of net loss, including settlement charges, tax	2,994	920
Derivative commodity instruments	'	'
Current period change in fair value of derivative, tax	1	-16,424
Reclassification adjustment for derivative instruments, tax	-1,541	-6,570
Interest rate swap	'	'
Current period change in fair value of derivative, tax	-62	-11
Reclassification adjustment for derivative instruments, tax	$157	$143

Consolidated_Condensed_Balance

Consolidated Condensed Balance Sheets (USD $)	Mar. 31, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified
Current Assets	'	'
Cash and cash equivalents	$35,343	$5,555
Accounts receivable	'	'
Allowance for doubtful accounts	-5,684	-5,694
Accounts receivable, net of allowance for doubtful accounts of $5,684 and $5,694 at March 31, 2014 and December 31, 2013, respectively	299,118	257,545
Inventories	'	'
Storage gas inventory	19,444	32,095
Materials and supplies	16,071	16,601
Liquified natural gas in storage	1,381	3,634
Regulatory assets	1,283	2,756
Income tax receivable	848	5,765
Assets held for sale	1,871	51,104
Deferred income taxes	53,843	41,299
Prepayments and other	9,827	10,877
Total current assets	439,029	427,231
Property, Plant and Equipment	'	'
Oil and gas properties, successful efforts method	7,130,801	6,864,375
Less accumulated depreciation, depletion and amortization	1,898,950	1,776,802
Oil and gas properties, net	5,231,851	5,087,573
Utility plant	1,503,696	1,491,433
Less accumulated depreciation	615,519	605,924
Utility plant, net	888,177	885,509
Other property, net	33,690	30,556
Total property, plant and equipment, net	6,153,718	6,003,638
Other Assets	'	'
Regulatory assets	82,570	84,890
Other postretirement assets	35,769	35,351
Long-term derivative instruments	2,638	5,439
Deferred charges and other	66,666	65,663
Total other assets	187,643	191,343
TOTAL ASSETS	6,780,390	6,622,212
Current Liabilities	'	'
Long-term debt due within one year	60,000	60,000
Notes payable to banks	575,000	539,000
Accounts payable	300,069	250,756
Accrued taxes	55,534	36,228
Customer deposits	21,654	21,692
Amounts due customers	6,397	16,990
Accrued wages and benefits	17,758	33,884
Regulatory liabilities	80,698	49,006
Royalty payable	61,344	51,519
Liabilities related to assets held for sale	3,410	18,545
Other	28,620	32,273
Total current liabilities	1,210,484	1,109,893
Long-term debt	1,328,442	1,343,464
Deferred Credits and Other Liabilities	'	'
Asset retirement obligations	110,729	108,533
Pension liabilities	72,465	67,675
Regulatory liabilities	83,240	94,125
Long-term derivative instruments	1,011	398
Deferred income taxes	1,037,898	1,013,245
Other	24,994	26,860
Total deferred credits and other liabilities	1,330,337	1,310,836
Commitments and Contingencies	'	'
Shareholders’ Equity	'	'
Preferred stock, cumulative $0.01 par value	0	0
Common shareholders’ equity	'	'
Common stock, $0.01 par value	757	756
Premium on capital stock	528,632	520,909
Capital surplus	2,802	2,802
Retained earnings	2,519,025	2,476,616
Accumulated other comprehensive income (loss), net of tax	'	'
Unrealized gain on hedges, net	10,851	13,362
Pension and postretirement plans	-26,632	-32,245
Interest rate swap	-1,010	-1,184
Deferred compensation plan	3,241	3,259
Treasury stock, at cost: 2,965,849 shares and 2,967,999 shares at March 31, 2014 and December 31, 2013, respectively	-126,539	-126,256
Total shareholders’ equity	2,911,127	2,858,019
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY	6,780,390	6,622,212
Alabama Gas Corporation	'	'
Current Assets	'	'
Cash and cash equivalents	34,069	3,032
Accounts receivable	'	'
Gas	109,601	103,301
Other	5,104	5,447
Affiliated companies	3,967	4,662
Allowance for doubtful accounts	-5,000	-5,000
Inventories	'	'
Storage gas inventory	19,444	32,095
Materials and supplies	5,188	5,471
Liquified natural gas in storage	1,381	3,634
Regulatory assets	1,283	2,756
Income tax receivable	0	3,644
Deferred income taxes	19,820	20,049
Prepayments and other	3,768	4,654
Total current assets	198,625	183,745
Property, Plant and Equipment	'	'
Utility plant	1,503,696	1,491,433
Less accumulated depreciation	615,519	605,924
Utility plant, net	888,177	885,509
Other property, net	40	41
Other Assets	'	'
Regulatory assets	82,570	84,890
Other postretirement assets	26,813	26,457
Deferred charges and other	17,117	17,433
Total other assets	126,500	128,780
TOTAL ASSETS	1,213,342	1,198,075
Current Liabilities	'	'
Notes payable to banks	0	50,000
Accounts payable	52,938	48,653
Accrued taxes	47,247	28,027
Customer deposits	21,654	21,692
Amounts due customers	6,397	16,990
Accrued wages and benefits	6,343	7,682
Regulatory liabilities	80,698	49,006
Other	10,155	10,113
Total current liabilities	225,432	232,163
Long-term debt	249,895	249,923
Deferred Credits and Other Liabilities	'	'
Pension liabilities	19,982	20,191
Regulatory liabilities	83,240	94,125
Deferred income taxes	206,669	205,631
Other	11,311	11,462
Total deferred credits and other liabilities	321,202	331,409
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	382,309	350,076
Accumulated other comprehensive income (loss), net of tax	'	'
Total shareholders’ equity	416,813	384,580
Total capitalization	666,708	634,503
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY	$1,213,342	$1,198,075

Consolidated_Condensed_Balance1

Consolidated Condensed Balance Sheets (Parenthetical) (USD $)	Mar. 31, 2014	Dec. 31, 2013
In Thousands, except Share data, unless otherwise specified
Current Assets	'	'
Allowance for doubtful accounts	$5,684	$5,694
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	75,651,310	75,574,156
Treasury stock, shares	2,965,849	2,967,999
Alabama Gas Corporation	'	'
Current Assets	'	'
Allowance for doubtful accounts	$5,000	$5,000
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 $)	3 Months Ended
In Thousands, unless otherwise specified	Mar. 31, 2014	Mar. 31, 2013
Operating Activities	'	'
Net Income	$53,316	$56,692
Adjustments to reconcile net income to net cash provided by operating activities:	'	'
Depreciation and amortization	135,697	105,828
Depreciation, depletion and amortization	137,449	115,295
Accretion expense	2,095	1,997
Deferred income taxes	10,531	29,028
Bad debt expense	461	218
Exploratory expense	1,277	541
Change in derivative fair value	39,555	37,977
(Gain) loss on sale of assets	995	-656
Stock-based compensation expense	5,228	3,063
Other, net	15,716	7,839
Net change in:	'	'
Accounts receivable	-50,857	-35,312
Inventories	15,434	26,338
Accounts payable	30,842	9,670
Amounts due customers, including gas supply pass-through	27,098	10,254
Income tax receivable	4,917	4,781
Pension and other postretirement benefit contributions	-3,880	-10,334
Other current assets and liabilities	6,774	4,062
Net cash provided by operating activities	296,951	261,453
Investing Activities	'	'
Additions to property, plant and equipment	-282,334	-297,301
Acquisitions, net of cash acquired	-6,537	-13,146
Proceeds from sale of assets	8,019	1,370
Purchase of short-term investments	-84,000	0
Sale of short-term investments	84,000	0
Other, net	-122	-362
Net cash used in investing activities	-280,974	-309,439
Financing Activities	'	'
Payment of dividends on common stock	-10,907	-10,473
Issuance of common stock	3,060	0
Reduction of long-term debt	-15,028	-10
Net change in short-term debt	36,000	69,000
Tax benefit on stock compensation	686	68
Net cash provided by financing activities	13,811	58,585
Net change in cash and cash equivalents	29,788	10,599
Cash and cash equivalents at beginning of period	5,555	9,704
Cash and cash equivalents at end of period	35,343	20,303
Alabama Gas Corporation	'	'
Operating Activities	'	'
Net Income	43,028	47,222
Adjustments to reconcile net income to net cash provided by operating activities:	'	'
Depreciation and amortization	11,325	10,729
Deferred income taxes	1,267	3,020
Bad debt expense	466	217
Gain on sale of assets	-612	0
Other, net	1,902	3,685
Net change in:	'	'
Accounts receivable	-20,830	-23,409
Inventories	15,187	23,317
Accounts payable	6,242	-11,306
Amounts due customers, including gas supply pass-through	27,098	10,254
Income tax receivable	3,644	2,762
Pension and other postretirement benefit contributions	-1,590	-5,365
Other current assets and liabilities	18,769	24,183
Net cash provided by operating activities	105,896	85,309
Investing Activities	'	'
Additions to property, plant and equipment	-15,465	-19,046
Proceeds from sale of assets	706	0
Other, net	723	886
Net cash used in investing activities	-14,036	-18,160
Financing Activities	'	'
Payment of dividends on common stock	-10,795	-8,438
Reduction of long-term debt	-28	-10
Net change in short-term debt	-50,000	-47,000
Net cash provided by financing activities	-60,823	-55,448
Net change in cash and cash equivalents	31,037	11,701
Cash and cash equivalents at beginning of period	3,032	5,559
Cash and cash equivalents at end of period	$34,069	$17,260

Basis_of_Presentation

Basis of Presentation	3 Months Ended
	Mar. 31, 2014
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, 2013, 2012 and 2011, included in the 2013 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.

Regulatory_Matters

Regulatory Matters	3 Months Ended
	Mar. 31, 2014
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. Alagasco’s current RSE order has a term extending through September 30, 2018 and will continue beyond September 30, 2018, unless the APSC enters an order to the contrary in a manner consistent with law. In the event of unforeseen circumstances, whether physical or economic, of the nature of force majeure and including a change in control the APSC and Alagasco will consult in good faith with respect to modifications, if any. Effective January 1, 2014, Alagasco’s allowed range of return on average common equity is 10.5 percent to 10.95 percent with an adjusting point of 10.8 percent. The previous allowed range of return on average common equity was 13.15 percent to 13.65 percent through December 31, 2013. 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. 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 ended March 31, 2014 and 2013, Alagasco had net pre-tax reductions in revenues of $16.2 million and $2.4 million, respectively, to bring the return on average common equity to midpoint within the allowed range of return. Under the provisions of RSE, an $8.5 million decrease, $10.3 million increase and $7.8 million increase in revenues became effective January 1, 2014, December 1, 2013 and 2012, respectively. The equity upon which a return will be permitted cannot exceed 56.5 percent of total capitalization, subject to certain adjustments.
	The inflation-based Cost Control Mechanism (CCM), established by the APSC, allows for annual increases to operations and maintenance (O&M) expense. The CCM range is Alagasco’s 2007 actual rate year O&M expense (Base Year) inflation-adjusted using the June Consumer Price Index For All Urban Consumers each rate year plus or minus 1.75 percent (Index Range). If rate year O&M expense falls within the Index Range, no adjustment is required. If rate year O&M expense exceeds the Index Range, three-quarters of the difference is returned to customers through future rate adjustments. To the extent that rate year O&M is less than the Index Range, the utility benefits by one-half of the difference through future rate adjustments. Certain items that fluctuate based on situations demonstrated to be beyond Alagasco’s control may be excluded from the CCM calculation.
	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, which 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 prescribe 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 expects to be able to recover 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	3 Months Ended
	Mar. 31, 2014
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 liquids and natural gas production. Such instruments may include over-the-counter (OTC) swaps and basis swaps typically executed with investment and commercial banks and energy-trading firms. Derivative transactions are pursuant to standing authorizations by the Board of Directors, which do not authorize speculative positions.
	The Company is at risk for economic loss based upon the creditworthiness of its counterparties. Energen Resources was in a net gain position with two of its active counterparties and in a net loss position with the remaining twelve at March 31, 2014. The largest counterparty net gain position at March 31, 2014, Macquarie Bank Limited, constituted approximately $3.0 million of Energen Resources’ total net loss on fair value of derivatives.
	The current policy of the Company is to not enter into agreements that require the posting of collateral. The 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. The effective portion of the gain or loss on the derivative instrument was recognized in accumulated other comprehensive income 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 was required to be recognized in operating revenues immediately. All other derivative transactions not designated as cash flow hedge accounting are accounted for as mark-to-market transactions with gains or losses recognized in operating revenues in the period of change.
	Effective March 31, 2013 and June 30, 2013, Energen Resources dedesignated from cash flow hedge accounting 5,078 thousand barrels (MBbl) and 2,353 MBbl, respectively, of various New York Mercantile Exchange (NYMEX) oil contracts associated with the Permian Basin due to lack of correlation. Gains and 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. 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 derivative commodity instruments on the balance sheets:
	(in thousands)	March 31, 2014
	Derivative assets or (liabilities) not designated as hedging instruments
	Accounts receivable	$	17,522
	Long-term asset derivative instruments	4,989
	Total derivative assets	22,511
	Accounts receivable	(14,165		)	*
	Long-term asset derivative instruments	(2,351		)	*
	Accounts payable	(52,602		)
	Long-term liability derivative instruments	(802		)
	Total derivative liabilities	(69,920		)
	Total derivatives not designated	$	(47,409	)
	(in thousands)	December 31, 2013
	Derivative assets or (liabilities) not designated as hedging instruments
	Accounts receivable	$	36,224
	Long-term asset derivative instruments	7,992
	Total derivative assets	44,216
	Accounts receivable	(18,761		)	*
	Long-term asset derivative instruments	(2,553		)	*
	Accounts payable	(30,302		)
	Total derivative liabilities	(51,616		)
	Total derivatives not designated	$	(7,400	)
	*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 $6.7 million and a net $8.2 million deferred tax liability included in current deferred income taxes on the balance sheets related to derivative items included in accumulated other comprehensive income as of March 31, 2014, and December 31, 2013, respectively.
	The following table details the effect of derivative commodity instruments in cash flow hedging relationships on the financial statements:
	(in thousands)	Location on Statements of Income	Three months			Three months
			ended			ended
			31-Mar-14			31-Mar-13
	Net gain (loss) recognized in other comprehensive income on derivatives (effective portion), net of tax of $1 and ($16,424)	—	$	2		$	(26,798	)
	Gain reclassified from accumulated other comprehensive income into income (effective portion)	Operating revenues	$	4,054		$	17,824
	Loss recognized in income on derivatives (ineffective portion and amount excluded from effectiveness testing)	Operating revenues	$	—		$	(534	)
	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 Statements of Income	Three months			Three months
			ended			ended
			31-Mar-14			31-Mar-13
	Loss recognized in income on derivatives	Operating revenues	$	(57,446	)	$	(31,501	)
	As of March 31, 2014, $10.9 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 March 31, 2014, the Company had 7.4 million barrels (MMBbl) and 7.3 MMBbl of oil swaps which expire during 2014 and 2015, respectively, that are considered mark-to-market transactions. The Company had 44.9 billion cubic feet (Bcf) and 12.0 Bcf of natural gas and natural gas basis swaps which expire during 2014 and 2015, respectively, that are considered mark-to-market transactions. During 2013, the Company had a discontinuance of hedge accounting when Energen Resources determined it was probable certain forecasted volumes would not occur due to certain properties being sold. This discontinuance of hedge accounting resulted in $2.6 million after-tax losses being recognized into operating revenues during the three months ended March 31, 2014.
	As of March 31, 2014, Energen Resources entered into the following transactions for the remainder of 2014 and subsequent years:
	Production Period	Total Hedged Volumes		Average Contract	Description
				Price
	Oil
	2014	7,392	MBbl	$92.65 Bbl	NYMEX Swaps
	2015	7,260	MBbl	$89.07 Bbl	NYMEX Swaps
	Natural Gas
	2014	7.9	Bcf	$4.55 Mcf	NYMEX Swaps
	2014	23.5	Bcf	$4.60 Mcf	Basin Specific Swaps - San Juan
	2014	7.4	Bcf	$3.81 Mcf	Basin Specific Swaps - Permian
	2015	12	Bcf	$4.05 Mcf	Basin Specific Swaps - San Juan
	Natural Gas Basis Differential
	2014	4.6	Bcf	$(0.09) Mcf	San Juan Basis Swaps
	2014	1.5	Bcf	$(0.17) Mcf	Permian Basis Swaps
	As of March 31, 2014, the maximum term over which Energen Resources has hedged exposures to the variability of cash flows is through December 31, 2015.
	The following sets forth derivative assets and liabilities that were measured at fair value on a recurring basis:
		March 31, 2014
	(in thousands)	Level 2*			Level 3*			Total
	Current assets	$	(6,646	)	$	10,003		$	3,357
Noncurrent assets	1,192			1,446			2,638
Current liabilities	(42,531		)	(10,071		)	(52,602		)
Noncurrent liabilities	(802		)	—			(802		)
Net derivative asset (liability)	$	(48,787	)	$	1,378		$	(47,409	)
	31-Dec-13
(in thousands)	Level 2*			Level 3*			Total
Current assets	$	(1,658	)	$	19,121		$	17,463
Noncurrent assets	4,383			1,056			5,439
Current liabilities	(28,414		)	(1,888		)	(30,302		)
Net derivative asset (liability)	$	(25,689	)	$	18,289		$	(7,400	)
*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 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 $18 million change in the fair value of open Level 3 derivative contracts. The resulting impact upon the results of operations would be an approximate $18 million associated with open Level 3 mark-to-market derivative contracts. Liquidity 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)	March 31, 2014			March 31, 2013
Balance at beginning of period	$	18,289		$	89,019
Realized gains (losses)	(3,019		)	27,107
Unrealized losses relating to instruments held at the reporting date*	(16,835		)	(63,482		)
Settlements during period	2,943			(26,185		)
Balance at end of period	$	1,378		$	26,459
*Includes $13.2 million and $12.4 million in mark-to-market losses for the three months ended March 31, 2014 and 2013, 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 March 31, 2014			Valuation Technique*	Unobservable Input*	Range
Natural Gas Basis - San Juan
2014	$	5,326		Discounted Cash Flow	Forward Basis	($0.06 - $0.09) Mcf
2015	$	(129	)	Discounted Cash Flow	Forward Basis	($0.14) Mcf
Natural Gas Basis - Permian
2014	$	(3,819	)	Discounted Cash Flow	Forward Basis	($0.12 - $0.13) Mcf
*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:
	March 31, 2014
										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	$	22,511		$	(16,516	)	$	5,995		$	—	$	—	$	5,995
Derivative liabilities	$	69,920		$	(16,516	)	$	53,404		$	—	$	—	$	53,404
	December 31, 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	$	44,215		$	(21,313	)	$	22,902		$	—	$	—	$	22,902
Derivative liabilities	$	51,615		$	(21,313	)	$	30,302		$	—	$	—	$	30,302

Reconciliation_of_Earnings_Per

Reconciliation of Earnings Per Share (EPS)	3 Months Ended
	Mar. 31, 2014
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)	March 31, 2014						March 31, 2013
		Net				Per Share		Net			Per Share
		Income			Shares	Amount		Income		Shares	Amount
	Basic EPS	$	53,316		72,629	$	0.73	$	56,692	72,143	$	0.79
	Effect of dilutive securities
	Stock options				296					144
	Non-vested restricted stock				44					1
	Performance share awards				76					—
	Diluted EPS	$	53,316		73,045	$	0.73	$	56,692	72,288	$	0.78
	The Company had the following shares that were excluded from the computation of diluted EPS, as their effect was non-dilutive:
		Three months ended
		March 31,
	(in thousands)	2014		2013
	Stock options	111,554		988,087
	Performance share awards	68,250		161,249

Segment_Information

Segment Information	3 Months Ended
	Mar. 31, 2014
Segment Reporting [Abstract]	'
Segment Information	'
	SEGMENT INFORMATION
	The Company is principally engaged in two business segments: the development, 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
		March 31,
	(in thousands)	2014			2013
	Operating revenues from continuing operations
	Oil and gas operations	$	297,278		$	236,331
	Natural gas distribution	263,900			237,685
	Total	$	561,178		$	474,016
	Operating income (loss) from continuing operations
	Oil and gas operations	$	33,548		$	23,181
	Natural gas distribution	72,351			79,293
	Eliminations and corporate expenses	(1,300		)	(284		)
	Total	$	104,599		$	102,190
	Other income (expense) from continuing operations
	Oil and gas operations	$	(13,819	)	$	(12,031	)
	Natural gas distribution	(2,839		)	(3,130		)
	Eliminations and other	348			74
	Total	$	(16,310	)	$	(15,087	)
	Income from continuing operations before income taxes	$	88,289		$	87,103
	(in thousands)	March 31, 2014			31-Dec-13
	Identifiable assets
	Oil and gas operations	$	5,521,883		$	5,379,135
	Natural gas distribution	1,209,375			1,193,413
	Eliminations and other	49,132			49,664
	Total	$	6,780,390		$	6,622,212

Stock_Compensation

Stock Compensation	3 Months Ended
	Mar. 31, 2014
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 and non-qualified stock options 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 was 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 107,868 non-qualified option shares during the first quarter of 2014 with a grant-date fair value of $27.57.
	Restricted Stock: Additionally, the Stock Incentive Plan provides for the grant of restricted stock units. In January 2014, the Company awarded 41,664 restricted stock units with a grant-date fair value of $70.68. 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 using the 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 287 performance share awards during the first quarter of 2014 with a two year vesting period and a grant-date fair value of $118.99. The Company also granted 63,842 performance share awards during the first quarter of 2014 with a three year award period and a grant-date fair value of $93.13.
	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 common 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 62,749 awards during the first quarter of 2014. These awards had a fair value of $35.04 as of March 31, 2014.
	Petrotech Incentive Plan
	The Energen Resources’ Petrotech Incentive Plan provides for the grant of stock equivalent units. These awards are liability awards which are re-measured each reporting period and settle in cash at completion of the vesting period. During the first quarter of 2014, Energen Resources awarded 28,840 Petrotech units with a fair value of $79.18 as of March 31, 2014, none of which included a market condition. Also awarded were 36,920 Petrotech units which included a market condition and had a fair value of $115.94 as of March 31, 2014. These awards have a three year vesting period.
	Stock Repurchase Program
	During the three months ended March 31, 2014, the Company had non-cash purchases of approximately $0.3 million 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	3 Months Ended
	Mar. 31, 2014
Defined Benefit Pension Plans and Defined Benefit Postretirement Plans Disclosure [Abstract]	'
Employee Benefit Plans	'
	EMPLOYEE BENEFIT PLANS
	The components of net periodic benefit cost for the Company’s two defined benefit non-contributory pension plans and certain non-qualified supplemental pension plans were as follows:
		Three months ended
		March 31,
	(in thousands)	2014			2013
	Components of net periodic benefit cost:
	Service cost	$	3,003		$	3,602
	Interest cost	2,575			2,718
	Expected long-term return on assets	(2,848		)	(3,713		)
	Actuarial loss amortization	2,256			3,690
	Prior service cost amortization	118			122
	Settlement charge	7,262			144
	Net periodic expense	$	12,366		$	6,563
	The Company anticipates required contributions of approximately $0.5 million during 2014 to the qualified pension plans. The Company expects sufficient funding credits, as established under Internal Revenue Code Section 430(f), exist to meet the required funding. 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 $3.0 million to the qualified pension plans in January 2014. 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 ended March 31, 2014, the Company made benefit payments aggregating $33,000 to retirees from the non-qualified supplemental retirement plans and expects to make additional benefit payments of approximately $0.2 million through the remainder of 2014. In the first quarter of 2014, the Company incurred a settlement charge of $17.1 million for the payment of lump sums from the qualified defined benefit pension plans, of which $6.9 million was expensed and $10.2 million was recognized as a pension asset in regulatory assets at Alagasco. Also in the first quarter of 2014, the Company incurred a settlement charge of $0.4 million for the payment of lump sums from the non-qualified supplemental retirement plans. In the first quarter of 2013, the Company incurred a settlement charge of $0.5 million for the payment of lump sums from the non-qualified supplemental retirement plans, of which $0.1 million was expensed and $0.4 million was recognized as a pension asset in regulatory assets at Alagasco.
	The components of net periodic benefit cost for the Company’s postretirement benefit plans were as follows:
		Three months ended
		March 31,
	(in thousands)	2014			2013
	Components of net periodic benefit cost:
	Service cost	$	170		$	444
	Interest cost	754			869
	Expected long-term return on assets	(1,412		)	(1,242		)
	Actuarial gain amortization	(520		)	—
	Transition obligation amortization	27			324
	Net periodic (income) expense	$	(981	)	$	395
	There are no required contributions to the postretirement benefit plans during 2014.

Commitments_and_Contingencies

Commitments and Contingencies	3 Months Ended
	Mar. 31, 2014
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 6.4 million barrels of oil equivalent (MMBOE) through September 2017.
	Certain of Alagasco’s long-term contracts associated with the delivery and storage of natural gas include fixed charges of approximately $150 million through September 2024. During the three months ended March 31, 2014 and 2013, Alagasco recognized approximately $13.4 million and $14.4 million, respectively, of long-term commitments through expense and its regulatory accounts in the accompanying financial statements. Alagasco also is committed to purchase minimum quantities of gas at market-related prices or to pay certain costs in the event the minimum quantities are not taken. These purchase commitments are approximately 123 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 March 31, 2014, the fixed price purchases under these guarantees had a maximum term outstanding through December 2014 with an aggregate purchase price and market value of $0.3 million.
	Legal Matters: Energen and its affiliates are, from time to time, parties to various pending or threatened legal proceedings and the Company has accrued a provision for its estimated liability. Certain of these lawsuits include claims for punitive damages in addition to other specified relief. The Company recognizes its liability for contingencies when information available indicates both a loss is probable and the amount of the loss can be reasonably estimated. 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 there is uncertainty in the valuation of pending claims and prediction of litigation results.
	On December 17, 2013, an incident occurred at a Housing Authority apartment complex in Birmingham, Alabama which resulted in one fatality, personal injuries and property damage. Alagasco is cooperating with the National Transportation Safety Board which is investigating the incident. Alagasco has been named as a defendant in several lawsuits arising from the incident and additional lawsuits and claims may be filed against Alagasco.
	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 $2.1 million of which $1.9 million has been incurred and $0.2 million has been reserved.
	During January 2014, Energen Resources responded to a General Notice and Information Request from the Environmental Protection Agency (EPA) regarding the Reef Environmental Site in Sylacauga, Talladega County, Alabama. The letter identifies Energen Resources as a potentially responsible party (PRP) under The Comprehensive Environmental Response, Compensation, and Liability Act (CERCLA) for the cleanup of the Site. In 2008, Energen hired a third party to transport approximately 3,000 gallons of non-hazardous wastewater to Reef Environmental for wastewater treatment. Reef Environmental ceased operating its wastewater treatment system in 2010. Due to its one time use of Reef Environmental for a small volume of non-hazardous wastewater, Energen Resources has not accrued a liability for cleanup of the Site.
	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 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 35th Avenue Superfund Site located in North 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 the EPA a General Notice Letter and Invitation to Conduct a Removal Action at the 35th Avenue Superfund Site. The letter identifies Alagasco as a 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 discussed its designation as a PRP further with the EPA, and Alagasco has requested additional information from the EPA regarding its designation as a PRP. Alagasco has also been approached by a law firm regarding entry into an agreement to toll the statute of limitations with potential plaintiffs related to purported damages allegedly incurred by such potential plaintiffs in connection with the 35th Avenue Superfund Site, and is considering whether to enter into such a tolling arrangement. Alagasco has not been provided information at this time that would allow it to determine the extent, if any, of its potential liability with respect to the 35th Avenue Superfund Site and the proposed removal action, and therefore Alagasco has not agreed to undertake the proposed removal activities and no amount has been accrued as of March 31, 2014.
	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 March 31, 2014.

Financial_Instruments

Financial Instruments	3 Months Ended
	Mar. 31, 2014
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 $1,421.2 million and $1,420.7 million and had a carrying value of $1,388.9 million and $1,403.9 million at March 31, 2014 and December 31, 2013, respectively. The fair value of Alagasco’s fixed-rate long-term debt, including the current portion, was approximately $263.5 million and $258.8 million and had a carrying value of $249.9 million at March 31, 2014 and December 31, 2013, 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.
	At March 31, 2014, the Company had interest rate swap agreements with a notional of $200 million. The interest rate swaps exchange a variable interest rate for a fixed interest rate of 2.6675 percent. The fair value of the Company’s interest rate swap was a $1.6 million and a $1.8 million liability at March 31, 2014 and December 31, 2013, 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 March 31, 2014 and December 31, 2013, Alagasco’s finance receivable totaled $10.5 million and $10.8 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 creditworthiness thresholds for customer payment history and external agency credit reports. Alagasco relies upon ongoing payments as the primary indicator of credit quality during the term of each contract. The allowance for credit losses is recognized using an estimate of write-off percentages based on historical experience applied to an aging of the finance receivable balance. Delinquent accounts are evaluated on a case-by-case basis and, absent evidence of debt repayment after 90 days, are due in full and assigned to a third-party collection agency. The remaining finance receivable is written off approximately 12 months after being assigned to a third-party collection agency. Alagasco had finance receivables past due 90 days or more of $0.3 million and $0.4 million as of March 31, 2014 and December 31, 2013, 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, 2013	$	423
	Provision	(124		)
	Allowance for credit losses as of March 31, 2014	$	299

Exploratory_Costs

Exploratory Costs	3 Months Ended
	Mar. 31, 2014
Extractive Industries [Abstract]	'
Exploratory Costs	'
	EXPLORATORY COSTS
	The Company capitalizes exploratory drilling costs until a determination is made that the well or project has either found proved reserves or is impaired. After an exploratory well has been drilled and found oil and natural gas reserves, a determination may be pending as to whether the oil and natural gas quantities can be classified as proved. In those circumstances, the Company continues to capitalize the drilling costs pending the determination of proved status if (i) the well has found a sufficient quantity of reserves to justify its completion as a producing well and (ii) the Company is making sufficient progress assessing the reserves and the economic and operating viability of the project. Capitalized exploratory drilling costs are presented in oil and gas properties in the balance sheets. If the exploratory well is determined to be impaired, the impaired costs are charged to operations and maintenance expense. Other exploration costs, including geological and geophysical costs, are expensed as incurred.
	The following table sets forth capitalized exploratory well costs and includes additions pending determination of proved reserves, reclassifications to proved reserves and costs charged to expense:
		Three months ended			Three months ended
	(in thousands)	31-Mar-14			31-Mar-13
	Capitalized exploratory well costs at beginning of period	$	57,600		$	79,791
	Additions pending determination of proved reserves	164,842			95,861
	Reclassifications due to determination of proved reserves	(112,474		)	(69,477		)
	Capitalized exploratory well costs at end of period	$	109,968		$	106,175
	The following table sets forth capitalized exploratory wells costs and includes amounts capitalized for a period greater than one year:
		Three months ended			Three months ended
	(in thousands)	March 31, 2014			31-Mar-13
	Exploratory wells in progress	$	62,280		$	21,676
	Capitalized exploratory well costs capitalized for a period of one year or less	46,460			83,301
	Capitalized exploratory well costs for a period greater than one year	1,228			1,198
	Total capitalized exploratory well costs	$	109,968		$	106,175
	At March 31, 2014, the Company had 45 gross exploratory wells either drilling or waiting on results from completion and testing. These wells are primarily located in the Permian Basin. The Company has one gross well capitalized greater than a year which is pending results from completion and testing. This well is currently waiting on facilities.

Regulatory_Assets_and_Liabilit

Regulatory Assets and Liabilities	3 Months Ended
	Mar. 31, 2014
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)	March 31, 2014				December 31, 2013
		Current		Noncurrent		Current		Noncurrent
	Regulatory assets:
	Pension assets	$	1,258	$	56,133	$	325	$	58,243
	Accretion and depreciation of asset retirement obligations	—		18,436		—		18,046
	Rate recovery of asset removal costs, net	—		4,001		—		4,601
	Enhanced stability reserve	—		4,000		—		4,000
	Gas supply adjustment	—		—		2,406		—
	Other	25		—		25		—
	Total regulatory assets	$	1,283	$	82,570	$	2,756	$	84,890
	Regulatory liabilities:
	RSE adjustment	$	16,193	$	—	$	4,690	$	—
	Unbilled service margin	28,251		—		28,504		—
	Postretirement liabilities	—		25,826		—		26,197
	Gas supply adjustment	23,782		—		—		—
	Refundable negative salvage	12,439		28,846		15,779		39,663
	Asset retirement obligation	—		27,840		—		27,528
	Other	33		728		33		737
	Total regulatory liabilities	$	80,698	$	83,240	$	49,006	$	94,125

Asset_Retirement_Obligations

Asset Retirement Obligations	3 Months Ended
	Mar. 31, 2014
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 lives 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 three months ended March 31, 2014, 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, 2013	$	108,533
	Liabilities incurred	766
	Liabilities settled	(413		)
	Accretion expense	1,843
	Balance as of March 31, 2014	$	110,729
	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 $27.8 million and $27.5 million to purge and cap its gas pipelines upon abandonment and to remediate other related obligations, as a regulatory liability as of March 31, 2014 and December 31, 2013, respectively. Regulatory assets for rate recovery of accumulated asset removal costs of $4.0 million and $4.6 million as of March 31, 2014 and December 31, 2013, 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.

Acquisition_and_Dispositions_o

Acquisition and Dispositions of Properties	3 Months Ended
	Mar. 31, 2014
Extractive Industries [Abstract]	'
Acquisition and Dispositions of Properties	'
	ACQUISITION AND DISPOSITION OF PROPERTIES
	In August 2013, Alagasco recorded a pre-tax gain of $10.9 million related to 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. During the third quarter of 2013, 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. In conjunction with the receipt of the rate order from the APSC on December 20, 2013, Alagasco recognized the deferred revenues from this 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.
	During 2013, Energen also completed a total of approximately $31.3 million in various purchases of unproved leasehold properties.

Accumulated_Other_Comprehensiv

Accumulated Other Comprehensive Income (Loss)	3 Months Ended
	Mar. 31, 2014
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, 2013	$	12,178		$	(32,245	)	$	(20,067	)
	Other comprehensive loss before reclassifications	(113		)	—			(113		)
	Amounts reclassified from accumulated other comprehensive income (loss)	(2,224		)	5,613			3,389
	Change in accumulated other comprehensive income (loss)	(2,337		)	5,613			3,276
	Balance as of March 31, 2014	$	9,841		$	(26,632	)	$	(16,791	)
	The following table provides details of the reclassifications out of accumulated other comprehensive income (loss).
		Three months ended			Three months ended
		31-Mar-14			31-Mar-13
	(in thousands)	Amounts Reclassified						Line Item Where Presented
	Gains and (losses) on cash flow hedges:
	Derivative commodity instruments	$	4,054		$	17,290		Operating revenues
	Interest rate swap	(446		)	(409		)	Interest expense
	Total cash flow hedges	3,608			16,881
	Income tax expense	(1,384		)	(6,427		)
	Net of tax	2,224			10,454
	Pension and postretirement plans:
	Transition obligation	(10		)	(74		)	Operations and maintenance
	Prior service cost	(74		)	(78		)	Operations and maintenance
	Actuarial losses*	(1,290		)	(2,254		)	Operations and maintenance
	Actuarial losses on settlement charges	(7,262		)	—			Operations and maintenance
	Actuarial losses on settlement charges*	—			(375		)	Regulatory asset
	Total pension and postretirement plans	(8,636		)	(2,781		)
	Income tax benefit	3,023			973
	Net of tax	(5,613		)	(1,808		)
	Total reclassifications for the period	$	(3,389	)	$	8,646
	*In the first quarter of 2013, the Company incurred a settlement charge of $0.5 million for the payment of lump sums from the non-qualified supplemental retirement plans, of which $0.1 million is recognized in actuarial gains (losses) above and $0.4 million 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	3 Months Ended
	Mar. 31, 2014
New Accounting Pronouncements and Changes in Accounting Principles [Abstract]	'
Recently Issued Accounting Standards	'
	RECENTLY ISSUED ACCOUNTING STANDARDS
	In April 2014, the Financial Accounting Standards Board issued Accounting Standards Update (ASU) No. 2014-08, Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity. This update defines a discontinued operation as a disposal of a component or a group of components that is disposed of or is classified as held-for-sale and represents a strategic shift that has (or will have) a major effect on an entity’s operations and financial results. The amendment is effective for all annual periods beginning on or after December 15, 2014, and interim periods within those annual periods. The Company is currently evaluating the impact of this ASU.

Discontinued_Operations

Discontinued Operations	3 Months Ended
	Mar. 31, 2014
Discontinued Operations and Disposal Groups [Abstract]	'
Discontinued Operations	'
	DISCONTINUED OPERATIONS
	In March 2014, Energen Resources completed the sale on its North Louisiana/East Texas natural gas and oil properties for $30.3 million (subject to closing adjustments). The sale had an effective date of December 1, 2013, and the proceeds from the sale were used to repay short-term obligations. During the third quarter of 2013, Energen Resources classified these natural gas and oil properties as held-for-sale and reflected the associated operating results in discontinued operations. Energen Resources recognized a non-cash impairment writedown on these properties in the first quarter of 2014 of $1.7 million pre-tax to adjust the carrying amount of these properties to their fair value based on an estimate of the selling price of the properties. This non-cash impairment writedown is reflected in loss on disposal of discontinued operations in the three months ended March 31, 2014. Energen Resources also recognized non-cash impairment writedowns on these properties in the third and fourth quarters of 2013 of $24.6 million pre-tax and $5.2 million pre-tax, respectively. Significant assumptions in valuing the proved reserves included the reserve quantities, anticipated operating costs, anticipated production taxes, future expected natural gas prices and basis differentials, anticipated production declines, and a discount rate of 10 percent commensurate with the risk of the underlying cash flow estimates. The impairment writedowns are classified as Level 3 fair value. At December 31, 2013, proved reserves associated with Energen’s North Louisiana/East Texas properties totaled 23 Bcf of natural gas and 91 MBbl of oil.
	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 recorded a pre-tax gain on the sale of approximately $35 million in the fourth quarter of 2013 which was reflected in gain on disposal of discontinued operations in the year ended December 31, 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.
	The following table details held-for-sale properties by major classes of assets and liabilities:
	(in thousands)	31-Mar-14
		Black Warrior Basin			North Louisiana/East Texas			Total
	Accounts receivable	$	—		$	1,670		$	1,670
	Inventories	—			68			68
	Other property, net	—			133			133
	Total assets held-for-sale	—			1,871			1,871
	Accounts payable	(2,172		)	(10		)	(2,182		)
	Royalty payable	—			(1,221		)	(1,221		)
	Other current liabilities	—			(7		)	(7		)
	Total liabilities held-for-sale	(2,172		)	(1,238		)	(3,410		)
	Total net held-for-sale properties	$	(2,172	)	$	633		$	(1,539	)
	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
		March 31,
	(in thousands, except per share data)	2014			2013
	Oil and gas revenues	$	4,821		$	18,663
	Pretax income (loss) from discontinued operations	$	(2,078	)	$	3,168
	Income tax expense (benefit)	(952		)	1,170
	Income (Loss) From Discontinued Operations	$	(1,126	)	$	1,998
	Loss on disposal of discontinued operations	$	(1,667	)	$	—
	Income tax benefit	(617		)	—
	Loss on Disposal of Discontinued Operations	$	(1,050	)	$	—
	Total Income (Loss) From Discontinued Operations	$	(2,176	)	$	1,998
	Diluted Earnings Per Average Common Share
	Income (Loss) from Discontinued Operations	$	(0.02	)	$	0.03
	Loss on Disposal of Discontinued Operations	(0.01		)	—
	Total Income (Loss) From Discontinued Operations	$	(0.03	)	$	0.03
	Basic Earnings Per Average Common Share
	Income (Loss) from Discontinued Operations	$	(0.02	)	$	0.03
	Loss on Disposal of Discontinued Operations	(0.01		)	—
	Total Income (Loss) From Discontinued Operations	$	(0.03	)	$	0.03

Subsequent_Event

Subsequent Event	3 Months Ended
	Mar. 31, 2014
Subsequent Events [Abstract]	'
Subsequent Event	'
	SUBSEQUENT EVENTS
	In April 2014, Energen signed a stock purchase agreement to sell Alagasco to The Laclede Group, Inc. (Laclede) for $1.6 billion, subject to closing adjustments, which includes an estimated $1.28 billion in cash and the assumption of $320 million in debt. This sale is expected to close during 2014. Energen plans to use cash proceeds from the sale to reduce long-term and short-term indebtedness.
	Due to the sale of Alagasco discussed above, the Company has separated its qualified defined benefit plans and the postretirement health care and life insurance benefit plans into separate plans established for Energen and Alagasco. These separate plans will be remeasured effective April 30, 2014.

Basis_of_Presentation_Policies

Basis of Presentation (Policies)	3 Months Ended
	Mar. 31, 2014
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, 2013, 2012 and 2011, included in the 2013 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 liquids and natural gas production. Such instruments may include over-the-counter (OTC) swaps and basis swaps typically executed with investment and commercial banks and energy-trading firms. Derivative transactions are pursuant to standing authorizations by the Board of Directors, which do not authorize speculative positions.
	The Company is at risk for economic loss based upon the creditworthiness of its counterparties. Energen Resources was in a net gain position with two of its active counterparties and in a net loss position with the remaining twelve at March 31, 2014. The largest counterparty net gain position at March 31, 2014, Macquarie Bank Limited, constituted approximately $3.0 million of Energen Resources’ total net loss on fair value of derivatives.
	The current policy of the Company is to not enter into agreements that require the posting of collateral. The 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. The effective portion of the gain or loss on the derivative instrument was recognized in accumulated other comprehensive income 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 was required to be recognized in operating revenues immediately. All other derivative transactions not designated as cash flow hedge accounting are accounted for as mark-to-market transactions with gains or losses recognized in operating revenues in the period of change.
	Effective March 31, 2013 and June 30, 2013, Energen Resources dedesignated from cash flow hedge accounting 5,078 thousand barrels (MBbl) and 2,353 MBbl, respectively, of various New York Mercantile Exchange (NYMEX) oil contracts associated with the Permian Basin due to lack of correlation. Gains and 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. 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	'
	RECENTLY ISSUED ACCOUNTING STANDARDS
	In April 2014, the Financial Accounting Standards Board issued Accounting Standards Update (ASU) No. 2014-08, Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity. This update defines a discontinued operation as a disposal of a component or a group of components that is disposed of or is classified as held-for-sale and represents a strategic shift that has (or will have) a major effect on an entity’s operations and financial results. The amendment is effective for all annual periods beginning on or after December 15, 2014, and interim periods within those annual periods. The Company is currently evaluating the impact of this ASU.

Derivative_Commodity_Instrumen1

Derivative Commodity Instruments (Tables)	3 Months Ended
	Mar. 31, 2014
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 derivative commodity instruments on the balance sheets:
	(in thousands)	March 31, 2014
	Derivative assets or (liabilities) not designated as hedging instruments
	Accounts receivable	$	17,522
	Long-term asset derivative instruments	4,989
	Total derivative assets	22,511
	Accounts receivable	(14,165		)	*
	Long-term asset derivative instruments	(2,351		)	*
	Accounts payable	(52,602		)
	Long-term liability derivative instruments	(802		)
	Total derivative liabilities	(69,920		)
	Total derivatives not designated	$	(47,409	)
	(in thousands)	December 31, 2013
	Derivative assets or (liabilities) not designated as hedging instruments
	Accounts receivable	$	36,224
	Long-term asset derivative instruments	7,992
	Total derivative assets	44,216
	Accounts receivable	(18,761		)	*
	Long-term asset derivative instruments	(2,553		)	*
	Accounts payable	(30,302		)
	Total derivative liabilities	(51,616		)
	Total derivatives not designated	$	(7,400	)
	*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 Statements of Income	Three months			Three months
			ended			ended
			31-Mar-14			31-Mar-13
	Net gain (loss) recognized in other comprehensive income on derivatives (effective portion), net of tax of $1 and ($16,424)	—	$	2		$	(26,798	)
	Gain reclassified from accumulated other comprehensive income into income (effective portion)	Operating revenues	$	4,054		$	17,824
	Loss recognized in income on derivatives (ineffective portion and amount excluded from effectiveness testing)	Operating revenues	$	—		$	(534	)
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 Statements of Income	Three months			Three months
			ended			ended
			31-Mar-14			31-Mar-13
	Loss recognized in income on derivatives	Operating revenues	$	(57,446	)	$	(31,501	)
Schedule of Hedging Transactions	'
	nergen Resources entered into the following transactions for the remainder of 2014 and subsequent years:
	Production Period	Total Hedged Volumes		Average Contract	Description
				Price
	Oil
	2014	7,392	MBbl	$92.65 Bbl	NYMEX Swaps
	2015	7,260	MBbl	$89.07 Bbl	NYMEX Swaps
	Natural Gas
	2014	7.9	Bcf	$4.55 Mcf	NYMEX Swaps
	2014	23.5	Bcf	$4.60 Mcf	Basin Specific Swaps - San Juan
	2014	7.4	Bcf	$3.81 Mcf	Basin Specific Swaps - Permian
	2015	12	Bcf	$4.05 Mcf	Basin Specific Swaps - San Juan
	Natural Gas Basis Differential
	2014	4.6	Bcf	$(0.09) Mcf	San Juan Basis Swaps
	2014	1.5	Bcf	$(0.17) Mcf	Permian Basis Swaps
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:
		March 31, 2014
	(in thousands)	Level 2*			Level 3*			Total
	Current assets	$	(6,646	)	$	10,003		$	3,357
	Noncurrent assets	1,192			1,446			2,638
	Current liabilities	(42,531		)	(10,071		)	(52,602		)
	Noncurrent liabilities	(802		)	—			(802		)
	Net derivative asset (liability)	$	(48,787	)	$	1,378		$	(47,409	)
		31-Dec-13
	(in thousands)	Level 2*			Level 3*			Total
	Current assets	$	(1,658	)	$	19,121		$	17,463
	Noncurrent assets	4,383			1,056			5,439
	Current liabilities	(28,414		)	(1,888		)	(30,302		)
	Net derivative asset (liability)	$	(25,689	)	$	18,289		$	(7,400	)
	*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)	March 31, 2014			March 31, 2013
	Balance at beginning of period	$	18,289		$	89,019
	Realized gains (losses)	(3,019		)	27,107
	Unrealized losses relating to instruments held at the reporting date*	(16,835		)	(63,482		)
	Settlements during period	2,943			(26,185		)
	Balance at end of period	$	1,378		$	26,459
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 March 31, 2014			Valuation Technique*	Unobservable Input*	Range
	Natural Gas Basis - San Juan
	2014	$	5,326		Discounted Cash Flow	Forward Basis	($0.06 - $0.09) Mcf
	2015	$	(129	)	Discounted Cash Flow	Forward Basis	($0.14) Mcf
	Natural Gas Basis - Permian
	2014	$	(3,819	)	Discounted Cash Flow	Forward Basis	($0.12 - $0.13) Mcf
	*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:
		March 31, 2014
											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	$	22,511		$	(16,516	)	$	5,995		$	—	$	—	$	5,995
	Derivative liabilities	$	69,920		$	(16,516	)	$	53,404		$	—	$	—	$	53,404
		December 31, 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	$	44,215		$	(21,313	)	$	22,902		$	—	$	—	$	22,902
	Derivative liabilities	$	51,615		$	(21,313	)	$	30,302		$	—	$	—	$	30,302

Reconciliation_of_Earnings_Per1

Reconciliation of Earnings Per Share (EPS) (Tables)	3 Months Ended
	Mar. 31, 2014
Earnings Per Share [Abstract]	'
Schedule of Earnings Per Share Reconciliation	'
		Three months ended						Three months ended
	(in thousands, except per share amounts)	March 31, 2014						March 31, 2013
		Net				Per Share		Net			Per Share
		Income			Shares	Amount		Income		Shares	Amount
	Basic EPS	$	53,316		72,629	$	0.73	$	56,692	72,143	$	0.79
	Effect of dilutive securities
	Stock options				296					144
	Non-vested restricted stock				44					1
	Performance share awards				76					—
	Diluted EPS	$	53,316		73,045	$	0.73	$	56,692	72,288	$	0.78
Schedule of Antidilutive Securities Excluded from Computation of Earnings Per Share	'
	The Company had the following shares that were excluded from the computation of diluted EPS, as their effect was non-dilutive:
		Three months ended
		March 31,
	(in thousands)	2014		2013
	Stock options	111,554		988,087
	Performance share awards	68,250		161,249

Segment_Information_Tables

Segment Information (Tables)	3 Months Ended
	Mar. 31, 2014
Segment Reporting [Abstract]	'
Schedule of Segment Reporting Information, by Segment	'
		Three months ended
		March 31,
	(in thousands)	2014			2013
	Operating revenues from continuing operations
	Oil and gas operations	$	297,278		$	236,331
	Natural gas distribution	263,900			237,685
	Total	$	561,178		$	474,016
	Operating income (loss) from continuing operations
	Oil and gas operations	$	33,548		$	23,181
	Natural gas distribution	72,351			79,293
	Eliminations and corporate expenses	(1,300		)	(284		)
	Total	$	104,599		$	102,190
	Other income (expense) from continuing operations
	Oil and gas operations	$	(13,819	)	$	(12,031	)
	Natural gas distribution	(2,839		)	(3,130		)
	Eliminations and other	348			74
	Total	$	(16,310	)	$	(15,087	)
	Income from continuing operations before income taxes	$	88,289		$	87,103
	(in thousands)	March 31, 2014			31-Dec-13
	Identifiable assets
	Oil and gas operations	$	5,521,883		$	5,379,135
	Natural gas distribution	1,209,375			1,193,413
	Eliminations and other	49,132			49,664
	Total	$	6,780,390		$	6,622,212

Employee_Benefit_Plans_Tables

Employee Benefit Plans (Tables)	3 Months Ended
	Mar. 31, 2014
Pension Plans	'
Defined Benefit Plan Disclosure	'
Schedule of Net Benefit Costs	'
	The components of net periodic benefit cost for the Company’s two defined benefit non-contributory pension plans and certain non-qualified supplemental pension plans were as follows:
		Three months ended
		March 31,
	(in thousands)	2014			2013
	Components of net periodic benefit cost:
	Service cost	$	3,003		$	3,602
	Interest cost	2,575			2,718
	Expected long-term return on assets	(2,848		)	(3,713		)
	Actuarial loss amortization	2,256			3,690
	Prior service cost amortization	118			122
	Settlement charge	7,262			144
	Net periodic expense	$	12,366		$	6,563
Postretirement Benefit Plans	'
Defined Benefit Plan Disclosure	'
Schedule of Net Benefit Costs	'
	The components of net periodic benefit cost for the Company’s postretirement benefit plans were as follows:
		Three months ended
		March 31,
	(in thousands)	2014			2013
	Components of net periodic benefit cost:
	Service cost	$	170		$	444
	Interest cost	754			869
	Expected long-term return on assets	(1,412		)	(1,242		)
	Actuarial gain amortization	(520		)	—
	Transition obligation amortization	27			324
	Net periodic (income) expense	$	(981	)	$	395

Financial_Instruments_Tables

Financial Instruments (Tables)	3 Months Ended
	Mar. 31, 2014
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, 2013	$	423
	Provision	(124		)
	Allowance for credit losses as of March 31, 2014	$	299

Exploratory_Costs_Tables

Exploratory Costs (Tables)	3 Months Ended
	Mar. 31, 2014
Extractive Industries [Abstract]	'
Schedule of Capitalized Exploratory Wells	'
	The following table sets forth capitalized exploratory well costs and includes additions pending determination of proved reserves, reclassifications to proved reserves and costs charged to expense:
		Three months ended			Three months ended
	(in thousands)	31-Mar-14			31-Mar-13
	Capitalized exploratory well costs at beginning of period	$	57,600		$	79,791
	Additions pending determination of proved reserves	164,842			95,861
	Reclassifications due to determination of proved reserves	(112,474		)	(69,477		)
	Capitalized exploratory well costs at end of period	$	109,968		$	106,175
	The following table sets forth capitalized exploratory wells costs and includes amounts capitalized for a period greater than one year:
		Three months ended			Three months ended
	(in thousands)	March 31, 2014			31-Mar-13
	Exploratory wells in progress	$	62,280		$	21,676
	Capitalized exploratory well costs capitalized for a period of one year or less	46,460			83,301
	Capitalized exploratory well costs for a period greater than one year	1,228			1,198
	Total capitalized exploratory well costs	$	109,968		$	106,175

Regulatory_Assets_and_Liabilit1

Regulatory Assets and Liabilities (Tables) (Alabama Gas Corporation)	3 Months Ended
	Mar. 31, 2014
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)	March 31, 2014				December 31, 2013
		Current		Noncurrent		Current		Noncurrent
	Regulatory assets:
	Pension assets	$	1,258	$	56,133	$	325	$	58,243
	Accretion and depreciation of asset retirement obligations	—		18,436		—		18,046
	Rate recovery of asset removal costs, net	—		4,001		—		4,601
	Enhanced stability reserve	—		4,000		—		4,000
	Gas supply adjustment	—		—		2,406		—
	Other	25		—		25		—
	Total regulatory assets	$	1,283	$	82,570	$	2,756	$	84,890
	Regulatory liabilities:
	RSE adjustment	$	16,193	$	—	$	4,690	$	—
	Unbilled service margin	28,251		—		28,504		—
	Postretirement liabilities	—		25,826		—		26,197
	Gas supply adjustment	23,782		—		—		—
	Refundable negative salvage	12,439		28,846		15,779		39,663
	Asset retirement obligation	—		27,840		—		27,528
	Other	33		728		33		737
	Total regulatory liabilities	$	80,698	$	83,240	$	49,006	$	94,125

Asset_Retirement_Obligations_T

Asset Retirement Obligations (Tables)	3 Months Ended
	Mar. 31, 2014
Asset Retirement Obligation Disclosure [Abstract]	'
Schedule of Change in Asset Retirement Obligation	'
	During the three months ended March 31, 2014, 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, 2013	$	108,533
	Liabilities incurred	766
	Liabilities settled	(413		)
	Accretion expense	1,843
	Balance as of March 31, 2014	$	110,729

Accumulated_Other_Comprehensiv1

Accumulated Other Comprehensive Income (Loss) (Tables)	3 Months Ended
	Mar. 31, 2014
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, 2013	$	12,178		$	(32,245	)	$	(20,067	)
	Other comprehensive loss before reclassifications	(113		)	—			(113		)
	Amounts reclassified from accumulated other comprehensive income (loss)	(2,224		)	5,613			3,389
	Change in accumulated other comprehensive income (loss)	(2,337		)	5,613			3,276
	Balance as of March 31, 2014	$	9,841		$	(26,632	)	$	(16,791	)
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			Three months ended
		31-Mar-14			31-Mar-13
	(in thousands)	Amounts Reclassified						Line Item Where Presented
	Gains and (losses) on cash flow hedges:
	Derivative commodity instruments	$	4,054		$	17,290		Operating revenues
	Interest rate swap	(446		)	(409		)	Interest expense
	Total cash flow hedges	3,608			16,881
	Income tax expense	(1,384		)	(6,427		)
	Net of tax	2,224			10,454
	Pension and postretirement plans:
	Transition obligation	(10		)	(74		)	Operations and maintenance
	Prior service cost	(74		)	(78		)	Operations and maintenance
	Actuarial losses*	(1,290		)	(2,254		)	Operations and maintenance
	Actuarial losses on settlement charges	(7,262		)	—			Operations and maintenance
	Actuarial losses on settlement charges*	—			(375		)	Regulatory asset
	Total pension and postretirement plans	(8,636		)	(2,781		)
	Income tax benefit	3,023			973
	Net of tax	(5,613		)	(1,808		)
	Total reclassifications for the period	$	(3,389	)	$	8,646
	*In the first quarter of 2013, the Company incurred a settlement charge of $0.5 million for the payment of lump sums from the non-qualified supplemental retirement plans, of which $0.1 million is recognized in actuarial gains (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)	3 Months Ended
	Mar. 31, 2014
Discontinued Operations and Disposal Groups [Abstract]	'
Schedule of Disposal Groups, Including Discontinued Operations, Income Statement, Balance Sheet and Additional Disclosures	'
		Three months ended
		March 31,
	(in thousands, except per share data)	2014			2013
	Oil and gas revenues	$	4,821		$	18,663
	Pretax income (loss) from discontinued operations	$	(2,078	)	$	3,168
	Income tax expense (benefit)	(952		)	1,170
	Income (Loss) From Discontinued Operations	$	(1,126	)	$	1,998
	Loss on disposal of discontinued operations	$	(1,667	)	$	—
	Income tax benefit	(617		)	—
	Loss on Disposal of Discontinued Operations	$	(1,050	)	$	—
	Total Income (Loss) From Discontinued Operations	$	(2,176	)	$	1,998
	Diluted Earnings Per Average Common Share
	Income (Loss) from Discontinued Operations	$	(0.02	)	$	0.03
	Loss on Disposal of Discontinued Operations	(0.01		)	—
	Total Income (Loss) From Discontinued Operations	$	(0.03	)	$	0.03
	Basic Earnings Per Average Common Share
	Income (Loss) from Discontinued Operations	$	(0.02	)	$	0.03
	Loss on Disposal of Discontinued Operations	(0.01		)	—
	Total Income (Loss) From Discontinued Operations	$	(0.03	)	$	0.03
	The following table details held-for-sale properties by major classes of assets and liabilities:
	(in thousands)	31-Mar-14
		Black Warrior Basin			North Louisiana/East Texas			Total
	Accounts receivable	$	—		$	1,670		$	1,670
	Inventories	—			68			68
	Other property, net	—			133			133
	Total assets held-for-sale	—			1,871			1,871
	Accounts payable	(2,172		)	(10		)	(2,182		)
	Royalty payable	—			(1,221		)	(1,221		)
	Other current liabilities	—			(7		)	(7		)
	Total liabilities held-for-sale	(2,172		)	(1,238		)	(3,410		)
	Total net held-for-sale properties	$	(2,172	)	$	633		$	(1,539	)

Regulatory_Matters_Details

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

0 Months Ended

3 Months Ended

0 Months Ended

12 Months Ended

0 Months Ended

3 Months Ended

12 Months Ended

0 Months Ended

Jan. 02, 2014

Dec. 01, 2013

Dec. 01, 2012

Mar. 31, 2014

Mar. 31, 2013

Mar. 31, 2014

Mar. 31, 2014

Mar. 31, 2014

Mar. 31, 2014

Jan. 02, 2014

Dec. 31, 2013

Jan. 02, 2014

Mar. 31, 2014

Dec. 31, 2013

Jan. 02, 2014

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 Approved Expension of ESR, November 1, 2010

APSC

Minimum

Minimum

Maximum

Maximum

Maximum

Self Insurance Costs

Force Majeure Event Costs

Force Majeure Events Costs

APSC

APSC

Regulatory Matters [Line Items]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Approved return on equity

'

'

'

'

'

'

'

'

'

'

'

10.50%

'

'

10.95%

Adjusting point

'

'

'

'

'

'

'

'

'

10.80%

'

'

'

'

'

Allowed return on average common equity

'

'

'

'

'

'

'

'

'

'

13.15%

'

'

13.65%

'

Performance based adjustment on adjusting point

0.05%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Rate increases as percentage of prior year revenues

'

'

'

'

'

'

'

'

'

'

'

'

4.00%

'

'

Revenue reductions (increase) of rate adjustments

$8,500,000

($10,300,000)

($7,800,000)

$16,200,000

$2,400,000

'

'

'

'

'

'

'

'

'

'

Equity upon which a return will be permitted

56.50%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Approved increase

1.75%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

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

'

'

'

'

'

'

1,000,000

275,000

412,500

'

'

'

'

'

'

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 $)	Mar. 31, 2014		Dec. 31, 2013		Jun. 30, 2013	Mar. 31, 2013
	counterparty				bbl	bbl
Derivative [Line Items]	'		'		'	'
Number of Active Counterparties with Whom Company Holds Net Gain Positions	2		'		'	'
Number of Active Counterparties with Whom Company Holds Net Loss Positions	12		'		'	'
Fair Value as of March 31, 2014	$53,404,000		$30,302,000		'	'
Derivative assets	5,995,000		22,902,000		'	'
Barrels dedesignated	'		'		2,353,000	5,078,000
Gross Amounts Recognized	22,511,000		44,215,000		'	'
Derivative liability	-69,920,000		-51,615,000		'	'
Deferred tax assets (liabilities), net	-6,700,000		-8,200,000		'	'
Not Designated as Hedging Instrument | Oil and gas operations	'		'		'	'
Derivative [Line Items]	'		'		'	'
Gross Amounts Recognized	22,511,000		44,216,000		'	'
Derivative liability	-69,920,000		-51,616,000		'	'
Total derivatives	-47,409,000		-7,400,000		'	'
Accounts receivable | Not Designated as Hedging Instrument | Oil and gas operations	'		'		'	'
Derivative [Line Items]	'		'		'	'
Gross Amounts Recognized	17,522,000		36,224,000		'	'
Derivative liability	-14,165,000	[1]	-18,761,000	[1]	'	'
Long-term asset derivative instruments | Not Designated as Hedging Instrument | Oil and gas operations	'		'		'	'
Derivative [Line Items]	'		'		'	'
Gross Amounts Recognized	4,989,000		7,992,000		'	'
Derivative liability	-2,351,000	[1]	-2,553,000	[1]	'	'
Accounts payable | Not Designated as Hedging Instrument | Oil and gas operations	'		'		'	'
Derivative [Line Items]	'		'		'	'
Derivative liability	-52,602,000		-30,302,000		'	'
Other Liabilities [Member] | Not Designated as Hedging Instrument | Oil and gas operations	'		'		'	'
Derivative [Line Items]	'		'		'	'
Derivative liability	-802,000		'		'	'
Cash Flow Hedging | Macquarie Bank Limited	'		'		'	'
Derivative [Line Items]	'		'		'	'
Derivative assets	$3,000,000		'		'	'
[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_Instrumen3

Derivative Commodity Instruments - Derivative Instruments by Income Statement Location (Details) (USD $)	3 Months Ended
	Mar. 31, 2014	Mar. 31, 2013
Derivative Instruments, Gain (Loss) [Line Items]	'	'
Net gain (loss) recognized in other comprehensive income on derivatives (effective portion), net of tax of $1 and ($16,424)	$2,000	($26,798,000)
Gain (loss) reclassification from AOCI to income estimated net amount to be transferred	10,900,000	'
Operating revenues	561,178,000	474,016,000
Reclassification out of Accumulated Other Comprehensive Income | Accumulated Net Gain from Discontinued Hedge Accounting	'	'
Derivative Instruments, Gain (Loss) [Line Items]	'	'
Operating revenues	2,600,000	'
Fair Value Hedging | Natural Gas | 2014	'	'
Derivative Instruments, Gain (Loss) [Line Items]	'	'
Nonmonetary notional amount	44,900,000	'
Fair Value Hedging | Natural Gas | 2015	'	'
Derivative Instruments, Gain (Loss) [Line Items]	'	'
Nonmonetary notional amount	12,000,000	'
Fair Value Hedging | Crude Oil | 2014	'	'
Derivative Instruments, Gain (Loss) [Line Items]	'	'
Nonmonetary notional amount	7,400,000	'
Fair Value Hedging | Crude Oil | 2015	'	'
Derivative Instruments, Gain (Loss) [Line Items]	'	'
Nonmonetary notional amount	7,300,000	'
Operating revenues	'	'
Derivative Instruments, Gain (Loss) [Line Items]	'	'
Gain reclassified from accumulated other comprehensive income into income (effective portion)	4,054,000	17,824,000
Loss recognized in income on derivatives (ineffective portion and amount excluded from effectiveness testing)	0	-534,000
Gain (loss) recognized in income on derivatives	-57,446,000	-31,501,000
Derivative commodity instruments	'	'
Derivative Instruments, Gain (Loss) [Line Items]	'	'
Current period change in fair value of derivative, tax	$1,000	($16,424,000)

Derivative_Commodity_Instrumen4

Derivative Commodity Instruments - Hedging Transactions (Details)	3 Months Ended
	Mar. 31, 2014
	Mcf
Natural Gas | 2014 | NYMEX Swaps	'
Derivative [Line Items]	'
Total Hedged Volumes	7,900,000
Average Contract Price, per Mcf	4.55
Natural Gas | 2014 | Basin Specific Swaps - San Juan	'
Derivative [Line Items]	'
Total Hedged Volumes	23,500,000
Average Contract Price, per Mcf	4.6
Natural Gas | 2014 | San Juan Basis Swaps	'
Derivative [Line Items]	'
Total Hedged Volumes	4,600,000
Average Contract Price, per Mcf	-0.09
Natural Gas | 2014 | Permian Basis Swaps	'
Derivative [Line Items]	'
Total Hedged Volumes	1,500,000
Average Contract Price, per Mcf	-0.17
Natural Gas | 2014 | Basin Specific Swaps - Permian	'
Derivative [Line Items]	'
Total Hedged Volumes	7,400,000
Average Contract Price, per Mcf	3.81
Natural Gas | 2015 | Basin Specific Swaps - San Juan	'
Derivative [Line Items]	'
Total Hedged Volumes	12,000,000
Average Contract Price, per Mcf	4.05
Crude Oil | 2014 | NYMEX Swaps	'
Derivative [Line Items]	'
Total Hedged Volumes	7,392,000
Average Contract Price, per Bbl	92.65
Crude Oil | 2015 | NYMEX Swaps	'
Derivative [Line Items]	'
Total Hedged Volumes	7,260,000
Average Contract Price, per Bbl	89.07

Derivative_Commodity_Instrumen5

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

Mar. 31, 2014

Dec. 31, 2013

Mar. 31, 2014

Dec. 31, 2013

Mar. 31, 2014

Mar. 31, 2014

Dec. 31, 2013

Mar. 31, 2014

Dec. 31, 2013

Level 2

Level 2

Level 3

Level 3

Level 3

Total

Total

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

'

'

'

'

'

'

'

'

'

Current assets

'

'

($6,646,000)

[1]

($1,658,000)

[1]

'

$10,003,000

[1]

$19,121,000

[1]

$3,357,000

$17,463,000

Noncurrent assets

2,638,000

5,439,000

1,192,000

[1]

4,383,000

[1]

'

1,446,000

[1]

1,056,000

[1]

2,638,000

5,439,000

Current liabilities

'

'

-42,531,000

[1]

-28,414,000

[1]

'

-10,071,000

[1]

-1,888,000

[1]

-52,602,000

-30,302,000

Noncurrent liabilities

-1,011,000

-398,000

-802,000

[1]

'

'

0

[1]

'

-802,000

'

Net derivative asset (liability)

'

'

-48,787,000

[1]

-25,689,000

[1]

'

1,378,000

[1]

18,289,000

[1]

-47,409,000

-7,400,000

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

'

'

'

'

18,000,000

'

'

'

'

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

'

'

'

'

$18,000,000

'

'

'

'

[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
	Mar. 31, 2014		Mar. 31, 2013
Derivative Commodity Instruments	'		'
Fair Value, Assets and Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]	'		'
Balance at beginning of period	$18,289,000		$89,019,000
Realized gains (losses)	-3,019,000		27,107,000
Unrealized losses relating to instruments held at the reporting date	-16,835,000	[1]	-63,482,000	[1]
Settlements during period	2,943,000		-26,185,000
Balance at end of period	1,378,000		26,459,000
Mark-to-market gain included in earnings, unrealized	$13,200,000		$12,400,000
[1]	Includes $13.2 million and $12.4 million in mark-to-market losses for the three months ended March 31, 2014 and 2013, respectively.

Derivative_Commodity_Instrumen7

Derivative Commodity Instruments - Quantitative Disclosures About Fair Value (Details) (USD $)	Mar. 31, 2014	Dec. 31, 2013	Mar. 31, 2014	Mar. 31, 2014	Mar. 31, 2014	Mar. 31, 2014	Mar. 31, 2014	Mar. 31, 2014	Mar. 31, 2014
In Thousands, unless otherwise specified			Discounted Cash Flow	Discounted Cash Flow	Discounted Cash Flow	Discounted Cash Flow	Discounted Cash Flow	Discounted Cash Flow	Discounted Cash Flow
			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 - Permian	Natural Gas Basis - Permian	Natural Gas Basis - Permian
			2014	2014	2014	2015	2014	2014	2014
				Minimum	Maximum			Minimum	Maximum
Fair Value Inputs, Derivatives, Quantitative Information [Line Items]	'	'	'	'	'	'	'	'	'
Fair Value as of March 31, 2014	$5,995	$22,902	$5,326	'	'	($129)	($3,819)	'	'
Fair Value as of March 31, 2014	($53,404)	($30,302)	'	'	'	'	'	'	'
Fair Value Inputs, Price Per Cubic Foot	'	'	'	0.06	0.09	0.14	'	0.12	0.13

Derivative_Commodity_Instrumen8

Derivative Commodity Instruments - Offsetting Assets and Liabilities (Details) (USD $)	Mar. 31, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified
Derivative assets	'	'
Gross Amounts Recognized	$22,511	$44,215
Gross Amounts Offset in the Balance Sheets	-16,516	-21,313
Net Amount Presented in the Balance Sheets	5,995	22,902
Financial Instruments	0	0
Cash Collateral Received	0	0
Net Amount	5,995	22,902
Derivative assets	'	'
Gross Amounts Recognized	69,920	51,615
Gross Amounts Offset in the Balance Sheets	-16,516	-21,313
Net Amount Presented in the Balance Sheets	53,404	30,302
Financial Instruments	0	0
Cash Collateral Received	0	0
Net Amount	$53,404	$30,302

Reconciliation_of_Earnings_Per2

Reconciliation of Earnings Per Share (EPS) - Earnings Per Share Reconciliation (Details) (USD $)	3 Months Ended
In Thousands, except Per Share data, unless otherwise specified	Mar. 31, 2014	Mar. 31, 2013
Earnings Per Share Reconciliation	'	'
Net Income, Basic EPS	$53,316	$56,692
Basic Shares Outstanding (in shares)	72,629	72,143
Earnings Per Share, Basic (in dollars per share)	$0.73	$0.79
Effect of dilutive securities	'	'
Net Income, Diluted EPS	$53,316	$56,692
Diluted Shares Outstanding (in shares)	73,045	72,288
Earnings Per Share, Diluted (dollars per share)	$0.73	$0.78
Stock options	'	'
Effect of dilutive securities	'	'
Incremental common shares attributable to share-based payment arrangements	296	144
Non-vested restricted stock	'	'
Effect of dilutive securities	'	'
Incremental common shares attributable to share-based payment arrangements	44	1
Performance share awards	'	'
Effect of dilutive securities	'	'
Incremental common shares attributable to share-based payment arrangements	0	0

Reconciliation_of_Earnings_Per3

Reconciliation of Earnings Per Share (EPS) - Antidilutive Securities (Details)	3 Months Ended
	Mar. 31, 2014	Mar. 31, 2013
Stock options	'	'
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]	'	'
Antidilutive securities excluded from computation of earnings per share, amount	111,554	988,087
Performance share awards	'	'
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]	'	'
Antidilutive securities excluded from computation of earnings per share, amount	68,250	161,249

Segment_Information_Details

Segment Information (Details) (USD $)	3 Months Ended
In Thousands, unless otherwise specified	Mar. 31, 2014	Mar. 31, 2013	Dec. 31, 2013
	segment
Segment Reporting Information	'	'	'
Number of business segments	2	'	'
Segment Reporting Information, Profit (Loss)	'	'	'
Operating revenues from continuing operations	$561,178	$474,016	'
Operating income (loss) from continuing operations	104,599	102,190	'
Other income (expense) from continuing operations	-16,310	-15,087	'
Income From Continuing Operations Before Income Taxes	88,289	87,103	'
Identifiable assets	6,780,390	'	6,622,212
Oil and gas operations	'	'	'
Segment Reporting Information, Profit (Loss)	'	'	'
Operating revenues from continuing operations	297,278	236,331	'
Operating income (loss) from continuing operations	33,548	23,181	'
Other income (expense) from continuing operations	-13,819	-12,031	'
Identifiable assets	5,521,883	'	5,379,135
Natural gas distribution	'	'	'
Segment Reporting Information, Profit (Loss)	'	'	'
Operating revenues from continuing operations	263,900	237,685	'
Operating income (loss) from continuing operations	72,351	79,293	'
Other income (expense) from continuing operations	-2,839	-3,130	'
Identifiable assets	1,209,375	'	1,193,413
Eliminations and corporate expenses	'	'	'
Segment Reporting Information, Profit (Loss)	'	'	'
Operating income (loss) from continuing operations	-1,300	-284	'
Other income (expense) from continuing operations	348	74	'
Identifiable assets	$49,132	'	$49,664

Stock_Compensation_Details

Stock Compensation (Details) (USD $)	3 Months Ended	1 Months Ended	3 Months Ended
In Millions, except Share data, unless otherwise specified	Mar. 31, 2014	Jan. 31, 2014	Mar. 31, 2014	Mar. 31, 2014	Mar. 31, 2013	Mar. 31, 2014	Mar. 31, 2014	Mar. 31, 2014	Mar. 31, 2014	Mar. 31, 2014
	Stock options	Restricted Stock Units (RSUs)	Restricted Stock Units (RSUs)	Restricted Stock Units (RSUs)	Restricted Stock Units (RSUs)	Performance share awards	Performance share awards	Performance share awards	Stock Appreciation Rights (SARs)	Deferred Compensation
				Petrotech Incentive Plan	Petrotech Incentive Plan	2 year vesting period	3 year vesting period	Petrotech Incentive Plan
								3 year 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	'
Expiration period	'10 years	'	'	'	'	'	'	'	'	'
Grants in period, options	107,868	'	'	'	'	'	'	'	'	'
Grants in period, options, fair value	$27.57	'	'	'	'	'	'	'	'	'
Grants in period (in shares)	'	41,664	'	'	28,840	287	63,842	36,920	62,749	'
Grants in period, fair value (in dollars per share)	'	$70.68	'	$79.18	'	$118.99	$93.13	$115.94	$35.04	'
Noncash payments for repurchase of common stock	'	'	'	'	'	'	'	'	'	$0.30

Employee_Benefit_Plans_Details

Employee Benefit Plans (Details) (USD $)	1 Months Ended	3 Months Ended
	Jan. 31, 2013	Mar. 31, 2014	Mar. 31, 2013
Defined Benefit Plan Disclosure	'	'	'
Number of defined benefit non-contributory pension plans and certain nonqualified supplemental pension plans	'	2	'
Pension Plans	'	'	'
Components of net periodic benefit cost:	'	'	'
Service cost	'	$3,003,000	$3,602,000
Interest cost	'	2,575,000	2,718,000
Expected long-term return on assets	'	-2,848,000	-3,713,000
Actuarial loss amortization	'	2,256,000	3,690,000
Prior service cost amortization	'	118,000	122,000
Settlement charge	'	7,262,000	144,000
Net periodic expense	'	12,366,000	6,563,000
Estimated required future employer contributions in current fiscal year	'	500,000	'
Contributions by employer in current fiscal year	3,000,000	'	'
Benefit payments made in current fiscal year	'	33,000	'
Estimated future benefit payments in current fiscal year	'	200,000	'
Settlement charges	'	17,100,000	'
Settlement charges expensed	'	6,900,000	'
Postretirement Benefit Plans	'	'	'
Components of net periodic benefit cost:	'	'	'
Service cost	'	170,000	444,000
Interest cost	'	754,000	869,000
Expected long-term return on assets	'	-1,412,000	-1,242,000
Actuarial loss amortization	'	-520,000	0
Transition obligation amortization	'	27,000	324,000
Net periodic expense	'	-981,000	395,000
Non-Qualified Supplemental Retirement Plans	'	'	'
Components of net periodic benefit cost:	'	'	'
Settlement charges	'	400,000	500,000
Settlement charges expensed	'	'	100,000
Alabama Gas Corporation | Pension Plans	'	'	'
Components of net periodic benefit cost:	'	'	'
Settlements recognized as a pension asset	'	10,200,000	'
Alabama Gas Corporation | Non-Qualified Supplemental Retirement Plans	'	'	'
Components of net periodic benefit cost:	'	'	'
Settlements recognized as a pension asset	'	'	$400,000

Commitments_and_Contingencies_

Commitments and Contingencies - Commitments and Agreements (Details) (USD $)	1 Months Ended				3 Months Ended
In Millions, unless otherwise specified	Sep. 30, 2013	Mar. 31, 2014	Mar. 31, 2014	Mar. 31, 2014	Mar. 31, 2014	Mar. 31, 2013	Mar. 31, 2014
	Alabama Gas Corporation	Alabama Gas Corporation	Alabama Gas Corporation	Crude Oil and Natural Gas	Natural Gas, Delivery and Storage	Natural Gas, Delivery and Storage	Natural Gas
	site	site	Wholly Owned Properties	MBoe	Alabama Gas Corporation	Alabama Gas Corporation	Alabama Gas Corporation
			site				Mcf
Long-term Purchase Commitment [Line Items]	'	'	'	'	'	'	'
Remaining contractual volume	'	'	'	6,400	'	'	'
Long-term purchase commitment	'	'	'	'	$150	'	'
Long-term purchase commitment, time period	'	'	'	'	'September 2024	'	'August 2020
Long-term commitments expense recognized in statement of operations	'	'	'	'	13.4	14.4	'
Long-term purchase commitment minimum quantity required	'	'	'	'	'	'	123,000,000
Recorded unconditional purchase obligation, time period	'	'	'	'	'	'	'December 2014
Recorded unconditional purchase obligation	'	'	'	'	'	'	$0.30
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 $)	3 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2014
	pit
Mitchell County, Texas	'
Environmental Exit Cost [Line Items]	'
Number of sites	9
Anticipated cost	$2.10
Costs incurred	1.9
Accrual for environmental loss contingencies	$0.20

Commitments_and_Contingencies_2

Commitments and Contingencies - New Mexico Audits (Details) (USD $)	3 Months Ended
	Mar. 31, 2014
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

Mar. 31, 2014

Mar. 31, 2014

Mar. 31, 2014

Mar. 31, 2014

Dec. 31, 2013

Mar. 31, 2014

Mar. 31, 2014

Dec. 31, 2013

Mar. 31, 2014

Dec. 31, 2013

Mar. 31, 2014

Dec. 31, 2013

Mar. 31, 2014

Dec. 31, 2013

Mar. 31, 2014

Dec. 31, 2013

Maximum

Senior Loans

Senior Loans

Senior Loans

Senior Loans

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

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

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

Swap

Swap

Swap

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

Alabama Gas Corporation

Alabama Gas Corporation

Alabama Gas Corporation

Alabama Gas Corporation

Level 2

Level 2

Swap

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

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Long-term debt fair value

'

'

'

'

'

'

'

'

$1,421,200,000

$1,420,700,000

$263,500,000

$258,800,000

$1,388,900,000

$1,403,900,000

$249,900,000

$249,900,000

Face amount

'

'

'

'

'

200,000,000

'

'

'

'

'

'

'

'

'

'

Interest rate

'

'

2.67%

'

'

'

'

'

'

'

'

'

'

'

'

'

Interest rate cash flow hedge liability at fair value

'

'

'

1,600,000

1,800,000

'

'

'

'

'

'

'

'

'

'

'

Financing receivable

'

'

'

'

'

'

10,500,000

10,800,000

'

'

'

'

'

'

'

'

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

'

'

'

'

'

'

300,000

400,000

'

'

'

'

'

'

'

'

Financing Receivable, Allowance for Credit Losses [Roll Forward]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Allowance for credit losses as of December 31, 2013

423,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Provision

-124,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Allowance for credit losses as of March 31, 2014

$299,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Exploratory_Costs_Details

Exploratory Costs (Details) (USD $)	3 Months Ended
In Thousands, unless otherwise specified	Mar. 31, 2014	Mar. 31, 2013
	well
Increase (Decrease) in Capitalized Exploratory Well Costs that are Pending Determination of Proved Reserves [Roll Forward]	'	'
Capitalized exploratory well costs at beginning of period	$57,600	$79,791
Additions pending determination of proved reserves	164,842	95,861
Reclassifications due to determination of proved reserves	-112,474	-69,477
Capitalized exploratory well costs at end of period	109,968	106,175
Exploratory wells in progress	62,280	21,676
Capitalized exploratory well costs capitalized for a period of one year or less	46,460	83,301
Capitalized exploratory well costs for a period greater than one year	1,228	1,198
Total capitalized exploratory well costs	$109,968	$106,175
Wells in process of drilling	45	'
Wells capitalized greater than one year pending results from completion and testing	1	'

Regulatory_Assets_and_Liabilit2

Regulatory Assets and Liabilities (Details) (USD $)	Mar. 31, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified
Regulatory Assets and Liabilities [Line Items]	'	'
Regulatory Assets, Current	$1,283	$2,756
Regulatory assets, noncurrent	82,570	84,890
Regulatory Liability, Current	80,698	49,006
Regulatory Liability, Noncurrent	83,240	94,125
Alabama Gas Corporation	'	'
Regulatory Assets and Liabilities [Line Items]	'	'
Regulatory Assets, Current	1,283	2,756
Regulatory assets, noncurrent	82,570	84,890
Regulatory Liability, Current	80,698	49,006
Regulatory Liability, Noncurrent	83,240	94,125
Alabama Gas Corporation | RSE adjustment	'	'
Regulatory Assets and Liabilities [Line Items]	'	'
Regulatory Liability, Current	16,193	4,690
Regulatory Liability, Noncurrent	0	0
Alabama Gas Corporation | Unbilled service margin	'	'
Regulatory Assets and Liabilities [Line Items]	'	'
Regulatory Liability, Current	28,251	28,504
Regulatory Liability, Noncurrent	0	0
Alabama Gas Corporation | Postretirement liabilities	'	'
Regulatory Assets and Liabilities [Line Items]	'	'
Regulatory Liability, Current	0	0
Regulatory Liability, Noncurrent	25,826	26,197
Alabama Gas Corporation | Gas supply adjustment	'	'
Regulatory Assets and Liabilities [Line Items]	'	'
Regulatory Liability, Current	23,782	0
Regulatory Liability, Noncurrent	0	0
Alabama Gas Corporation | Refundable negative salvage	'	'
Regulatory Assets and Liabilities [Line Items]	'	'
Regulatory Liability, Current	12,439	15,779
Regulatory Liability, Noncurrent	28,846	39,663
Alabama Gas Corporation | Accretion and depreciation of asset retirement obligations	'	'
Regulatory Assets and Liabilities [Line Items]	'	'
Regulatory Liability, Current	0	0
Regulatory Liability, Noncurrent	27,840	27,528
Alabama Gas Corporation | Other	'	'
Regulatory Assets and Liabilities [Line Items]	'	'
Regulatory Liability, Current	33	33
Regulatory Liability, Noncurrent	728	737
Alabama Gas Corporation | Pension assets	'	'
Regulatory Assets and Liabilities [Line Items]	'	'
Regulatory Assets, Current	1,258	325
Regulatory assets, noncurrent	56,133	58,243
Alabama Gas Corporation | Accretion and depreciation of asset retirement obligations	'	'
Regulatory Assets and Liabilities [Line Items]	'	'
Regulatory Assets, Current	0	0
Regulatory assets, noncurrent	18,436	18,046
Alabama Gas Corporation | Rate recovery of asset removal costs, net	'	'
Regulatory Assets and Liabilities [Line Items]	'	'
Regulatory Assets, Current	0	0
Regulatory assets, noncurrent	4,001	4,601
Alabama Gas Corporation | Enhanced stability reserve	'	'
Regulatory Assets and Liabilities [Line Items]	'	'
Regulatory Assets, Current	0	0
Regulatory assets, noncurrent	4,000	4,000
Alabama Gas Corporation | Gas supply adjustment	'	'
Regulatory Assets and Liabilities [Line Items]	'	'
Regulatory Assets, Current	0	2,406
Regulatory assets, noncurrent	0	0
Alabama Gas Corporation | Other	'	'
Regulatory Assets and Liabilities [Line Items]	'	'
Regulatory Assets, Current	25	25
Regulatory assets, noncurrent	$0	$0

Asset_Retirement_Obligations_D

Asset Retirement Obligations (Details) (USD $)	3 Months Ended
In Thousands, unless otherwise specified	Mar. 31, 2014	Mar. 31, 2013	Dec. 31, 2013
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]	'	'	'
Balance as of December 31, 2013	$108,533	'	'
Liabilities incurred	766	'	'
Liabilities settled	-413	'	'
Accretion expense	1,843	1,687	'
Balance as of March 31, 2014	110,729	'	'
Regulatory assets, noncurrent	82,570	'	84,890
Alabama Gas Corporation	'	'	'
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]	'	'	'
Balance as of December 31, 2013	'	'	27,500
Balance as of March 31, 2014	27,800	'	27,500
Regulatory assets, noncurrent	82,570	'	84,890
Alabama Gas Corporation | Asset removal costs	'	'	'
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]	'	'	'
Regulatory assets, noncurrent	$4,001	'	$4,601

Acquisition_and_Dispositions_o1

Acquisition and Dispositions of Properties (Details) (USD $)	3 Months Ended		12 Months Ended	3 Months Ended		1 Months Ended	3 Months Ended
	Mar. 31, 2014	Mar. 31, 2013	Dec. 31, 2013	Mar. 31, 2014	Mar. 31, 2013	Aug. 31, 2013	Mar. 31, 2014
				Alabama Gas Corporation	Alabama Gas Corporation	Birmingham Metro Operations Center	Birmingham Metro Operations Center
						Alabama Gas Corporation	Alabama Gas Corporation
Gas and Oil Acreage [Line Items]	'	'	'	'	'	'	'
Gain on disposition of property, plant and equipment	'	'	'	$612,000	$0	$10,900,000	'
Sales price	'	'	'	'	'	'	13,800,000
Lease back period after sale	'	'	'	'	'	'	'20 months
Acquisitions, net of cash acquired	$6,537,000	$13,146,000	$31,300,000	'	'	'	'

Rollforward_of_Accumulated_Oth

Rollforward of Accumulated Other Comprehensive Income (Loss) (Details) (USD $)	3 Months Ended
In Thousands, unless otherwise specified	Mar. 31, 2014
Accumulated Other Comprehensive Income (Loss) [Roll Forward]	'
Balance as of December 31, 2013	($20,067)
Other comprehensive loss before reclassifications	-113
Amounts reclassified from accumulated other comprehensive income (loss)	3,389
Change in accumulated other comprehensive income (loss)	3,276
Balance as of March 31, 2014	-16,791
Cash Flow Hedges	'
Accumulated Other Comprehensive Income (Loss) [Roll Forward]	'
Balance as of December 31, 2013	12,178
Other comprehensive loss before reclassifications	-113
Amounts reclassified from accumulated other comprehensive income (loss)	-2,224
Change in accumulated other comprehensive income (loss)	-2,337
Balance as of March 31, 2014	9,841
Pension and Postretirement Plans	'
Accumulated Other Comprehensive Income (Loss) [Roll Forward]	'
Balance as of December 31, 2013	-32,245
Other comprehensive loss before reclassifications	0
Amounts reclassified from accumulated other comprehensive income (loss)	5,613
Change in accumulated other comprehensive income (loss)	5,613
Balance as of March 31, 2014	($26,632)

Reclassifications_of_Accumulat

Reclassifications of Accumulated Other Comprehensive Income (Details) (USD $)	3 Months Ended
	Mar. 31, 2014		Mar. 31, 2013
Gains and (losses) on cash flow hedges:	'		'
Operating revenues from continuing operations	$561,178,000		$474,016,000
Interest expense	-17,640,000		-16,752,000
Income tax expense	-32,797,000		-32,409,000
Alabama Gas Corporation	'		'
Gains and (losses) on cash flow hedges:	'		'
Interest expense	-3,965,000		-4,030,000
Non-Qualified Supplemental Retirement Plans	'		'
Pension and postretirement plans:	'		'
Settlement charges	400,000		500,000
Settlement charges expensed	'		100,000
Non-Qualified Supplemental Retirement Plans | Alabama Gas Corporation	'		'
Pension and postretirement plans:	'		'
Settlements recognized as a pension asset	'		400,000
Reclassification out of Accumulated Other Comprehensive Income	'		'
Gains and (losses) on cash flow hedges:	'		'
Net of tax	-3,389,000		8,646,000
Cash Flow Hedges | Reclassification out of Accumulated Other Comprehensive Income	'		'
Gains and (losses) on cash flow hedges:	'		'
Total	3,608,000		16,881,000
Income tax expense	-1,384,000		-6,427,000
Net of tax	2,224,000		10,454,000
Pension and Postretirement Plans | Reclassification out of Accumulated Other Comprehensive Income	'		'
Gains and (losses) on cash flow hedges:	'		'
Total	-8,636,000		-2,781,000
Income tax expense	3,023,000		973,000
Net of tax	-5,613,000		-1,808,000
Pension and postretirement plans:	'		'
Transition obligation	-10,000		-74,000
Prior service cost	-74,000		-78,000
Actuarial losses	-1,290,000	[1]	-2,254,000	[1]
Actuarial losses on settlement charges	-7,262,000		0
Actuarial losses on settlement charges	0	[1]	-375,000	[1]
Derivative commodity instruments | Cash Flow Hedges | Reclassification out of Accumulated Other Comprehensive Income	'		'
Gains and (losses) on cash flow hedges:	'		'
Operating revenues from continuing operations	4,054,000		17,290,000
Interest rate swap | Cash Flow Hedges | Reclassification out of Accumulated Other Comprehensive Income	'		'
Gains and (losses) on cash flow hedges:	'		'
Interest expense	($446,000)		($409,000)
[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 non-qualified supplemental retirement plans, of which $0.1 million is recognized in actuarial gains (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 $)	1 Months Ended		3 Months Ended
In Millions, unless otherwise specified	Oct. 31, 2013	Dec. 31, 2013	Mar. 31, 2014	Dec. 31, 2013	Sep. 30, 2013	Jan. 31, 2014	Dec. 31, 2013	Dec. 31, 2013
	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	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
	Alabama	Alabama					Natural Gas	Oil
		Natural Gas					Mcf	bbl
		Mcf
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	'	'	'	'	'	'	'
Gain on disposition of oil and gas property	35	'	'	'	'	'	'	'
Proved Developed Reserves (Volume)	'	97,000,000	'	'	'	'	23,000,000	91,000
Sales price	'	'	'	'	'	30.3	'	'
Impairment of oil and gas properties held-for-sale	'	'	$1.70	$5.20	$24.60	'	'	'

Discontinued_Operations_Balanc

Discontinued Operations Balance Sheet and Income Statement (Details) (USD $)	3 Months Ended
In Thousands, except Per Share data, unless otherwise specified	Mar. 31, 2014	Mar. 31, 2013
Assets of Disposal Group, Including Discontinued Operation [Abstract]	'	'
Accounts receivable	$1,670	'
Inventories	68	'
Other property, net	133	'
Total assets held-for-sale	1,871	'
Liabilities of Disposal Group, Including Discontinued Operation [Abstract]	'	'
Accounts payable	-2,182	'
Royalty payable	-1,221	'
Other current liabilities	-7	'
Total liabilities held-for-sale	-3,410	'
Total net held-for-sale properties	-1,539	'
Disposal Group, Including Discontinued Operation, Income Statement Disclosures [Abstract]	'	'
Oil and gas revenues	4,821	18,663
Pretax income (loss) from discontinued operations	-2,078	3,168
Income tax expense (benefit)	-952	1,170
Income (Loss) From Discontinued Operations	-1,126	1,998
Loss on disposal of discontinued operations	-1,667	0
Income tax benefit	-617	0
Loss on Disposal of Discontinued Operations	-1,050	0
Total Income (Loss) From Discontinued Operations	-2,176	1,998
Diluted Earnings Per Average Common Share	'	'
Income (Loss) from Discontinued Operations (in dollars per share)	($0.02)	$0.03
Loss on Disposal of Discontinued Operations (in dollars per share)	($0.01)	$0
Total Income (Loss) From Discontinued Operations (in dollars per share)	($0.03)	$0.03
Basic Earnings Per Average Common Share	'	'
Income (Loss) from Discontinued Operations (in dollars per share)	($0.02)	$0.03
Loss on Disposal of Discontinued Operations (in dollars per share)	($0.01)	$0
Total Income (Loss) From Discontinued Operations (in dollars per share)	($0.03)	$0.03
Black Warrior Basin	'	'
Assets of Disposal Group, Including Discontinued Operation [Abstract]	'	'
Accounts receivable	0	'
Inventories	0	'
Other property, net	0	'
Total assets held-for-sale	0	'
Liabilities of Disposal Group, Including Discontinued Operation [Abstract]	'	'
Accounts payable	-2,172	'
Royalty payable	0	'
Other current liabilities	0	'
Total liabilities held-for-sale	-2,172	'
Total net held-for-sale properties	-2,172	'
North Louisiana/East Texas	'	'
Assets of Disposal Group, Including Discontinued Operation [Abstract]	'	'
Accounts receivable	1,670	'
Inventories	68	'
Other property, net	133	'
Total assets held-for-sale	1,871	'
Liabilities of Disposal Group, Including Discontinued Operation [Abstract]	'	'
Accounts payable	-10	'
Royalty payable	-1,221	'
Other current liabilities	-7	'
Total liabilities held-for-sale	-1,238	'
Total net held-for-sale properties	$633	'

Subsequent_Event_Details

Subsequent Event (Details) (Alabama Gas Corporation, Subsequent Event, USD $)	1 Months Ended
	Apr. 30, 2014
Alabama Gas Corporation | Subsequent Event	'
Subsequent Event [Line Items]	'
Expected amount of consideration to be received	$1,600,000,000
Expected proceeds from sale of Alagasco	1,280,000,000
Expected amount of debt to be assigned	$320,000,000